Cimarex Energy Co 10-K 2010
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Commission file number 001-31446
CIMAREX ENERGY CO.
1700 Lincoln Street, Suite 1800, Denver, Colorado 80203
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 ý 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 ý
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 ý NO o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ý 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 the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO ý
Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2009 was approximately $2,319,938,473.
Number of shares of Cimarex Energy Co. common stock outstanding as of February 19, 2010 was 83,839,327.
Documents Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2010 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
Bbl/dBarrels (of oil) per day
One barrel of oil is the energy equivalent of six Mcf of natural gas
Throughout this Form 10-K, we make statements that may be deemed "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, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking statements include statements with respect to, among other things:
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures and other risks described herein.
Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except as required by law.
Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. Proved oil and gas reserves as of year-end 2009 totaled 1.5 Tcfe, consisting of 1.2 Tcf of gas and 58.0 million barrels of oil and natural gas liquids. Of total proved reserves, 77 percent are gas and 77 percent are classified as proved developed. Our 2009 production averaged 462.9 MMcfe per day, comprised of 323.2 MMcf of gas per day and 23,283 barrels of oil per day. We operate the wells that account for 79 percent of our total proved reserves and approximately 82 percent of production.
Our corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is (303) 295-3995. Cimarex is a Delaware corporation.
Our Web site address is www.cimarex.com. There you will find our news releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other Securities and Exchange Commission ("SEC") filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries.
Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC.
On June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of liabilities. That transaction effectively tripled our proved reserves and doubled our production. Since 2005, we have principally focused on exploration and development drilling and have funded these investments with cash flow provided by operating activities.
Beginning in the fourth quarter of 2008, severe financial market disruptions and global economic contraction contributed to large decreases in the prices we received for our oil and gas production. Our oil price realizations for 2009 averaged $56 per barrel, 42% less than our 2008 average of $96 per barrel. Our average gas price dropped 51% to $4.12 per Mcf during 2009 from $8.43 per Mcf in 2008. The large decrease in price resulted in a significant decrease in the amount of cash flow available to invest in exploration and development. In response, we sharply reduced our drilling activity. In 2009 we drilled 76% fewer wells as compared to 2008. Our total capital investment in exploration and development during 2009 was just $524 million versus $1.4 billion in 2008.
In early 2010, oil and gas prices have improved and the cost to drill and complete our wells has decreased. We have begun to increase our drilling activity and our exploration and development capital investment for 2010 is presently expected to range from $700-$900 million.
During 2009 we accomplished the following positive highlights:
However, largely as a result of low oil and gas prices we also:
Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our shareholders. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development. During 2009, our cash flow from operating activities totaled approximately $675 million. Our 2009 investment in exploration and development was $524 million.
A cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices.
Our integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined capital investment process mitigates risk and positions us to continue to achieve consistent increases in proved reserves and production.
While our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we acquired 38,000 net acres in our western Oklahoma Cana-Woodford shale play. The cost of that acquisition was $180.9 million.
Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low prices. At year-end 2009 we had $393 million of long-term debt and our debt to total capitalization ratio was 16 percent.
Cimarex has one reportable segment (exploration and production).
Exploration and Development Overview
Our exploration and development activities are conducted within three main areas: the Mid-Continent region, the Permian Basin and the Gulf Coast. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. The Permian Basin encompasses west Texas and southeast New Mexico. Our Gulf Coast operations are currently focused in southeast Texas. We also have a gas field development project underway in Wyoming.
A summary of our 2009 exploration and development (E&D) activity by region is as follows.
Company-wide, we participated in drilling 110 gross wells during 2009, with an overall completion rate of 93 percent. On a net basis, 60 of 67 total wells drilled during 2009 were completed as producers.
Our 2009 E&D investment totaled $524 million and resulted in 312 Bcfe of proved reserve additions. Of total expenditures, 48 percent were invested in projects located in the Mid-Continent area; 30 percent in the Permian Basin; and 20 percent in the Gulf Coast.
Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 51 gross (22 net) Mid-Continent wells during 2009, completing 98 percent as producers. The bulk of this drilling activity is directed at gas-bearing geological formations in the Anadarko Basin of western Oklahoma. Full-year 2009 investment in this area was $251 million, or 48 percent of total E&D capital.
We drilled 44 gross (17 net) Anadarko Basin wells, of which 98 percent were completed as producers. Our largest investment in this area is in the western Oklahoma, Cana-Woodford shale play. We have approximately 94,000 net acres in the play.
The Cana-Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. During 2009, we drilled and completed 35 gross (13.6 net) horizontal Cana-Woodford wells. At year-end there were 11 gross (6.3 net) wells waiting on completion.
Since the Cana play began in late 2007, Cimarex has participated in a total of 75 gross (32.8 net) wells. Of which, 58 gross (23.7 net) wells have been brought on production and the remainder were either in the process of being drilled or awaiting completion at year-end 2009. For the 58 producing wells, average estimated gross ultimate recovery exceeds 6.5 Bcfe per well. Our acreage positions have multiple years of drilling opportunity.
In the Texas Panhandle, we drilled 2 gross (2 net) successful Granite Wash wells. Our land position in the Texas Panhandle is primarily in Roberts and Hemphill counties.
Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 49 gross (36 net) wells in this area during 2009 completing 44 gross (32 net) as producers. Full-year 2009 investment in this area totaled $155 million, or 30 percent of total E&D capital. Our 2009 drilling focused on horizontal oil plays.
Southeast New Mexico drilling, mainly targeting the Bone Spring, Cherry Canyon, Abo, Paddock and Wolfcamp formations, totaled 38 gross (30 net) wells with 87% being completed as producers.
Our current Gulf Coast exploration drilling is primarily in southeast Texas. This effort is generally characterized by reliance on three-dimensional (3-D) seismic information for prospect generation. We also experience larger potential reserves per well, greater drilling depths and lower success rates. Full-year 2009 investment in the Gulf Coast area was $106 million, or 20 percent of total E&D capital. During 2009 we drilled 9 gross (8.1 net) Gulf Coast wells, realizing an 89 percent success rate. The majority of the activity occurred near Beaumont in Jefferson County, Texas, where seven gross (6.9 net) Yegua/Cook Mountain wells were drilled.
We also own interests offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our 2009 activity in this area consisted primarily of workovers and recompletions.
We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. During 2009 we invested a total of $20.1 million in this project and our cumulative investment in this project is $70.9 million. We presently expect that we will initiate gas sales from this project in 2011. Our total investment, including planned expansion, will approximate $200 million.
Production and Pricing Information
The following table sets forth certain information regarding the company's production volumes and the average oil and gas prices received:
Total 2009 oil and gas production fell five percent averaging 462.9 MMcfe per day as compared to 485.8 MMcfe per day in 2008. Gas production in 2009 decreased seven percent to 323.2 MMcf per day and oil production grew one percent to 23,283 barrels per day.
Production changes reflect the early-2009 reduction in company-operated drilling rigs and number of wells drilled. During the fourth quarter of 2008, we were running an average of 31 operated rigs. By the end of March 2009, we were operating only 3 rigs. In the second half of 2009 we began to pick up our drilling activity and had 12 rigs running during the fourth quarter. In total, we drilled and completed 110 gross (67 net) wells during 2009 compared to 450 gross (276.9 net) in 2008. Partially offsetting the impact of the sharp reduction in drilling were four new highly productive wells in southeast Texas that contributed 70 MMcfe/d to our average fourth quarter volumes.
Reflecting weaker overall U.S. gas markets, we sold our 2009 gas at an average price of $4.12 per Mcf, which was 51 percent lower than the $8.43 per Mcf we received in 2008. Declining global oil prices negatively impacted the oil prices we received. Our annual average realized oil price during 2009 dropped 42 percent to $56.13 per barrel from $96.03 per barrel in 2008.
The following table summarizes Cimarex's daily production by region for 2009 and 2008.
Our largest producing area is the Mid-Continent region. During 2009 our Mid-Continent production averaged 218.5 MMcfe per day, or 47 percent of our total 2009 production. Limited drilling activity outside of the western Oklahoma Cana-Woodford resulted in Mid-Continent production decreasing two percent in 2009.
The Permian Basin contributed 161.4 MMcfe per day in 2009, which was 35 percent of our total production. Oil production increased seven percent as a result of successful drilling in Bone Spring, Cherry Canyon, Abo, Paddock and Wolfcamp formations in southeast New Mexico and West Texas.
Gulf Coast production averaged 80.2 MMcfe per day during 2009, or 17 percent of total production. Full-year 2009 Gulf Coast volumes decreased 12 percent as compared to 2008 as a result of natural production declines and the timing of exploration success. Successful exploration drilling in the second-half of 2009 near Beaumont Texas, resulted in production volumes increasing to 116.2 MMcfe/d, a 54 percent increase over fourth-quarter 2008 average of 75.7 MMcfe/d.
Acquisitions and Divestitures
During 2009, we sold various oil and gas properties for a total of $109.4 million. Associated proved reserves were 25 Bcfe. The largest transaction was $79 million for an interest in a West Texas secondary oil field. There were no significant acquisitions during 2009. Subsequent to year end we acquired additional interests in our Western Oklahoma Cana-Woodford shale play for approximately $23 million.
During 2008 we sold interests in various oil and gas properties primarily located in South Texas for $38.1 million. Also during 2008, we purchased 38,000 undeveloped acres in western Oklahoma for $180.9 million.
In 2005, Cimarex acquired Magnum Hunter Resources, Inc, an independent oil and gas exploration and production company with operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves (60 percent gas and 73 percent proved developed).
Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market.
We sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for approximately 14 percent of 2009 revenues. Because over 95 percent of our gas production is from wells in Kansas, Oklahoma, New Mexico, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.
We employed 756 people on December 31, 2009. None of our employees are subject to collective bargaining agreements.
The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have larger financial, human and technological resources than we do.
We compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these competitive factors cannot be predicted.
Title to Oil and Gas Properties
We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor encumbrances, easements and restrictions.
Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems.
The states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production from wells, generally prohibit the venting
or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill.
Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.
We are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.
We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances.
Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines.
Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.
In addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship our gas to markets.
Additional proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position.
Federal and State Income and Other Local Taxation
Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there will be any undisclosed impact on our capital expenditures, earnings or competitive position.
The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations. If any of the following risks and uncertainties actually occurs, our business, financial condition or results of operations could be materially adversely affected, and these events could negatively impact the value of our common stock.
Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.
Oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations, proximity and capacity of oil and gas pipelines and other transportation facilities and the price and technological advancement of alternative fuels.
The downward pressure in natural gas prices that began in the last half of 2008 continued in 2009. Our average realized natural gas price for 2009 decreased 51% from 2008. Additionally, although oil prices have improved since the end of 2008, our average realized price for oil for 2009 was down 42% from 2008. The decrease in prices significantly decreased the amount available to invest in exploration and development drilling and the present value of our proved reserves. As a result of the drop in commodity prices in the first quarter of 2009, we recorded a $502 million after-tax, full-cost ceiling test write-down of proved properties book-value.
Our proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices also reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions would also be impacted.
If oil and natural gas prices decrease further, we may be required to take additional write-downs of the carrying values of our oil and gas properties and/or our goodwill.
Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the end of each reporting period. If prices decrease significantly, we may incur
additional impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.
The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on our lenders, purchasers of our oil and gas production and working interest owners in properties we operate, causing them to fail to meet their obligations to us.
Failure to economically replace commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth.
In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. This can require significant capital expenditures and can impose reinvestment risk for our company, as we may not be able to continue to replace our reserves economically. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations.
Exploration and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit.
Our drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in the availability of, drilling rigs and related equipment.
Our proved reserve estimates may be inaccurate and future net cash flows are uncertain.
Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause actual results to vary considerably from estimates:
The estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2009, 23 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 61 percent are related to a project in Wyoming and 33 percent are from the western Oklahoma, Cana-Woodford shale play.
Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2009.
The cash flow amounts referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow from proved reserves is based on the average of the previous twelve months' prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.
Hedging transactions may limit our potential gains and involve other risks.
To manage our exposure to price risk, we from time to time enter into hedging arrangements, using commodity derivatives with respect to a significant portion of our future production. The goal of these hedges is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if oil and gas prices rise above the price established by the hedges.
In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
Because all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative gains or losses on our income statement as changes occur in the relevant price indexes.
We have been an early entrant into new or emerging resource development projects; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful.
New or emerging oil and gas resource development projects have limited or no production history. Consequently, we may be unable to use past drilling results in those areas to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage may decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays.
Unless production is established during the term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop the related properties.
Our business depends on oil and natural gas transportation facilities, most of which are owned by others.
The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural 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.
Competition in our industry is intense and many of our competitors have greater financial and technological resources.
We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.
We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations.
In addition, studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's climate. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil and natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases. In December 2009, the Environmental Protection Agency (EPA) issued findings that methane and carbon dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from legislation by Federal or state legislators, or regulations imposed by the EPA, may have an effect on demand for our products, and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our operations.
We make extensive use of hydraulic fracturing, a process that creates a fracture extending from the well bore in a rock formation, to enable gas or oil to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water, chemicals and sand into the rock formation. Legislative and regulatory efforts at the Federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on our operations.
Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control.
Other companies operate approximately 18 percent of our net production. Our success in properties operated by others depends upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.
Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.
Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.
We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.
We may not be able to generate enough cash flow to meet our debt obligations.
At December 31, 2009, we had total long-term debt of $392.8 million, consisting of $25.0 million of bank debt, $350 million of unsecured 7.125% Senior Notes and $17.8 million of Convertible Notes ($19.45 million face value). Subject to the limits contained in the agreements governing our senior revolving credit facility, we have a borrowing base of $1 billion as of December 31, 2009, with current bank commitments of $800 million. We have demands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures.
Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates.
Our business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:
We may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.
The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.
The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially limit our management's discretion in certain respects. In particular, these agreements will limit our and our subsidiaries' ability to, among other things:
In addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.5 to 1 and a current ratio (defined to include undrawn borrowings) of greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.25 to 1. The additional indebtedness limitation does not prohibit us from borrowing under our $1.0 billion revolving credit facility. See Note 7, Long-term Debt, in Notes to Consolidated Financial Statements for further information.
If we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.
Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.
We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must anticipate problems and difficulties related to the acquisition. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such review will not reveal all existing or potential problems. Our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Therefore, the purchase price we pay may exceed the value we realize. When we make entity acquisitions, we may have transferee liability that is not fully indemnified. Acquisitions may have an adverse effect on our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.
Competition for experienced, technical personnel may negatively impact our operations.
Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.
Our certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment.
The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to our stockholders.
Oil and Gas Properties and Reserves
Effective December 31, 2009, the SEC and the Financial Accounting Standards Board ("FASB") adopted amendments to required oil and gas reporting disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve calculations to be based on the unweighted average first-day-of-the-month prices for the prior twelve months. In prior years proved reserves were based on
prices in effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make disclosures of unproved reserves in our SEC filings. The effect of our adoption of the new rules was minimal, apart from the change to using the 12-month average pricing.
Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the SEC. Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of the company. The technical employee primarily responsible for overseeing the oil and gas reserve estimation process is the company's Vice PresidentCorporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than fifteen years of practical experience in oil and gas reserve evaluation. This individual has been directly involved in the annual SEC reserve reporting process of Cimarex since 2002 and serving in the current role for the past five years.
DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent of the total future net revenue discounted at ten percent attributable to the total interests owned by Cimarex as of December 31, 2009. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-five years of experience in oil and gas reservoir studies and evaluations.
All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 79 percent of our proved reserves. All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 17, Unaudited Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for further information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves:
At December 31, 2009, the impact of adopting the new rules requiring the use of a twelve month average price, rather than prices in effect at year end, was significant to our reserve volumes and more so to our reserve values. At year end the reference prices for gas and oil were $5.79 per MMBtu and $79.36 per barrel, respectively, whereas the twelve month average reference prices were $3.87 per MMBtu and $61.18 per barrel. Adjusted for regional differentials, the average prices used were $3.56 per Mcf and $57.58 per barrel. Had prices in effect at year end been used, we believe our December 31, 2009 total equivalent proved reserve volumes would be approximately five to six percent greater than those calculated
using the average price. We estimate that the Standardized Measure at year end would be approximately 60 percent greater if prices in effect at year end had been used.
As of December 31, 2009, 79 percent of proved reserves were located in the Mid-Continent and Permian Basin regions. In total we owned an interest in 12,320 gross (4,748 net) productive oil and gas wells.
The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2009.
Our ten largest producing fields hold 35 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). The table below summarizes certain key statistics about these properties.
The following table sets forth as of December 31, 2009, the gross and net acres of both developed and undeveloped leases held by Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest.
Gross Wells Drilled
We participated in drilling the following number of gross wells during calendar years 2009, 2008, and 2007:
We were in the process of drilling 16 gross (9.7 net) wells at December 31, 2009 and there were 11 gross (6.3 net) Cana-Woodford wells waiting on completion.
Net Wells Drilled
The number of net wells we drilled during calendar years 2009, 2008, and 2007 are shown below:
We have working interests in the following productive wells as of December 31, 2009:
In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million, plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments.
In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be significant, the resolution of them we believe,
individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.
No matters were submitted for a vote of security holders during the fourth quarter of 2009.
The executive officers of Cimarex as of February 26, 2010 were:
There are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an executive officer.
F.H. MERELLI was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was president and chief operating officer of Apache Corporation.
JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering (June 1994 to October 1999).
THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.
STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February 1994 to September 1999, he served as vice president, land.
PAUL KORUS was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice president and chief financial officer of Key Production Company, Inc. from
September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research analyst with Petrie Parkman & Co., an investment banking firm.
GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc.
RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, Mr. Dinkins was with Sprint.
JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of Westport Resources Corporation.
THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and served as a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend of $.06 per share was paid to shareholders in each quarter of 2009. Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors.
Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per share of Common Stock on the NYSE and the quarterly dividends paid per share.
The closing price of Cimarex stock as reported on the New York Stock Exchange on February 19, 2010, was $59.98. At December 31, 2009, Cimarex's 83,541,995 shares of outstanding common stock were held by approximately 4,092 stockholders of record.
The graph below compares the cumulative 5-year total return of holders of Cimarex Energy Co.'s common stock with the cumulative total returns of the S&P 500 index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from 12/31/2004 to 12/31/2009.
The stock price performance included in this graph is not necessarily indicative of future stock price performance.
In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2009, or since the quarter ended September 30, 2007.
The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in Item 8 of this Report.
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this report and also with "Certain Risks" in Item 1 of this report. Certain amounts in prior years' financial statements have been reclassified to conform to the 2009 financial statement presentation. This discussion also includes Forward-Looking statements. Please refer to "Cautionary Information about Forward-Looking Statements" in Part I of this Report for important information about these types of statements.
We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed.
Our operating strategy is to achieve profitable growth in proved reserves and production primarily through exploration and development. To supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. Our growth is generally funded with cash flow provided by our operating activities. To achieve a consistent rate of growth and mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our operations are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming.
The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved reserves. We use the full cost method of accounting for oil and gas activities.
Our revenue, profitability and future growth are highly dependent on the oil and gas prices we receive. Our ability to find, develop and/or acquire proved oil and gas reserves will also impact our financial results. Continued volatility in commodity prices, and turmoil in the global financial system may have adverse effects on our business and financial position. Our ability to access the capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, the global economic situation could have an impact on our lenders, business partners and customers, potentially causing them to fail to meet their obligations to us.
Oil and gas prices reached historically high levels during the first nine months of 2008. However, during the fourth quarter of 2008 severe disruptions in the credit markets and reductions in global economic activity caused significant decreases in oil and gas prices. The downward pressure on natural gas prices continued in 2009. Our average realized natural gas price for 2009 decreased 51% compared to the 2008 realized price. Oil prices improved as 2009 unfolded but they are still significantly lower than prices received in 2008. Our average realized oil price during 2009 was 42% lower than the realized price for 2008. This dramatic decrease in both oil and gas prices had a significant negative impact on our 2009 revenue and net income. We also had less cash flow available for capital expenditures. Our stock price and market capitalization have also been adversely affected by these economic events.
Lower oil and gas prices negatively impacted our 2009 revenues, earnings and cash flow. We reported a net loss of $311.9 million, or $3.82 per share. The 2009 loss was primarily the result of a first quarter full-cost ceiling test write down of our oil and gas properties of $501.8 million (after tax). Substantially all
of this noncash charge was the result of the continuing drop in commodity prices that began during the fourth quarter of 2008. Despite the impact of lower prices, we made several meaningful accomplishments during 2009. Most notably, we increased our proved reserves by 15% and have positioned the company to achieve 17-23% production volume growth in 2010.
2009 summary financial and operating results:
In response to the lower oil and gas prices we significantly reduced our 2009 capital expenditures from our record high in 2008. Total oil and gas capital expenditures for 2009 were $528 million, down from 2008 expenditures of $1.6 billion.
In October 2009 our bank group, as part of the regularly scheduled fall review, reaffirmed our $1.0 billion borrowing base related to our credit facility maturing in April 2012. Bank group commitments of $800 million also remain unchanged. As of December 31, 2009, we had bank borrowings outstanding of $25 million, which is $195 million less than the December 31, 2008 balance of $220 million. The reduction in borrowings was primarily funded from non-core property sales and tax refunds.
We sold various interests in oil and gas properties in 2009, the largest of which was a West Texas secondary oil recovery field. Total 2009 sales proceeds were $109.4 million, with associated proved reserves of 25 Bcfe. There were no significant acquisitions during 2009. Subsequent to year end we acquired additional interests in our Western Oklahoma Cana-Woodford shale play for approximately $23 million.
Oil and Gas Prices
While our revenues are a function of both production and prices, wide swings in commodity prices had the greatest impact on our results of operations. Our annual average realized gas price decreased from $8.43 per Mcf in 2008 to $4.12 per Mcf in 2009; and oil prices decreased from $96.03 per barrel in 2008 to $56.13 per barrel in 2009.
During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. Year-end 2008 oil and gas prices fell 50-70% from their mid-2008 peak. Though prices improved as 2009 unfolded, they remained substantially below prior year levels.
On an energy equivalent basis, 70% of our 2009 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately an $11.8 million change in our gas revenues. Similarly, 30% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in approximately an $8.5 million change in our oil revenues.
In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. From time to time we attempt to mitigate a portion of our price risk through the use of hedging transactions.
In March 2009 we entered into derivative gas contracts covering the period April 2009 through December 2009. The collars set a floor of $3.00 and a ceiling of $5.00 and covered approximately 148,000 MMBtu per day of our Mid-Continent gas production during the contract period. These contracts expired at December 31, 2009. We recognized a net gain of $1.4 million from the 2009 contracts.
For 2007 and 2008 we executed cash flow effective hedges covering approximately 24% of our overall 2007 gas production and 11% of our 2008 gas volumes. We hedged 29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. As of December 31, 2008 all of our cash flow effective hedge contracts had expired.
During the second and third quarters of 2009 we entered into derivative contracts for a portion of our 2010 production. These contracts cover approximately 40% of our anticipated 2010 oil and gas production volumes. At December 31, 2009, we had the following outstanding contracts:
We did not choose to apply hedge accounting treatment to any of the 2009 and 2010 contracts. Settlements on these contracts will not impact our realized commodity prices during the periods they cover. Instead, any settlements on these contracts are shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. See Note 4 to the Consolidated Financial Statements for additional information regarding our derivative instruments.
Reserve replacement and growth
Due to lower oil and gas prices we sharply reduced our capital investments during 2009. In 2009, investments in oil and gas exploration, development and acquisition activities totaled $528 million versus $1.6 billion in 2008. Our exploration and development capital investment is expected to increase to $700-$900 million in 2010, depending on prices and corresponding cash flow.
Because oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of resource depletion and natural production decline. Our operations also entail significant complexities that require the use of advanced technologies and highly trained personnel. Even when modern exploration technology is properly used, our geo-scientists still may not know conclusively if hydrocarbons will be present, the rate at which they will be produced, or economic viability. Future growth will continue to depend upon our ability to economically add reserves in excess of production.
Despite lower capital investment in 2009, our year-end total proved oil and gas reserves increased by 15% to 1.53 Tcfe from 1.34 Tcfe at year-end 2008. This increase is net of production of 169.0 Bcfe and property sales of 24.9 Bcfe. Reserves added from exploration and development and improved recovery totaled 312.3 Bcfe and 3.9 Bcfe were acquired via property purchases. Revisions of previous estimates added 73.9 Bcfe, comprised of 104.7 Bcfe from positive performance and lower operating costs, partially offset by 30.8 Bcfe from lower prices.
Proved natural gas reserves at year-end 2009 were 1.19 Tcf compared to 1.07 Tcf at year-end 2008. Natural gas comprised 77% and 80% of our total proved reserves at year-end 2009 and 2008, respectively. Our proved oil reserves at year-end 2009 were 58.0 MMBbls compared to 45.2 MMBbls at the end of 2008.
Overall, about 47% of our proved reserves are in our Mid-Continent region and 32% are in the Permian Basin. Our onshore Gulf Coast and other onshore operations collectively make another 20% of total proved reserves. Only 1% of our total proved reserves are in the Gulf of Mexico.
The process of estimating quantities of oil and gas reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for more reserve information.
In most years our primary source for reserve replacement and growth is exploration and development (E&D). We invested $524.4 million on E&D during 2009 and $1,438.4 million in 2008. Approximately 48% of 2009 expenditures were in the Mid-Continent area, 30% in the Permian Basin, 20% in the Gulf Coast area, and 2% in Wyoming/Other. Cash flow from operating activities for 2009 totaled $675 million, which more than funded our drilling program.
Production and other operating expenses
The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some trend with production volume and some are a function of the number of wells we own. At the end of 2009, we owned interests in 12,320 wells.
Production expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to produce oil and gas from existing wells.
Transportation expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and expenses, respectively.
Depreciation, depletion and amortization (DD&A) of our producing properties is computed using the units-of- production method. Because the economic life of each producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense.
General and administrative expenses (G&A) consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.
Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes.
Significant expenses that generally do not trend with production
Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees and the expensing of stock options. Net stock compensation expense in 2009 was $9.3 million compared to $10.1 million in 2008.
The derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment. The gain or loss fluctuates based on changes in the fair value of underlying commodities. For the year ended December 31, 2009, we recognized a net realized gain of $1.4 million for the contracts that settled and expired in 2009. For those contracts that cover the period January 1, 2010 to December 31 2010, we have recorded a non-cash fair value loss of $14.5 million at December 31, 2009.
RESULTS OF OPERATIONS
2009 compared to 2008
We recognized a net loss for 2009 of $311.9 million or $3.82 per share. This compares to a net loss of $915.2 million, or $11.22 per share for 2008. The lower loss in 2009 compared to 2008 is primarily the result of a lower non-cash full cost ceiling impairment write-down recorded in 2009 compared to the write-down
in 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below.
Oil and gas sales during 2009 totaled $962.4 million, compared to $1.88 billion in 2008. Of the $918.4 million decrease in sales between the two periods, $847.5 million related to lower prices and $70.9 million resulted from lower production volumes.
Compared to 2008, our 2009 oil production increased by one percent to an average of 23,283 barrels per day. This increase resulted in $9.9 million of incremental revenues. Gas volumes averaged 323.2 MMcf per day in 2009 compared to 348.2 MMcf per day in 2008, resulting in a decrease in revenues of $80.8 million. Total 2009 oil and gas production volumes were 462.9 MMcfe per day, down 22.9 MMcfe per day from 2008. During the fourth quarter of 2009, our gas production averaged 330.0 MMcf per day down from 350.3 MMcf per day (a six percent decrease) from the fourth quarter of 2008. Fourth quarter oil production decreased by four percent to 22,935 barrels per day from 23,907 barrels per day in 2008. The expected decrease in production volumes between the periods is primarily the result of reduced drilling. Our fourth quarter 2008 operated rig count averaged 31 dropping to a low of three rigs in the first quarter of 2009 and averaged 12 by the fourth quarter of 2009.
Average realized gas prices decreased by 51% to $4.12 per Mcf in 2009, compared to $8.43 per Mcf for 2008. This price decrease lowered gas sales by $508.4 million between the two periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of Mid-Continent gas production.
Realized oil prices averaged $56.13 per barrel during 2009, compared to $96.03 per barrel in 2008. The decrease in oil sales resulting from this 42% decline in oil prices totaled $339.1 million.
The decreases in realized gas and oil prices were the result of overall market conditions.
We sometimes transport, process and market third-party gas that is associated with our gas. In 2009, third-party gas gathering and processing contributed $26.2 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $43.9 million in 2008. Our gas marketing margin (revenues less purchases) decreased to $0.6 million in 2009 from $1.7 million in 2008. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions.
Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) decreased to $1.445 billion in 2009 compared to $3.367 billion in 2008.
The largest component of the change between periods is the non-cash impairment of oil and gas properties recorded in 2009 and 2008. As a result of declines in commodity prices, an impairment of $791.1 million ($501.8 million net of tax) was reported in the first quarter of 2009. In 2008 a total of $2.2 billion ($1.4 billion, net of tax) of impairments were recorded. Volatility of oil and gas prices could require us to record a ceiling test impairment write-down in future periods. The full cost method of accounting is discussed in detail under "Critical Accounting Policies and Estimates".
DD&A decreased $281.7 million between periods from $547.4 million in 2008 to $265.7 million in 2009. On a unit of production basis, DD&A was $1.57 per Mcfe in 2009 compared to $3.08 per Mcfe for 2008. The significant decrease is due to $3.0 billion of impairments to the carrying value of our oil and gas properties recorded during the last half of 2008 and the first quarter of 2009.
Asset retirement obligation expense rose to $12.3 million in 2009 from $8.8 million in 2008. The increase is due to plugging and abandonment costs being greater than our original asset retirement obligation estimates. This was primarily the result of hurricane damage to our offshore properties. This caused additional expenses to be incurred during site restoration.
Production costs decreased $40.5 million, or 19 percent, from $218.7 million ($1.23 per Mcfe) in 2008 to $178.2 million ($1.05 per Mcfe) in 2009. Our production costs consist of workover expense and lease operating expenses. We have seen a decrease in costs in both of these areas. A reduction in large scale workover projects caused a $13.9 million decrease. A decrease in lease operating expense of $26.6 million is attributable to the sale of producing properties in the last half of 2008 and early 2009 coupled with a significant decline in service costs in comparison to their peak in mid-2008.
Transportation costs decreased from $38.1 million in 2008 to $33.8 million in 2009. The decrease is the result of lower sales volumes and lower fuel costs from 2008 to 2009.
Taxes other than income were $54.9 million lower, dropping from $130.5 million in 2008 to $75.6 million in 2009. The decrease between periods resulted from decreases in oil and gas sales stemming from significantly lower commodity prices and lower gas production volumes.
General and administrative (G&A) expenses decreased $2.8 million from $44.5 million in 2008 to $41.7 million in 2009. The decrease between periods is due to higher employee-benefit costs including bonus and severance costs, offset by lower legal costs and lower costs associated with having fewer employees.
A component of our operating costs and expenses in 2009 is a loss of $13.1 million on our derivative instruments. We recorded an unrealized loss of $14.5 million related to calendar 2010 contracts which is partially offset by $1.4 million of net realized gains on contract settlements in 2009. See Note 4 to the Consolidated Financial Statements for detailed information regarding our derivative instruments.
Other operating, net expense consists of costs related to various legal matters most of which pertain to litigation and contract settlements and title and royalty issues. In 2009, the decrease in Other operating, net to $24.3 million from $126.4 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. Krug case in 2008. The total accrued litigation expense for the year ended December 31, 2008 for this lawsuit was $119.6 million. We have appealed the District Court's judgments. For further information on this lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates".
Other income and expense
Interest expense increased by $6.7 million, or 20%, primarily because of an increase in our average bank debt outstanding during the year. We had no borrowings on our credit facility during the first eleven months of 2008 and an average outstanding balance of approximately $270 million during 2009. Also, in comparison to 2008, we recognized an additional $4.3 million of deferred financing costs. These higher costs are the result of the new credit facility we entered into in April 2009. Partially offsetting these increases is a $3.7 million decrease in interest expense on our convertible notes due to the December 2008 repurchases of $105.5 million of the outstanding $125 million (face value) notes. We repurchased the notes with borrowings under our credit facility and recognized a $10.1 million loss on early extinguishment of debt in 2008.
Capitalized interest increased by $1.3 million due mostly to more costs associated with our unproved properties and construction project in 2009.
Other, net decreased from $10.3 million of income in 2008 to $16.3 million of expense in 2009. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on the sale or value of oil and gas well equipment, and interest income. The change from 2008 to 2009 is primarily the result of losses of $15.5 million related to oil and gas well equipment due to decreased value of drill pipe resulting from a significant slowing of drilling activity across the industry. In 2008 we had a gain of $21.8 million on the sale of oil and gas well equipment. Also included in our 2009 expense is a $2.4 million loss on the sale of an equity investment.
During 2009, a net deferred income tax benefit of $176.5 million was recognized (the year end deferred tax benefit included $11.8 million of current income tax benefit). This compares with a 2008 net deferred income tax benefit of $536.4 million. The combined Federal and state effective income tax rates were 36.1% and 37.0% in the years of 2009 and 2008, respectively. The effective tax rate of 36.1% for 2009 differs from the statutory rate primarily due to the effects of state income taxes and the Domestic Production Activities allowance.
RESULTS OF OPERATIONS
2008 compared to 2007
We recognized a net loss for 2008 of $915.2 million or $11.22 per share. This compares to net income of $345.3 million, or $4.05 per diluted share for the same period in 2007. The decrease in net income is primarily the result of a non-cash full cost ceiling write-down recorded in the third and fourth quarters of 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below.
Oil and gas sales during 2008 totaled $1.9 billion, compared to $1.4 billion in 2007. Of the $516.3 million increase in sales between the two periods, $396.8 million related to higher prices and $119.4 million resulted from higher production volumes.
Compared to 2007, our 2008 oil production increased by 13% to an average of 22,937 barrels per day in 2008. This increase resulted in $66.2 million of incremental revenues. Gas volumes averaged 348.2 MMcf per day in 2008 compared to 328.6 MMcf per day in 2007, resulting in an increase in revenues of $53.2 million. Total 2008 oil and gas production volumes were 485.8 MMcfe per day, up 34.8 MMcfe per day from 2007. Both our gas and oil volumes increased as 2008 unfolded. During the fourth quarter of 2008, our gas production averaged 350.3 MMcf per day up from 341.1 MMcf per day (a three percent increase) in the fourth quarter of 2007. Fourth quarter oil production increased by 10% to 23,907 barrels per day, up from 21,680 barrels per day in 2007.
Average realized gas prices increased by 20% to $8.43 per Mcf in 2008, compared to $7.05 per Mcf for 2007. This price increase boosted gas sales by $175.9 million between the two periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of Mid-Continent gas production.
Realized oil prices averaged $96.03 per barrel during 2008, compared to $69.71 per barrel in 2007. The increase in oil sales resulting from this 38% improvement in oil prices totaled $221.0 million.
Changes in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program.
We sometimes transport, process and market third-party gas that is associated with our gas. In 2008, third-party gas gathering and processing contributed $43.9 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $31 million in 2007. Our gas marketing margin (revenues less purchases) decreased to $1.7 million in 2008 from $5.1 million in 2007. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions.
Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $3,367.5 million in 2008 compared to $858.9 million in 2007.
The largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $2.2 billion ($1.4 billion, net of tax) that was recorded as a result of declines in natural gas and oil prices during the last half of 2008. At September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Electing to use period end prices, at December 31, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax). Due to the volatility of oil and gas prices and because the ceiling calculation requires that prices in effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test write-down in future periods. The full cost method of accounting is discussed in detail under "Critical Accounting Policies and Estimates".
DD&A increased $85.6 million between periods from $461.8 million in 2007 to $547.4 million in 2008. On a unit of production basis, DD&A was $3.08 per Mcfe in 2008 compared to $2.81 per Mcfe for 2007.
The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been increasing and we are drilling deeper and more complex wells. Additionally, the significant decrease in oil and gas prices over the last half of 2008 reduced the amount of our estimated reserve quantities (future production), causing an increase in our depletion rate. Due to the reduction to the carrying value of oil and gas properties recorded at year end we expect the DD&A rate to be lower in the first quarter of 2009 in comparison to the full year 2008.
Production costs rose $17.2 million, or nine percent, from $201.5 million ($1.22 per Mcfe) in 2007 to $218.7 million ($1.23 per Mcfe) in 2008. This increase resulted from an eight percent increase in production volumes and a $7.4 million increase in workover expense between periods.
Transportation costs increased from $26.4 million in 2007 to $38.1 million in 2008. The increase is the result of higher sales volumes, increased market rates and a higher fuel cost component due to higher natural gas prices during the year.
Taxes other than income were $36.9 million greater, rising from $93.6 million in 2007 to $130.5 million in 2008. The increase between periods resulted from increases in oil and gas sales stemming from higher production volumes and commodity prices.
General and administrative (G&A) expenses decreased $4.8 million from $49.3 million in 2007 to $44.5 million in 2008. The decrease between periods is due to lower employee-benefit costs due to a decrease in bonus and profit sharing expenses resulting from significant decreases in commodity prices during the last quarter of 2008.
In 2008, the increase in Other operating, net to $126.4 million from $6.6 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. Krug case. The total accrued litigation expense for the year ended December 31, 2008 for this lawsuit is $119.6 million. We have appealed the District Court's judgments. For further information on this lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates".
Other income and expense
Interest expense decreased by $6.0 million, or 15%, primarily because of a decrease in our average bank debt outstanding during the year. In addition, in comparison to prior year, we experienced a decrease in our average interest rate on both our bank borrowings and convertible notes. Capitalized interest increased by $2.4 million mainly because we had more costs incurred to develop our unproved properties than we had in 2007. We also had a loss on the repurchase of convertible notes of $10.1 million compared to a $5.1 million gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of 9.6% senior unsecured notes.
Other, net decreased from $14.2 million of income in 2007 to $10.3 million of income in 2008. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on sale or value of oil and gas well equipment and interest income. Included in our 2008 Other, net is $16.0 million of impairment expense on our equity investments and $0.8 million of impairment on our short-term investments. These additional expenses were offset by a $17.2 million increase in gain on sale of oil and gas well equipment in comparison to 2007. Another element of the decrease between periods is lower income of $4.2 million from equity investees.
During 2008, a net deferred income tax benefit of $536.4 million was recognized (the year end deferred tax benefit included $66.2 million of income tax expense). This compares with 2007 current taxes of $30.6 million and deferred income tax expense of $166.8 million. The combined Federal and state effective income tax rates were 37.0% and 36.4% in the years of 2008 and 2007, respectively. The effective
tax rate of 37.0% for 2008 differs from the statutory rate due to effects of the domestic production activities deduction and percentage depletion.
LIQUIDITY AND CAPITAL RESOURCES
The ongoing global economic slowdown has continued to impact commodity prices. Though prices improved as 2009 unfolded, they remained substantially below prior year levels. Volatility in commodity prices may reduce the amount of oil and gas that we can economically produce. Commodity prices also affect the amount of cash flow available for capital expenditures as well as our ability to borrow and raise additional capital. These conditions could impact third parties with whom we do business, causing them to fail to meet their obligations to us.
We have and will continue to focus on maintaining liquidity and low financial leverage. Historically our exploration and development expenditures have generally been funded by cash flow provided by operating activities ("operating cash flow"). In 2010 we intend to continue to fund our exploration and development expenditures with operating cash flow.
We will also continue to consider attractive acquisition opportunities. However, the timing and size of acquisitions is unpredictable. To ready ourselves for potential acquisitions and possible further declines in commodity prices, we entered into a new three-year senior secured revolving credit facility in April 2009. The new facility increased bank commitments from $500 million to $800 million. The borrowing base is $1 billion.
We believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing, and dividend payments for 2010 and beyond.
Sources and Uses of Cash
Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share repurchases.
The following table presents the sources and uses of our cash and cash equivalents from 2007 to 2009. The table presents capital expenditures on a cash basis. These amounts differ from the amounts of capital expenditures (including accruals) that are referred to elsewhere in this document.
Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows)
Cash flow provided by operating activities for 2009 was $675.2 million, compared to $1,367.5 million for 2008 and $994.7 million for 2007. The decrease from 2008 to 2009 resulted primarily from lower gas and oil prices and decreased gas production. The increase from 2007 to 2008 resulted primarily from higher gas prices, high oil prices and increased production.
Cash flow used in investing activities for 2009 was $444 million, compared to $1.6 billion for 2008 and $875.4 million for 2007. Changes in the cash flow used in investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The decrease from 2008 to 2009 was mostly caused by decreased oil and gas expenditures. In response to the lower oil and gas prices at the end of 2008, we significantly reduced our planned 2009 capital expenditures from our record high in 2008. The increase from 2007 to 2008 was caused by increased oil and gas expenditures resulting from a more active drilling program. In addition, we had $138.1 million less proceeds from sales of assets in 2008 when compared to 2007.
Net cash flow used in financing activities in 2009 was $229.8 million versus net cash flow provided by financing activities of $107.4 million in 2008. In 2009 we had net payments on our credit facility of $195 million and $18 million of financing costs for the new three-year senior secured revolving credit facility. In 2008 we had borrowings under our credit facility of $220.0 million and $13.1 million in proceeds from issuance of common stock and other. Also in 2008 we used $105.6 million of the borrowings under
our credit facility to repurchase a portion of our convertible notes in December. We made dividend payments of approximately $20.0 million in both 2009 and 2008.
Net cash flow used in financing activities in 2007 was $1.3 million. Two significant uses were for share repurchases of $42.3 million and $13.4 million for dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our old 9.6% notes and reduce outstanding borrowings under our credit facility.
The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, exploration, and development activities (in thousands):
Our exploration and development expenditures decreased 64 percent in 2009 compared to 2008. The decrease in 2009 resulted from a planned decrease in our exploration activity in response to the economic environment and our continued efforts to operate within our cash flow provided by operating activities. Overall, we drilled and completed 110 gross (67 net) wells during 2009 versus 450 gross (277 net) wells in 2008. At year-end 2009 an additional 11 gross (6.3 net) Cana-Woodford wells were waiting on completion.
Our planned capital program for 2010 will range from $700-$900 million. Although our 2010 capital budget is set at a level that we believe corresponds with our anticipated 2010 cash flows, the timing of capital expenditures and the receipt of cash flows do not necessarily match. We anticipate borrowing and repaying funds under our credit arrangements throughout the year. If we start to see a significant change in commodity prices from our current forecasts, we have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations.
We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact
Our 2009 exploration and development drilling program is discussed in more detail in Exploration and Development Activity Overview under Item 1 of this Form 10-K.
Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and producing new reserves, the level of production from existing wells and prices of oil and natural gas. To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility to finance our working capital needs and growth.
During 2009 our total assets, net oil and gas assets, net income and stockholders' equity were reduced by a non-cash impairment of oil and gas properties in the amount of $791.1 million ($501.8 million after tax). Total assets decreased in 2009 from $4.2 billion at the beginning of the year to $3.4 billion by December 31, 2009. Our net oil and gas assets decreased by $623.6 million and our cash position increased by $1.3 million for the same period. As of December 31, 2009, stockholders' equity totaled $2.0 billion, down from $2.4 billion at December 31, 2008. The decrease resulted primarily from a current year 2009 net loss of $311.9 million.
In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to shareholders. A dividend has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 per common share.
Common Stock Repurchase Program
In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases were made in 2009 or since the quarter ended September 30, 2007. In 2009 the Board of Directors extended the repurchase program to December 31, 2011.
Working Capital Analysis
Our working capital balance fluctuates primarily as a result of our exploration and development activities and our realized commodity prices. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments.
At December 31, 2009, we had positive working capital of $18.5 million, down $26.9 million from year-end 2008. Working capital decreased primarily because of the following:
These working capital decreases were mostly offset by:
Debt at December 31, 2009 and 2008 consisted of the following (in thousands):
In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special and regular semi-annual redeterminations.
The credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2009, we were in compliance with all of the financial and non-financial covenants.
At Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional 1.125 to 2.125 percent, based on borrowing base usage.
At December 31, 2009, there was $25 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 2.2%. We also had letters of credit outstanding of $16.7 million leaving an unused borrowing availability of $758.3 million.
In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets.
The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption.
At any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium.
If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.
The floating rate convertible senior notes mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at the three month LIBOR, reset quarterly. On December 31, 2009, the interest rate approximated 0.3%.
In December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the $105.5 million in notes with borrowings under our credit facility. Holders of the remaining $19.5 million of notes have optional repurchase dates as of December 15, 2013, and 2018.
In addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above 110% of the conversion price of $28.59 per share for a defined period of time. As of December 31, 2008, the notes were not convertible. However, based on the price of our common stock, the notes became convertible effective October 1, 2009 and continue to be convertible through the first quarter of 2010.
At our option, we may offer to redeem the notes at any time at par. In addition, if a change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes.
In May 2008, the FASB issued new guidance that changed the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements were required to be applied to both new instruments and retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. The effective interest rate for the years ended December 31, 2009, 2008 and 2007 was 2.0%, 4.4% and 7.1%, respectively. See Note 7 for a comparison of certain financial statement line items affected by the retrospective application of this guidance.
Contractual Obligations and Material Commitments
At December 31, 2009, we had contractual obligations and material commitments as follows:
At December 31, 2009, we had firm sales contracts to deliver approximately 1.9 Bcf of natural gas over the next three months. If this gas is not delivered, our financial commitment would be approximately $11.1 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will be due.
In connection with a gas gathering and processing agreement, we have commitments to deliver 55.7 Bcf of gas over the next four years. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately $41.6 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreement.
We have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $4.7 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements.
All of the noted commitments were routine and were made in the normal course of our business.
Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available under our existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration and development activities.
Our exploration and development expenditures program for 2010 are projected to range from $700 million to $900 million. Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. It is also possible that we may increase our level of planned capital investment if our oil and gas prices exceed our current expectation or if attractive new opportunities arise.
Production estimates for 2010 range from 540 to 570 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2009, our realized prices averaged $4.12 per Mcf of gas and $56.13 per barrel of oil. Prices can be very volatile and the possibility of 2010 realized prices varying from prices in 2009 is high.
Certain expenses for 2010 on a per Mcfe basis are currently estimated as follows:
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee.
Oil and Gas Reserves
The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 61 percent are related to a project in Wyoming and 33 percent are from the Western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly as new information becomes available. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes. As further discussed in Recently Issued Accounting Standards, the SEC and FASB amended oil and gas reporting requirements effective December 31, 2009. The impact to Cimarex was minimal, apart from the change to a new standard using 12 month average pricing rather than prices in effect at the end of a period.
We use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It is also possible that a full cost ceiling limitation charge could occur in the period of the revision.
The following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from better information due to production history, well performance and changes in production costs.
Non-price related revisions added 115.1 Bcfe over the three-year period 2007-2009. Over the same period we have seen a 140.5 Bcfe decrease resulting from lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for additional reserve data.
Full Cost Accounting
We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other disposition of oil and gas
properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our full cost pool.
At the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation have previously been determined based on current oil and gas prices adjusted for designated cash flow hedges. For year-end 2009, new SEC rules were implemented requiring reserve calculations to be based on the unweighted average first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date.
Due to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil prices, we recorded additional non-cash impairments of oil and gas properties of $1.6 billion ($1.0 billion after tax) in the fourth quarter of 2008, and $791.1 million ($501.8 million after tax) in the first quarter of 2009. The Company's quarterly and annual ceiling test has been primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2009 would not have resulted in a ceiling test impairment. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will determine the Company's actual ceiling test calculation and impairment analyses. Decreases in commodity prices can also impact our goodwill impairment analyses.
At December 31, 2009, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including the goodwill), after giving effect to all other period impairments, including the impairment of oil and gas properties from the full cost pool ceiling limitation calculation. If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business combination accounting rules.
We perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of performing the annual goodwill impairment test. As of December 31, 2009, the market price per share of our common stock was greater than the book value by $28 per share. Due to volatility in the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10 percent. The ceiling calculation is not intended to be indicative of fair value.
In estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, 2009 (adjusted for estimated
delivery point price differentials). As of December 31, 2009, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill.
A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us.
In January, 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million, plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments.
In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.
Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2009, we revised our existing estimated asset retirement obligation by $13.4 million, or approximately nine percent of the asset retirement obligation at December 31, 2009, due to changes in the various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 9.5 percent. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to
depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recently Issued Accounting Standards
In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In addition, the amendments concurrently align the SEC's full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.
The following amendments have the greatest likelihood of affecting our reserve disclosures:
The revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells. Because the revised rules generally expand the definition of proved reserves, proved reserve estimates could increase in the future based upon adoption of the revised rules.
In June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which after its launch on July 1, 2009 became the single source of authoritative, nongovernmental U.S. Generally Accepted Accounting Principles (GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 accounting topics and displays all topics using a consistent structure. All existing standards that were used to create the Codification are now superseded, replacing the previous references to specific Statements of Financial Accounting Standards with numbers used in the Codification's structural organization.
In January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, Extractive Industries-Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosure. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new SEC Rule, Modernization of Oil and Gas Reporting Requirements. The ASU is effective for reporting periods ending on or after December 31, 2009.
The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.
Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable.
We periodically hedge a portion of our price risk associated with our future oil and gas production.
The following table details the contracts we have in place as of December 31, 2009:
While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the 2010 contracts listed above, a hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2010 of $8.2 million.
In spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with eight separate counterparties. Second, our derivative contracts are held with "investment grade" counterparties that are a part of our credit facility. See Note 4 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.
Interest Rate Risk
At December 31, 2009, our debt was comprised of the following (in thousands):
As of December 31, 2009, the amounts outstanding under our senior secured revolving credit facility bears interest at either (a) a LIBOR plus 2 to 3 percent, based on borrowing base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional 1.125 to 2.125 percent, based on borrowing base usage. Our senior unsecured notes bear interest at a fixed rate of 7.125% and will mature on May 1, 2017, and our unsecured convertible senior notes bear interest at an annual rate of three-month LIBOR, reset quarterly.
We consider our interest rate exposure to be minimal because approximately 89% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the three-month LIBOR rate would increase our annual interest expense by $445,000. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding debt.
CIMAREX ENERGY CO.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES
All other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or related notes thereto.
Report of Independent Registered Public Accounting Firm
Board of Directors
We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
As discussed in notes 7 and 10 to the consolidated financial statements, Cimarex Energy Co. changed its accounting for its convertible debt instrument that may be settled in cash upon conversion (including partial cash settlement) and began computing earnings per share using the two-class earnings allocation method, effective January 1, 2009, which have been applied retrospectively in the consolidated financial statements referred to above.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2009, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2010 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.