UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D C 20549
Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 2004
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Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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Commission file number 001-31446
CIMAREX ENERGY CO.
(Exact name of registrant as specified in its charter)
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Delaware |
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45-0466694 |
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(State or other jurisdiction of |
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(I.R.S. Employer Identification No.) |
1700 Lincoln Street, Suite 1800, Denver, Colorado 80203
(Address of principal executive offices including ZIP code)
(303) 295-3995
(Registrant’s telephone number)
Securities Registered Pursuant to Section 12(b) of the Act:
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Title of Each Class |
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Name of each exchange on which registered |
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Common Stock ($.01 par value) |
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New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act: None
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 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.
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). YES ý NO o
Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2004 was approximately $1,223,126,000.
Number of shares of Cimarex Energy Co. common stock outstanding as of February 28, 2005 was 41,764,211.
Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its 2005 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K
TABLE OF CONTENTS
DESCRIPTION
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Bbls – Barrels (of oil)
Bcf – Billion cubic feet
Bcfe – Billion cubic feet equivalent
MBbls – Thousand barrels
Mcf – Thousand cubic feet (of natural gas)
Mcfe – Thousand cubic feet equivalent
MMBbls – Million barrels
MMBtu – Million British Thermal Units
MMcf – Million cubic feet
MMcfe – Million cubic feet equivalent
Net Acres – Gross acreage multiplied by working interest percentage
Net Production – Gross production multiplied by net revenue interest
NGL – Natural gas liquids
One barrel of oil is the energy equivalent of six Mcf of natural gas.
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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:
• amount, nature and timing of capital expenditures;
• drilling of wells;
• reserve estimates;
• timing and amount of future production of oil and natural gas;
• operating costs and other expenses;
• cash flow and anticipated liquidity;
• estimates of proved reserves, exploitation potential or exploration prospect size; and
• marketing of oil and natural gas.
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 schedule of any 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 occur, or should underlying assumptions prove 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.
The forward-looking statements in this Form 10-K do not include any risks, uncertainties or forward-looking information associated with our proposed acquisition of Magnum Hunter or the
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operations of the combined company following the proposed acquisition, if completed. For a discussion of additional risks, uncertainties and forward-looking information related to the proposed acquisition, as well as additional associated cautionary statements, see the discussion under the caption “Cautionary Statement Concerning Forward-Looking Statements” in the Form S-4 Registration Statement (File No. 333-123019) filed by Cimarex with the Securities and Exchange Commission on February 25, 2005.
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Cimarex Energy Co. is an independent oil and gas exploration and production company. Our principal areas of operations are located in Oklahoma, Texas, Kansas, and Louisiana.
At December 31, 2004, proved reserves totaled 449.0 Bcfe consisting of 364.6 Bcf of gas and 14.1 million barrels of oil. Of total proved reserves, 81 percent are gas and more than 99 percent are classified as proved developed. We operate the wells that account for 60 percent of our total proved reserves and 70 percent of our production.
Approximately 41 percent of our proved reserves are located in Oklahoma. Properties situated in Texas and Kansas comprised 25 percent and 19 percent of total proved reserves, respectively.
Cimarex was formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc. or H&P. In July 2002, H&P contributed its oil and gas exploration and production assets and the common stock of its gas marketing subsidiary to Cimarex. On September 30, 2002, H&P distributed in the form of a dividend to H&P stockholders approximately 26.6 million shares of Cimarex common stock. As a result, Cimarex was spun off and became a stand-alone company. Also on September 30, 2002, Cimarex acquired Key Production Company, Inc. or Key in a stock-for-stock transaction whereby each of Key’s 14.1 million outstanding common shares was exchanged for Cimarex common stock on a one-for-one basis. Key continues to conduct exploration and development activities as a wholly owned subsidiary of Cimarex.
Because the merger with Key was a tax-free reorganization that was accounted for as a purchase business combination, the financial and operating results presented in this report unless expressly noted otherwise, include Key only for the period subsequent to the merger on September 30, 2002. On September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31.
Cimarex is comprised primarily of an exploration and production segment, but because we market third party gas incidental to the sale of our own production, we also report in our footnotes segment information for natural gas marketing. For a discussion of financial information about the two segments of Cimarex, see Note 13 of Notes to Consolidated Financial Statements contained herein.
Corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203, telephone (303) 295-3995. Principal operations offices are at 15 East 5th Street, Suite 1000, Tulsa, Oklahoma 74103, telephone (918) 585-1100. Our common stock is listed on the New York Stock Exchange and trades under the symbol “XEC.”
Our approach to the business is fundamentally driven by seeking to achieve consistent profitable growth in proved reserves and production by conducting a continually expanding drilling program. To implement this strategy, we seek to:
• Generate our own drilling inventory by maintaining a highly qualified staff of geoscientists;
• Maintain a balanced portfolio of prospects that is underpinned by a predominant mixture (70-90 percent of total capital) of low-to-moderate risk drilling prospects combined with a smaller proportion of higher risk/higher potential projects;
• Mitigate exploration risk by operating in multiple basins, which provides both geologic and geographic diversification to our drilling program;
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• Maintain operational control of our drilling and production activities;
• Closely monitor the production performance of our existing properties and constantly evaluate the potential to increase production rates and enhance ultimate recoveries through workovers, recompletions and operational efficiencies; and
• Maintain financial flexibility and an appropriate capital structure.
To supplement our growth, we also evaluate the economic and strategic attractiveness of acquisition and merger opportunities, such as the acquisition of Magnum Hunter Resources, Inc announced on January 26, 2005.
Our exploration and development activities are focused in western Oklahoma and the upper Gulf Coast areas of Texas and south Louisiana. We have smaller projects underway in Kansas, the Hardeman Basin of north Texas, the Permian Basin of west Texas and southeast New Mexico, the Mississippi Salt Basin, and the northern San Joaquin Valley of California.
For each of our core exploration areas we have assembled integrated teams of geoscientists, landmen and petroleum engineers, who base their drilling decisions on detailed analysis of the potential reserves, expected costs, future net cash flow and risks associated with individual wells and programs. Through our centralized exploration management system, we measure actual results and provide continuous feedback about them to the respective exploration teams in order to help them improve and refine future investment decisions.
Company-wide, we participated in drilling 221 gross wells during 2004, with an overall success rate of 86 percent. On a net basis, 86 of 104 total wells drilled during 2004 were successful.
Our 2004 exploration and development expenditures totaled $296.1 million and resulted in 106.4 Bcfe of proved reserve additions. Of total expenditures, 63 percent ($187.9 million) was invested in projects located in the mid-continent area of the U.S., including Oklahoma, Kansas and north Texas. Approximately 27 percent, or $78.8 million, was directed toward prospects located along the gulf coast of Texas and Louisiana.
One of our most notable discoveries during 2003 was the Mauboules #1 well on the West Gueydan prospect in Vermilion Parish, Louisiana. First sales from this well occurred on February 20, 2004, and net production was averaging 11.1 MMcf of gas and 172 barrels of oil per day at year end. A second well, the Mauboules #2, situated approximately 2,000 feet north of the #1 well, was completed in September 2004, having year-end net daily production of 7.8 MMcf and 129 barrels. We operate both wells with a 64.5 percent working interest and have a 46.4 percent revenue interest.
In September 2004, the Henry Heirs #1 was completed in a separate geologic feature in the immediately surrounding area. Net production from this well was averaging 3.7 MMcf and 88 barrels during December. We operate the Henry Heirs with a 48.3 percent working interest and a 34.8 percent revenue interest. We plan to drill 12 more wells in south Louisiana during 2005.
We continue to have a high level of drilling activity in western Oklahoma, primarily targeting the Red Fork, Atoka and Granite Wash formations in the Anadarko Basin. During 2004, we completed 115 of 125 gross wells in this area, and we anticipate drilling nearly 120 wells there during 2005.
In the Mountain Front play of southwestern Oklahoma, 17 of the 19 wells drilled were completed as producers. One of the larger discoveries in this area, the Gwendolyn #5-29, was averaging 3.2 MMcf of net daily production during December. We plan to drill 20 more wells in this area during 2005.
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In a project area that encompasses the Oklahoma and Texas panhandles, fifteen of sixteen wells drilled were completed as producers during 2004. A total of 28 wells are planned to be drilled in this area during 2005.
In the Arkoma basin of eastern Oklahoma, we drilled and completed 6 wells during 2004, and plan on drilling another three wells in the area in 2005. In the Hardeman Basin of north Texas we completed three of four wells drilled during 2004. We anticipate drilling up to fifteen additional wells in and around the area in 2005.
In Liberty County, Texas, we drilled 14 wells, of which 10 were productive in the Yegua and Cook Mountain formations. Three of the best wells were the Henderson #2 (74.2 percent working interest), the Willis Estate #4 (25.0 percent working interest), and the Temple Inland #1 (37.5 percent working interest). Net daily rates of production from these wells were 2.0 MMcfe, 1.7 MMcfe, and 1.4 MMcfe, respectively. We plan to drill as many as 19 additional wells in this area during 2005.
The Permian Basin of west Texas and southeast New Mexico has recently emerged as a meaningful exploration core area. Through a strategic alliance with an industry partner, and participation in state and Federal lease sales, our drilling program in this area has rapidly expanded. We completed 14 of 18 wells drilled in this basin during 2004 and anticipate pursuing over 26 drilling locations during 2005.
To date, we have participated in 21 wells (15 of which have been successful) in the salt domes located within the Mississippi Salt Basin. We believe a number of exploration opportunities still exist in the area. In 2004, the Ellzey #2 well was completed in November at Centerville Dome, testing at daily net production rates of 400 barrels and 1,000 MMcf. We hold a 54.66 percent working interest and approximately a 40 percent revenue interest in the well. Two additional wells were being drilled in the area at year end, with at least two more wells planned for the Mississippi Salt Basin, as well as three wells planned for the Hosston and Cotton Valley trends in Mississippi, for 2005.
During 2005, we anticipate drilling as many as 26 wells in California, with estimated expenditures to approximate $13.1 million. Our focus will be in the northern San Joaquin Edgeline play and the Sacramento Basin.
As noted earlier, on September 30, 2002 in connection with the spin off of Cimarex from H&P, Cimarex acquired 100 percent of the common stock of Key. Key’s oil and gas properties were valued at $297 million and resulted in the addition of 149.4 Bcfe of proved reserves (98 percent proved developed) principally in Oklahoma, Texas, Mississippi and Louisiana.
In 2003, we added to our ownership interest in certain Texas and Louisiana properties by acquiring incremental interests for $2 million. The property interests acquired had associated proved reserves of 1.6 Bcfe. During 2004, acquisitions of proved oil and gas properties totaled $324 thousand.
On January 26, 2005, Cimarex announced that its board of directors had unanimously approved an agreement and plan of merger that provides for the acquisition by Cimarex of Irving, Texas-based Magnum Hunter Resources, Inc. Terms of the merger agreement provide that Magnum Hunter stockholders will receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock that they own. As a result of the merger transaction and based on the 87.5 million Magnum Hunter common shares currently outstanding, Cimarex expects to issue approximately 36.3 million common shares to Magnum Hunter’s common stockholders (excluding 790 thousand shares to be issued to a subsidiary of Magnum Hunter). After closing, the combined company will have approximately 78 million shares outstanding, and Cimarex stockholders will own 53 percent and
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Magnum Hunter stockholders 47 percent. The merger will be accounted for as a purchase of Magnum Hunter by Cimarex. The merger remains subject to approval by both companies’ stockholders as well as regulatory approvals.
Production volumes during 2004 averaged 217 MMcfe per day versus 180 MMcfe per day in 2003. Gas production was 173.8 MMcf per day, compared to 138.5 MMcf per day during 2003. Oil production was 7,215 barrels per day in 2004 versus 6,859 barrels per day in 2003. The increase in volumes primarily stems from favorable drilling results. Because of natural production declines from the wells we own, our production would typically decrease by 20-25 percent year-to-year, had we not conducted successful drilling operations.
The weighted-average gas price we received during 2004 was $5.76 per Mcf, which was 16 percent higher than the $4.96 per Mcf average price we received during 2003. Our annual average realized oil price during 2004 increased by 37 percent to $40.19 per barrel from $29.30 per barrel in 2003. The increase in the prices we received during 2004 was the result of tighter market conditions for oil and gas.
Our largest producing area was western Oklahoma, providing nearly 46 MMcfe per day, or 21 percent of our total production during 2004. We operated 71 percent of this production, of which 95 percent was gas.
The areas along the Gulf Coast of Texas, Louisiana and Mississippi yielded net production of approximately 41 MMcfe per day of output, which was 19 percent of our 2004 total production, compared to 30 MMcfe per day of production from the area in 2003. Of our 2004 volumes, 78 percent was gas and 69 percent was operated. Production from this area significantly increased from the prior year due to the drilling success realized at the West Gueydan prospect in Louisiana, and several completions in the Yegua and Cook Mountain formations in Liberty County, Texas.
Production in Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 13 percent of our total 2004 production, with 78 percent being gas. We operated 94 percent of the related volumes.
The Permian basin provided about 21 MMcfe per day of production during 2004, with 79 percent of the related volumes being gas and 65 percent from properties we operate.
We have field offices located near our major concentrations of operated properties in Kansas, Oklahoma and Texas and have a centralized production management team in our Tulsa office. We have implemented management systems over our production operations that closely monitor actual results against plan. Overall, approximately 70 percent of our production and 60 percent of our oil and gas reserves are from properties that we operate.
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 generally 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, OGE Energy Resources Inc., accounted for 7 percent of 2004 revenues. Because over two-thirds of our gas production is from wells in Kansas, Oklahoma, 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
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and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.
We have a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI), through which we conduct a majority of our gas marketing activity. Like Cimarex, CESI enters into sales transactions with various purchasers under a variety of short-term arrangements and supplies these sales with equity gas (gas produced by Cimarex) or gas purchased from third parties. Certain gathering systems and related equipment are held and operated by Cimarex and its subsidiaries. CESI operates most of the gas gathering systems and processing plants incidental to our production. Non-equity gas handled by CESI is predominantly comprised of gas owned by our royalty interest owners and working interest partners who have elected to have us sell their gas for them. Gas purchased from other third parties, such as marketing companies and owners of production from wells that we do not have an interest in, is generally limited to activity associated with supplying gas sales arrangements under which our equity gas is also being sold. Approximately 58 percent of the gas sold through CESI was Cimarex equity gas.
CESI has no employees and is not considered an autonomous operating unit. Neither Cimarex nor CESI has any long-term sales contracts nor any marketing arrangements that would be considered derivative instruments within the scope of Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities.
We employed 363 people on December 31, 2004. None of our employees are subject to collective bargaining agreements.
Our Web site address is www.cimarex.com. There you will find our news releases, annual reports and proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other 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 Assistant Corporate Secretary.
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 the 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 financial and human resources substantially larger than those of Cimarex. The effect of these competitive factors on Cimarex cannot be predicted.
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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. Our oil and gas properties are subject to customary royalty interests contracted for in connection with the acquisition of title, 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 many varying and complex Federal and state regulations. In recent years, we have been most directly affected by Federal and state environmental regulations and energy conservation rules. We are indirectly affected by Federal and state regulation of pipeline and other oil and gas transportation systems. Compliance with such laws and regulations increases our overall cost of business, but has not had a material adverse effect on our operations or financial condition.
Most of the states in which we conduct operations regulate the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws 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 often 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 and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect our operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause us to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, we have acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under our control. Under environmental laws and regulations, we could be required to remove or remediate wastes disposed of or released by prior owners or operators. It is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts that are material in relation to our exploration and development expenditure program in order to comply with environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. We also could incur costs related to the clean up of sites to which we sent regulated substances for disposal and for damages to natural resources or other claims related to releases of regulated substances at such sites.
Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open access transportation. Interstate pipelines have implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided 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
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regulations. Although exempt from Federal regulatory oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state agencies.
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.
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.
Cimarex and the petroleum industry in general are affected by both Federal and state income tax laws. 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. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our business, financial condition or results of operations and could negatively impact the value of our common stock. These risks do not include any of the risks associated with our proposed acquisition of Magnum Hunter or the operations of the combined company following the proposed acquisition, if completed. For a discussion of these additional risks, see the discussion under the caption “Risk Factors” in the Form S-4 Registration Statement (File No. 333-123019) filed by Cimarex with the Securities and Exchange Commission on February 25, 2005.
Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in 2004 we sold our gas at an average price of $5.76 per Mcf, which was 16 percent higher than our 2003 average sales price of $4.96 per Mcf. Similarly, our average 2004 oil price of $40.19 per barrel was 37 percent higher than the price we received in 2003 of $29.30 per barrel.
Petroleum prices could continue to be volatile in the future. In recent years, oil prices have responded to changes in supply and demand stemming from actions taken by the Organization of Petroleum Exporting Countries, worldwide economic conditions, growing transportation and power generation needs, and other events. Factors affecting gas prices have included declining domestic supplies; the level and price of natural gas imports into the U.S.; weather conditions; and the price and level of alternative sources of energy such as nuclear power, hydroelectric power, coal, and other petroleum products.
Our proved oil and gas reserves and production volumes will 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
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production operations. Because low oil and gas prices would negatively affect the amount of cash flow available to fund these capital investments, they could also affect our future rate of growth. Low prices may 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.
Most of our wells produce from reservoirs characterized by high levels of initial production and declines which stabilize within three to five years. 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. 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 and reduce our ability to raise capital.
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.
We often are uncertain as to the future cost or timing of drilling, completing and producing wells. 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.
Estimates of proved oil and gas reserves and their associated future net cash flow necessarily depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause estimates to vary considerably from actual results:
• production rates, reservoir pressure, and other subsurface information;
• future oil and gas prices;
• assumed effects of governmental regulation;
• future operating costs;
• future property, severance, excise and other taxes incidental to oil and gas operations;
• capital expenditures;
• workover and remedial costs; and
• Federal and state income taxes.
Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, reviewed our reserve estimates for properties that comprised 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2004.
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The net present values 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 prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.
We deliver oil and gas through pipelines that we do not own. The marketability of our production depends in part upon the availability, proximity and capacity of these pipelines. These facilities may not always be available to us in the future. The lack of availability of these facilities for an extended period of time could negatively affect revenues.
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.
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.
Other companies operate approximately 30 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 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
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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 regularly evaluate opportunities and frequently 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 difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses.
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.
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 Cimarex stockholders.
15
All of our proved reserves and undeveloped acreage is located in the United States, primarily in Oklahoma, Texas, Kansas, Louisiana and Wyoming. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 60 percent of our proved reserves.
Our engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. Ryder Scott Company, L.P., independent petroleum engineers, reviewed our reserve estimates for those properties that comprised 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2004. All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 16, Supplemental Oil and Gas Disclosures, to Notes to Consolidated Financial Statements for further information. See Item 1, Business, for a description of our business.
|
|
|
Gas |
|
Oil, Condensate and |
|
Equivalent |
|
|
Oklahoma |
|
178,099 |
|
1,220 |
|
185,419 |
|
|
Texas |
|
76,451 |
|
5,989 |
|
112,385 |
|
|
Kansas |
|
70,666 |
|
2,612 |
|
86,338 |
|
|
Louisiana |
|
13,744 |
|
356 |
|
15,880 |
|
|
Wyoming |
|
9,443 |
|
2,094 |
|
22,007 |
|
|
Other |
|
16,238 |
|
1,792 |
|
26,991 |
|
|
Total |
|
364,641 |
|
14,063 |
|
449,020 |
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
364,566 |
|
13,372 |
|
444,798 |
|
Collectively our properties in western Oklahoma produced at an average daily rate of about 46 MMcfe during 2004, which was 21 percent of our company-wide 2004 production. These properties consist of varying working interests in approximately 811 wells, mostly located in Roger Mills, Washita, Custer and Beckham counties. We operate wells that account for 71 percent of our Anadarko Basin output.
Elsewhere in the state, we have concentrations of properties in southwestern Oklahoma, focusing on the Mountain Front play, and the Arkoma Basin of eastern Oklahoma, principally the Ashland field. During 2004, net production from the Mountain Front area averaged approximately 14 MMcf of gas per day and output from the Arkoma Basin averaged nearly 5 MMcf per day.
Altogether, at year-end 2004, our Oklahoma properties accounted for 185.4 Bcfe of proved reserves, or 41 percent of our total proved reserves. Production from these properties during 2004 averaged 82 MMcfe per day and equated to 38 percent of our aggregate output. Including all wells, our average working interest in Oklahoma is 25 percent.
In southwest Kansas, our principal properties produce from the Chase and Council Grove formations of the Hugoton field. During 2004, net production from this area averaged 28 MMcfe per day,
16
or 13 percent of total company output. We have a 57 percent average working interest in over 650 Hugoton wells, and we operate 94 percent of the related 2004 production. Our year-end 2004 proved reserves in Kansas of 86.3 Bcfe were 82 percent gas and 19 percent of our total proved reserves.
During 2004, oil production from the Hardeman Basin of north-central Texas averaged nearly 1,900 barrels per day, which equated to 26 percent of our total company-wide oil sales. We have an average working interest of 85 percent in 64 wells and operate 93 percent of our 2004 net production in the Basin.
In Liberty County, Texas, we have over 600 square miles of 3-D seismic survey data and are actively exploring for production from the Yegua and Cook Mountain formations. To date, we have 13 producing wells in the area with working interests ranging from 25 to 87.5 percent. Total 2004 daily production from this area averaged approximately 11.1 MMcf and 510 barrels. During 2004, we drilled fourteen wells in the area, ten of which were productive. We plan to drill as many as 19 additional wells in this area during 2005.
Proved reserves in the Permian Basin include varying working interests in the Dixieland, Gomez and Toro fields, and a one percent interest in the Denver Unit. The Dixieland #10-2 well in Reeves County produced gas at an average rate of 4.5 MMcf per day during 2004.
Overall, our proved oil and gas reserves in Texas amounted to 112.4 Bcfe, represent 25 percent of total proved reserves and are 68 percent natural gas. Production volumes during 2004 from our Texas properties averaged 65 MMcfe per day, or 30 percent of total production.
Our activity in the Permian Basin has expanded into southeast New Mexico, with further drilling being planned in the area in 2005.
In south Louisiana, our Mauboules #1 and #2 wells in the West Gueydan prospect of Vermilion Parish produced an average of 12.5 MMcfe per day during 2004, or 5.8 percent of our total production. We operate both wells with a 64.5 percent working interest and have a 46.4 percent revenue interest. The Henry Heirs #1 was completed in September 2004 on a separate geologic feature in the immediately surrounding area. This third well averaged 3.7 net MMcf and 88 net barrels per day during December. We operate this well with a 48.0 percent working interest and a 34.8 percent revenue interest. In total, our south Louisiana properties have proved reserves equal to 3.5 percent of our company-wide total proved reserves. We plan to drill a total of 12 wells in Louisiana during 2005, with working interests averaging approximately 42 percent and revenue interests averaging 31 percent.
In the western U.S., our principal properties include small (averaging approximately five percent) royalty and working interests in over 1,200 non-operated wells in the Powder River, Wind River and Big Horn basins of Wyoming. In aggregate, these interests accounted for 4.9 percent of our total proved reserves.
In the Williston Basin of North Dakota and Montana, we own an average working interest of 20 percent in 74 producing wells. During 2004, oil production from this area averaged 123 barrels per day and our total proved reserves amounted to 5 Bcfe, of which 93 percent was oil.
Proved reserves attributable to our California operations amount to 5.4 Bcf of gas, or 1.2 percent of our total proved reserves. We operate 31 wells in California, with an average 81 percent working interest.
17
The undeveloped and developed acreage held by us as of December 31, 2004 is set forth below:
|
|
|
Undeveloped Acreage |
|
Developed Acreage |
|
||||
|
|
|
Gross Acres |
|
Net Acres |
|
Gross Acres |
|
Net Acres |
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama |
|
1,267 |
|
1,109 |
|
— |
|
— |
|
|
Arkansas |
|
— |
|
— |
|
4,766 |
|
1,638 |
|
|
California |
|
45,683 |
|
41,694 |
|
10,091 |
|
8,016 |
|
|
Colorado |
|
12,874 |
|
315 |
|
14,803 |
|
2,758 |
|
|
Kansas |
|
4,836 |
|
4,726 |
|
123,738 |
|
90,400 |
|
|
Louisiana |
|
3,597 |
|
1,560 |
|
23,443 |
|
4,381 |
|
|
Michigan |
|
361 |
|
282 |
|
— |
|
— |
|
|
Mississippi |
|
6,836 |
|
2,420 |
|
11,368 |
|
3,121 |
|
|
Montana |
|
41,849 |
|
13,439 |
|
11,512 |
|
6,333 |
|
|
Nebraska |
|
12,821 |
|
969 |
|
480 |
|
168 |
|
|
New Mexico |
|
18,450 |
|
6,035 |
|
16,157 |
|
4,091 |
|
|
North Dakota |
|
40,032 |
|
16,433 |
|
11,463 |
|
1,262 |
|
|
Oklahoma |
|
51,282 |
|
46,626 |
|
206,861 |
|
94,469 |
|
|
Texas |
|
79,306 |
|
49,664 |
|
177,220 |
|
68,490 |
|
|
Utah |
|
13,821 |
|
3,425 |
|
19,784 |
|
1,718 |
|
|
Wyoming |
|
106,714 |
|
19,819 |
|
90,788 |
|
29,623 |
|
|
|
|
439,729 |
|
208,516 |
|
722,474 |
|
316,468 |
|
We participated in drilling the following number of gross wells during calendar years 2004, 2003 and 2002:
|
|
|
Exploratory |
|
Developmental |
|
||||||||
|
|
|
Productive |
|
Dry |
|
Total |
|
Productive |
|
Dry |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2004 |
|
12 |
|
11 |
|
23 |
|
177 |
|
21 |
|
198 |
|
|
Year ended December 31, 2003 |
|
19 |
|
27 |
|
46 |
|
125 |
|
7 |
|
132 |
|
|
Year ended December 31, 2002 |
|
13 |
|
12 |
|
25 |
|
84 |
|
1 |
|
85 |
|
We were in the process of drilling 27 gross (15.3 net) wells at December 31, 2004.
The number of net wells we drilled during calendar years 2004, 2003 and 2002 are shown below:
|
|
|
Exploratory |
|
Developmental |
|
||||||||
|
|
|
Productive |
|
Dry |
|
Total |
|
Productive |
|
Dry |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2004 |
|
6.78 |
|
6.55 |
|
13.33 |
|
78.78 |
|
12.16 |
|
90.94 |
|
|
Year ended December 31, 2003 |
|
17.42 |
|
20.12 |
|
37.54 |
|
55.45 |
|
4.21 |
|
59.66 |
|
|
Year ended December 31, 2002 |
|
7.05 |
|
4.15 |
|
11.20 |
|
32.07 |
|
0.93 |
|
33.00 |
|
18
Our estimated proved oil and gas reserves, as of December 31, 2004, 2003 and 2002 are included in Note 16, Supplemental Oil and Gas Disclosures to Notes to Consolidated Financial Statements appearing in this Form 10-K. The Supplemental Oil and Gas Disclosures also include for the same periods estimates of our future revenue and associated costs resulting from projected production of our proved reserves.
|
|
|
Total Proved Reserves |
|
Proved Developed Reserves |
|
||||||||
|
|
|
Gas |
|
Oil |
|
Total |
|
Gas |
|
Oil |
|
Total |
|
|
As of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
364,641 |
|
14,063 |
|
449,020 |
|
364,566 |
|
13,372 |
|
444,798 |
|
|
December 31, 2003 |
|
337,344 |
|
14,137 |
|
422,167 |
|
336,230 |
|
13,876 |
|
419,488 |
|
|
December 31, 2002 |
|
318,627 |
|
15,025 |
|
408,779 |
|
318,452 |
|
14,765 |
|
407,044 |
|
Future reserve values are based on year-end prices except in those instances where the sale of gas is covered by contract terms providing for determinable escalations. Operating costs, production and ad valorem taxes, and future development costs are based on current costs with no escalations (in thousands, except price data).
|
|
|
Discounted Future Net |
|
Standardized |
|
Average |
|
||||||
|
|
|
|
|
|
|
Gas |
|
Oil |
|
||||
|
As of: |
|
|
|
|
|
|
|
|
|
||||
|
December 31, 2004 |
|
$ |
1,172,230 |
|
$ |
798,033 |
|
$ |
5.58 |
|
$ |
40.76 |
|
|
December 31, 2003 |
|
1,030,340 |
|
711,581 |
|
5.54 |
|
30.49 |
|
||||
|
December 31, 2002 |
|
741,209 |
|
533,859 |
|
4.22 |
|
28.56 |
|
||||
We have working interests in the following productive oil and gas wells as of December 31, 2004:
|
|
|
Gas |
|
Oil |
|
||||
|
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
|
Kansas |
|
450 |
|
279.0 |
|
201 |
|
94.3 |
|
|
Louisiana |
|
50 |
|
15.7 |
|
17 |
|
3.0 |
|
|
Oklahoma |
|
1,293 |
|
355.8 |
|
388 |
|
58.9 |
|
|
Texas |
|
391 |
|
132.6 |
|
3,582 |
|
127.5 |
|
|
Wyoming |
|
91 |
|
4.8 |
|
1,115 |
|
57.5 |
|
|
Other |
|
166 |
|
41.9 |
|
158 |
|
26.4 |
|
|
|
|
2,441 |
|
829.8 |
|
5,461 |
|
367.6 |
|
19
The following table describes for the periods indicated our production, pricing and production cost data:
|
|
|
Gas |
|
Oil |
|
|
|
Average |
|
|||||
|
|
Per Mcf |
|
Per Bbl |
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
Year ended December 31, 2004 |
|
63,611 |
|
2,641 |
|
$ |
5.76 |
|
$ |
40.19 |
|
$ |
0.47 |
|
|
Year ended December 31, 2003 |
|
50,552 |
|
2,504 |
|
$ |
4.96 |
|
$ |
29.30 |
|
$ |
0.49 |
|
|
Year ended December 31, 2002 |
|
41,300 |
|
1,171 |
|
$ |
3.10 |
|
$ |
24.97 |
|
$ |
0.40 |
|
20
H.B. Krug, et al v. Helmerich & Payne, Inc., filed in the District Court of Tulsa County, Oklahoma on December 22, 1998 (Case No. CS-98-06012)
Cimarex is a defendant to certain claims relating to drainage of gas from two properties that it operates. The royalty owner plaintiffs have filed suit on behalf of themselves and a class of allegedly similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was in an amount that significant. The plaintiffs have stated that the royalty owner class has sustained actual damages of approximately $20 million exclusive of interest and costs. We estimate that the share of such alleged damages attributable to our working interest ownership would total approximately $3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, should not exceed our working interest share of any actual damages attributable to the alleged drainage. In this regard, the court granted our request to assert third-party claims against all of the other working interest owners. Our contention is that the other working interest owners should bear responsibility for their respective pro rata shares of damages, if any. We cannot predict the outcome of this litigation, and accordingly, no accrual has been recorded in connection with this action.
Cimarex has other various litigation related matters in the normal course of business, none of which are material, individually or in aggregate. We are also party to certain litigation as plaintiffs that could result in potential gains. Net settlements of $3.4 million have been received during 2004 related to litigation in which we were plaintiffs. Such amounts were recorded as other income. Any future potential gains are not deemed material at this time.
No matters were submitted for a vote of security holders during the fourth quarter of 2004.
The executive officers of Cimarex as of March 7, 2005 were:
|
Name |
|
Age |
|
Office |
|
|
|
|
|
|
|
F.H. Merelli |
|
68 |
|
Chairman of the Board, Chief Executive Officer and President |
|
Thomas E. Jorden |
|
47 |
|
Executive Vice President-Exploration |
|
Joseph R. Albi |
|
46 |
|
Executive Vice President-Operations |
|
Paul Korus |
|
48 |
|
Vice President, Chief Financial Officer, Treasurer and Secretary |
|
Stephen P. Bell |
|
50 |
|
Senior Vice President, Business Development and Land |
|
Gary R. Abbott |
|
32 |
|
Vice President-Corporate Engineering |
|
Richard S. Dinkins |
|
60 |
|
Vice President of Human Resources |
|
James H. Shonsey |
|
53 |
|
Chief Accounting Officer and Controller |
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, president and a director of Cimarex on September 30, 2002. Prior to its merger with Cimarex, Mr. Merelli had been the chairman and chief executive officer of Key since 1992.
21
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 its merger with Cimarex, Mr. Jorden was with Key. He served as chief geophysicist from November 1993 until September 1999, before being appointed vice president of exploration. Prior to joining Key, Mr. Jorden was with Union Pacific Resources in Fort Worth, Texas.
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. From 1994 until September 30, 2002, Mr. Albi was with Key where he served as vice president of engineering.
PAUL KORUS was elected vice president, chief financial officer, treasurer and corporate secretary on September 30, 2002. Mr. Korus joined Key in September 1999 as its vice president and chief financial officer. Prior to September 1999 and since June 1995, Mr. Korus was an equity research analyst with Petrie Parkman & Co., an investment banking firm.
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 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.
RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key 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 in Overland Park, Kansas.
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 senior engineer with Key Production.
JAMES H. 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.
22
Cimarex’s $0.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. Cimarex does not pay dividends and does not anticipate declaring dividends in the foreseeable future. We intend to retain earnings for the operation and expansion of our business, including exploration and development activities.
Cimarex common stock was listed on the New York Stock Exchange on September 26, 2002, on a “when-issued” basis, and commenced normal trading on October 1, 2002. The high and low sales prices of Cimarex common stock for the each quarter of 2003 and 2004 were:
|
|
|
2004 |
|
2003 |
|
||||||||
|
|
|
High |
|
Low |
|
High |
|
Low |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
First Quarter |
|
$ |
29.75 |
|
$ |
24.05 |
|
$ |
20.42 |
|
$ |
17.07 |
|
|
Second Quarter |
|
$ |
30.25 |
|
$ |
26.24 |
|
$ |
24.40 |
|
$ |
18.80 |
|
|
Third Quarter |
|
$ |
35.25 |
|
$ |
29.20 |
|
$ |
23.70 |
|
$ |
19.24 |
|
|
Fourth Quarter |
|
$ |
41.45 |
|
$ |
33.60 |
|
$ |
28.14 |
|
$ |
19.50 |
|
The closing price of Cimarex stock as reported on the New York Stock Exchange on March 4, 2005, was $41.75. At December 31, 2004, Cimarex’s 41,729,280 shares of outstanding common stock were held by approximately 3,455 stockholders of record.
23
The following table shows selected financial data for the years ended December 31, 2004, 2003 and 2002, together with similar information for each of the two preceding fiscal years ended September 30, and the three months ended December 31, 2001.
On September 30, 2002, Cimarex acquired 100 percent of the common stock of Key in a tax-free exchange of stock accounted for as a business purchase combination. Also on September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. Results of Key are included in the operating results only for the period subsequent to the acquisition on September 30, 2002. This information should be read in connection with and is qualified in its entirety by the more detailed information and Consolidated Financial Statements provided in Item 8 of this Form 10-K:
|
|
|
As of and For the Years Ended |
|
Three Months 2001 |
|
||||||||||||||
|
|
|
December 31, |
|
September 30, |
|
|
|||||||||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
|
|||||||
|
|
|
(In thousands, except per share and proved reserve amounts) |
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Operating results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Revenues |
|
$ |
674,929 |
|
$ |
454,212 |
|
$ |
209,644 |
|
$ |
316,778 |
|
$ |
237,021 |
|
$ |
39,596 |
|
|
Net income |
|
153,592 |
|
94,633 |
|
39,819 |
|
35,253 |
|
57,386 |
|
4,479 |
|
||||||
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Basic |
|
3.70 |
|
2.28 |
|
1.32 |
|
1.33 |
|
2.16 |
|
0.17 |
|
||||||
|
Diluted |
|
3.59 |
|
2.22 |
|
1.31 |
|
1.33 |
|
2.16 |
|
0.17 |
|
||||||
|
Cash dividends declared per share |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
||||||
|
Balance sheet data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Total assets |
|
1,105,446 |
|
805,508 |
|
674,286 |
|
246,212 |
|
286,090 |
|
251,966 |
|
||||||
|
Total debt |
|
— |
|
— |
|
32,000 |
|
— |
|
— |
|
— |
|
||||||
|
Stockholders’ equity |
|
700,712 |
|
534,740 |
|
444,880 |
|
166,795 |
|
192,972 |
|
175,082 |
|
||||||
|
Other financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Oil and gas sales |
|
472,389 |
|
324,119 |
|
157,299 |
|
222,136 |
|
158,502 |
|
26,857 |
|
||||||
|
Oil and gas capital expenditures |
|
296,371 |
|
162,082 |
|
368,399 |
|
104,975 |
|
73,821 |
|
14,425 |
|
||||||
|
Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Gas (MMcf) |
|
364,641 |
|
337,344 |
|
318,627 |
|
216,337 |
|
262,498 |
|
212,326 |
|
||||||
|
Oil (MBbls) |
|
14,063 |
|
14,137 |
|
15,025 |
|
5,932 |
|
6,305 |
|
5,304 |
|
||||||
|
Total equivalent (MMcfe) |
|
449,020 |
|
422,167 |
|
408,779 |
|
251,927 |
|
300,329 |
|
244,150 |
|
||||||
24
Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are presently focused in Oklahoma, Texas, Kansas and Louisiana. Our primary focus is to explore for and discover new reserves.
To supplement our growth, we also consider acquisitions and mergers, such as the proposed acquisition of Magnum Hunter Resources, Inc. On January 26, 2005, Cimarex announced that its board of directors had unanimously approved an agreement and plan of merger that provides for the acquisition by Cimarex of Irving, Texas-based Magnum Hunter Resources, Inc. Terms of the merger agreement provide that Magnum Hunter stockholders will receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock that they own. As a result of the merger transaction and based on the 87.5 million Magnum Hunter common shares currently outstanding, Cimarex expects to issue approximately 36.3 million common shares to Magnum Hunter’s common stockholders (excluding 790 thousand shares issued to a subsidiary of Magnum Hunter). After closing, the combined company will have approximately 78 million shares outstanding, and Cimarex stockholders will own 53 percent and Magnum Hunter stockholders 47 percent. The merger will be accounted for as a purchase of Magnum Hunter by Cimarex. The merger remains subject to approval by both companies’ stockholders as well as regulatory approvals.
In managing our business, we must deal with many factors inherent in our industry. First and foremost is wide fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile, with future price movements difficult to predict. While our revenues are a function of both production and prices, it is wide swings in prices that have most often had the greatest impact on our results of operations.
Our operations entail significant complexities. Advanced technologies requiring highly trained personnel are utilized in both exploration and production. Even when the technology is properly used, the interpreter still may not know conclusively if hydrocarbons will be present or the rate at which they will be produced. Exploration is a high-risk activity, often times resulting in no commercially productive reservoirs being discovered. Moreover, costs associated with operating within the industry are substantial.
The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas businesses, and individual operators. In addition, the industry as a whole competes with other businesses that supply energy to industrial and commercial end users.
Extensive Federal, state and local regulation of the industry significantly affects our operations. In particular, our activities are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.
25
Approach to the Business
Profitable growth of our assets will largely depend upon our ability to successfully find and develop new proved reserves. To accommodate an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate and higher risk exploration and development projects. We believe that this approach allows for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We may consider the use of transaction specific hedging of oil and gas prices, if warranted, to reduce price risk. However, to date the use of hedging has not been implemented.
Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of capital.
We project that 2005 exploration and development expenditures will approximate $350-375 million, up from $296 million in 2004. We are expanding our 2005 program as a result of successful exploration wells drilled in 2004, growth in our western Oklahoma development projects and entry into new basins. Similar to 2004, a large portion of our 2005 expenditures will be directed to our projects in Oklahoma, Texas and Louisiana. A total of $200 million is anticipated to be invested in the mid-continent area of Oklahoma and north Texas. We plan to invest $100 million in the upper Gulf Coast Regions of Texas and Louisiana during 2005. The remainder of our projected 2005 expenditures will be focused in the Permian Basin, California and other western states.
Based on expected cash provided by operating activities and stockholders’ equity of $700.7 million, a cash balance of $115.7 million, no debt, and proved reserves of 449 Bcfe, we believe we are well positioned to fund the projects identified for 2005 and beyond.
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. Our significant accounting policies are described in Note 3 to our consolidated financial statements included in this report. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” 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, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, 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 critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.
Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production.
26
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. For 2004 revisions of reserve estimates resulted in an increase of 1.2 MMBbls of oil and an increase of 20.1 Bcf of gas, representing eight percent and five percent of proved oil and gas reserves, respectively, as of the end of the year. Revisions of oil and gas reserve estimates for 2003 resulted in an increase of 0.3 percent and 2.0 percent, respectively. See Note 16, Supplemental Oil and Gas Disclosures for reserve data.
As described in Note 3 of Notes to Consolidated Financial Statements, we use the units-of-production method to amortize our oil and gas properties. Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the quantity revision or, in some cases, a full cost ceiling limitation charge in the period of the revision. To date, changes in expense resulting from changes in previous estimates of reserves have not been material.
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.
Under full cost accounting rules, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value discounted at 10 percent of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Cash flows used in the calculation of the full cost ceiling limitation are determined based upon estimates of proved oil and gas reserves, future prices, and the costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying value of our oil and gas properties. If capitalized costs exceed this limit, the excess must be charged to expense. This is referred to as the “full cost ceiling limitation.” The expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation.
At the end of each quarter, a full cost ceiling limitation calculation is made. See Note 3 of Notes to Consolidated Financial Statements.
27
Goodwill
As described in Note 3 of Notes to Consolidated Financial Statements, we account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of the reporting unit. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. These factors are each individually weighted to estimate the total fair value of the reporting unit. If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the unit is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. We recorded $45.0 million of goodwill in the purchase of Key on September 30, 2002. To date, no impairment has been recorded.
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. As of December 31, 2004, no liabilities have been accrued for known contingencies. See Note 15 of Notes to Consolidated Financial Statements.
In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share-Based Payment, requiring companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation to employees for fiscal periods after June 15, 2005. This Statement amends SFAS No. 123, Accounting for Stock Based Compensation. We currently provide in our Notes to Consolidated Financial Statements pro forma information regarding net income as if the compensation cost for our stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure.
We anticipate adopting the provisions of SFAS No. 123R in the first quarter of 2005 and that the impact, based on outstanding options at December 31, 2004, will result in future charges to compensation expense similar to the pro forma amounts reflected in Note 3 of Notes to Consolidated Financial Statements.
Accounting for Income Taxes, thus reducing tax expense in the periods the deductions are deductible on the tax return and not as an adjustment of recorded deferred tax assets and liabilities.
Our results of operations are impacted by oil and gas prices, which are volatile. Realized oil and gas prices increased from $29.30 per Bbl and $4.96 per Mcf in 2003 to $40.19 per Bbl and $5.76 per Mcf in 2004. The majority of our revenues are from oil and gas sales, so price fluctuations can significantly affect our financial results.
28
Marketing sales and related purchases pertain to activities with third parties conducted by our marketing group. Natural gas sales transactions are conducted with various purchasers under a variety of terms and conditions and supplied by purchasing gas from other producers and marketing companies. For the sales transactions in which the gas is supplied by our own production, related sales and costs are reflected in Cimarex’s gas sales and transportation expense.
Transportation expenses are comprised of costs paid to carry and deliver oil and gas to a specified delivery 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 revenues and costs are shown gross in sales and expenses, respectively.
Production costs are composed of lease operating expenses, which generally consist of pumpers’ salaries, utilities, maintenance and other costs necessary to operate our producing properties.
Taxes other than income are taxes assessed by applicable taxing authorities pertaining to production, revenues or the value of our properties. These typically include production severance, ad valorem and excise taxes.
Depreciation, depletion and amortization of our producing properties is computed using the unit-of-production method. Because the economic life of each producing well depends upon the assumed price for 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, while lower prices generally have the effect of decreasing reserves, which increases depletion.
General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.
Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees.
Cimarex was formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc., or H&P. In July 2002, H&P contributed its oil and gas exploration and production assets and the common stock of Cimarex Energy Services, Inc. (CESI) to Cimarex. On September 30, 2002, H&P distributed in the form of a dividend to H&P stockholders approximately 26.6 million shares of Cimarex common stock. As a result, Cimarex was spun-off and became a stand-alone company.
Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc., or Key. The transaction was treated as a tax-free reorganization and accounted for as a purchase business combination. In the merger, we issued 14.1 million shares of Cimarex common stock on a one-for-one basis for 100 percent of the shares of Key common stock outstanding. Key continues to conduct exploration and development activities as a wholly owned subsidiary of Cimarex.
Because the merger was accounted for as a purchase business combination, the financial and operating results presented in this report on Form 10-K, unless expressly noted otherwise, include Key only for the period subsequent to the merger on September 30, 2002.
On September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31 effective January 1, 2002. Financial statements included in this report show results of operations for the years ended December 31, 2004, 2003 and 2002.
29
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
SUMMARY DATA:
|
|
|
For the Years Ended |
|
||||
|
(in thousands or as indicated) |
|
2004 |
|
2003 |
|
||
|
Net income |
|
$ |
153,592 |
|
$ |
94,633 |
|
|
Per share-basic |
|
3.70 |
|
2.28 |
|
||
|
Per share-diluted |
|
3.59 |
|
2.22 |
|
||
|
|
|
|
|
|
|
||
|
Gas sales |
|
$ |
366,260 |
|
$ |
250,764 |
|
|
Oil sales |
|
106,129 |
|
73,355 |
|
||
|
Total oil and gas sales |
|
$ |
472,389 |
|
$ |
324,119 |
|
|
|
|
|
|
|
|
||
|
Total gas volume-MMcf |
|
63,611 |
|
50,552 |
|
||
|
Gas volume-MMcf per day |
|
173.8 |
|
138.5 |
|
||
|
Average gas price-per Mcf |
|
$ |
5.76 |
|
$ |
4.96 |
|
|
|
|
|
|
|
|
||
|
Total oil volume-thousand barrels |
|
2,641 |
|
2,504 |
|
||
|
Oil volume-barrels per day |
|
7,215 |
|
6,859 |
|
||
|
Average oil price-per barrel |
|
$ |
40.19 |
|
$ |
29.30 |
|
|
|
|
|
|
|
|
||
|
Marketing sales |
|
$ |
195,816 |
|
$ |
130,156 |
|
|
Marketing purchases |
|
193,325 |
|
129,503 |
|
||
|
Marketing margin |
|
$ |
2,491 |
|
$ |
653 |
|
|
|
|
|
|
|
|
||
|
Other, net |
|
$ |
6,724 |
|
$ |
(63 |
) |
|
|
|
|
|
|
|
||
|
Depreciation, depletion and amortization |
|
$ |
124,251 |
|
$ |
88,774 |
|
|
Production |
|
37,476 |
|
31,801 |
|
||
|
Transportation |
|
10,003 |
|
7,472 |
|
||
|
Taxes other than income |
|
37,761 |
|
27,485 |
|
||
|
General and administrative |
|
22,483 |
|
17,526 |
|
||
|
Stock compensation |
|
1,957 |
|
1,824 |
|
||
|
Asset retirement obligation accretion |
|
1,241 |
|
1,009 |
|
||
We reported net income of $153.6 million, or $3.59 per diluted share, in 2004 compared to net income of $94.6 million, or $2.22 per diluted share, in 2003. The primary reason for this increase in net income is the increase in revenues from oil and gas sales. These sales for 2004 equaled $472.4 million, compared to $324.1 million in 2003. The $148.3 million increase in sales between the two years consists of $79.6 million related to higher oil and gas prices, and $68.7 million associated with increased production volumes.
Realized gas prices averaged $5.76 per Mcf for 2004, compared to $4.96 per Mcf for 2003. This 16 percent increase had an incremental effect on sales of $50.9 million between the two years. Realized oil prices averaged $40.19 per barrel for 2004, compared to $29.30 per barrel for 2003. The effect on sales between years resulting from this 37 percent improvement in oil prices totaled $28.7 million. Higher prices were the direct result of overall market conditions. We have not entered into any derivative contracts or hedges with respect to our production.
Oil and gas sales also benefited from higher production volumes. Average gas volumes rose 35.3 MMcf per day in 2004 to 173.8 MMcf per day from 138.5 MMcf per day in 2003, resulting in $64.8 million of incremental revenues. Oil volumes averaged 7,215 barrels per day in 2004, compared to 6,859
30
barrels per day in 2003, resulting in increased revenues of $3.9 million. The increase in overall sales volumes between the two years is due to positive drilling results during 2004. Average daily production contributed from wells drilled during 2004 totaled 27.8 MMcfe, which largely offset natural declines.
Marketing sales net of related purchases equaled $2.5 million in 2004 compared to $0.7 million in 2003. These sales relate to marketing activities with outside parties conducted by our marketing group. The financial impact from these activities is small relative to our overall results of operations. The marketing margin in 2004 was favorably impacted by wide fluctuations in gas prices. Revenues and costs related to marketing of our own production are eliminated in consolidation.
Other revenues and expenses (net) equaled $6.7 million in 2004, consisting primarily of $3.2 million of net gains from the sale of inventory and $3.4 million of net gains from the settlement of various litigation.
Overall costs and expenses (not including income taxes) were $235.3 million in 2004 compared to $176.5 million in 2003. The largest component of this $58.8 million increase between years is a $35.5 million increase in total depreciation, depletion and amortization expense (DD&A) from $88.8 million in 2003 to $124.3 million in 2004, resulting from higher costs for reserves added during 2004. On a unit of production basis, DD&A was $1.56 per Mcfe in 2004 compared to $1.35 per Mcfe for 2003.
Taxes other than income were $10.3 million greater, rising from $27.5 million in 2003 to $37.8 million in 2004. This increase resulted from a 46 percent jump in oil and gas sales stemming from higher product prices and volumes.
Production costs rose $5.7 million from $31.8 million in 2003 to $37.5 million in 2004 due primarily to the installation and operation of additional compressors (primarily in Kansas) to enhance production, higher field operating expenses from an expanded number of properties, and higher maintenance costs.
General and administrative (G&A) expenses increased $5.0 million from $17.5 million in 2003 to $22.5 million in 2004, due to an expansion of staff as a result of a larger drilling program, higher employee-benefit costs, and higher consulting fees.
Smaller variances of costs between years include stock compensation related to amortization of costs of restricted stock, slightly increasing by $.1 million between years from $1.8 in 2003 to $1.9 million in 2004; and accretion expense associated with asset retirement obligations, increasing by $.2 million from $1.0 million in 2003 to $1.2 million in 2004. Asset retirement obligations were recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003.
Income tax expense
Income tax expense totaled $92.7 million for 2004 versus $55.1 million for 2003. Tax expense equaled a combined Federal and state effective income tax rate of 37.6 percent and 37.2 percent in 2004 and 2003, respectively. The increase in effective rates results from greater utilization of tax credits in 2003. We estimate that $25.9 million of our 2004 income tax expense is current.
31
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
SUMMARY DATA:
|
|
|
For the Years Ended |
|
||||
|
(in thousands or as indicated) |
|
2003 |
|
2002 |
|
||
|
|
|
|
|
|
|
||
|
Net income |
|
$ |
94,633 |
|
$ |
39,819 |
|
|
Per share-basic |
|
2.28 |
|
1.32 |
|
||
|
Per share-diluted |
|
2.22 |
|
1.31 |
|
||
|
|
|
|
|
|
|
||
|
Gas sales |
|
$ |
250,764 |
|
$ |
128,060 |
|
|
Oil sales |
|
73,355 |
|
29,239 |
|
||
|
Total oil and gas sales |
|
$ |
324,119 |
|
$ |
157,299 |
|
|
|
|
|
|
|
|
||
|
Total gas volume-MMcf |
|
50,552 |
|
41,300 |
|
||
|
Gas volume-MMcf per day |
|
138.5 |
|
113.2 |
|
||
|
Average gas price-per Mcf |
|
$ |
4.96 |
|
$ |
3.10 |
|
|
|
|
|
|
|
|
||
|
Total oil volume-thousand barrels |
|
2,504 |
|
1,171 |
|
||
|
Oil volume-barrels per day |
|
6,859 |
|
3,209 |
|
||
|
Average oil price-per barrel |
|
$ |
29.30 |
|
$ |
24.97 |
|
|
|
|
|
|
|
|
||
|
Marketing sales |
|
$ |
130,156 |
|
$ |
52,350 |
|
|
Marketing purchases |
|
129,503 |
|
49,671 |
|
||
|
Marketing margin |
|
$ |
653 |
|
$ |
2,679 |
|
|
|
|
|
|
|
|
||
|
Depreciation, depletion and amortization |
|
$ |
88,774 |
|
$ |
49,231 |
|
|
Production |
|
31,801 |
|
19,427 |
|
||
|
Transportation |
|
7,472 |
|
7,918 |
|
||
|
Taxes other than income |
|
27,485 |
|
13,154 |
|
||
|
General and administrative |
|
17,526 |
|
8,568 |
|
||
|
Stock compensation |
|
1,824 |
|
125 |
|
||
|
Asset retirement obligation accretion |
|
1,009 |
|
— |
|
||
We reported net income of $94.6 million, or $2.22 per diluted share, in 2003 compared to net income of $39.8 million, or $1.31 per diluted share, in 2002. The primary reason for this increase in net income is the increase in revenues from oil and gas sales. These sales for 2003 equaled $324.1 million, compared to $157.3 million in 2002. The $166.8 million increase in sales between the two years consists of $104.8 million related to higher oil and gas prices, and $62.0 million associated with increased production volumes.
Realized gas prices averaged $4.96 per Mcf for 2003, compared to $3.10 per Mcf for 2002. This 60 percent increase had an incremental effect on sales of $94.0 million between the two years. Realized oil prices averaged $29.30 per barrel for 2003, compared to $24.97 per barrel for 2002. The effect on sales between years resulting from this 17 percent improvement in oil prices totaled $10.8 million. Higher prices were the direct result of overall market conditions. We have not entered into any derivative contracts or hedges with respect to our production.
Oil and gas sales also benefited from higher production volumes. Average gas volumes rose 25.3 MMcf per day in 2003 to 138.5 MMcf per day from 113.2 MMcf per day in 2002, resulting in $28.7 million of incremental revenues. Oil volumes averaged 6,859 barrels per day in 2003, compared to 3,209
32
barrels per day in 2002, resulting in increased revenues of $33.3 million. The increase in overall sales volumes between the two years is due to the Key acquisition and positive drilling results during 2003. Prior to the acquisition, sales volumes for the first three quarters of 2002 averaged 116.4 MMcfe per day. With the inclusion of Key’s volumes in the fourth quarter of 2002, production increased to 179.7 MMcfe per day. Average daily production contributed from wells drilled during 2003 totaled 17.2 MMcfe, which largely offset natural declines.
Marketing sales net of related purchases equaled $0.7 million in 2003 compared to $2.7 million in 2002. These sales relate to marketing activities with outside parties conducted by our marketing group. The financial impact from these activities is small relative to our overall results of operations. The marketing margin in 2002 was favorably impacted by wide fluctuations in gas prices. Revenues and costs related to marketing of our own production are eliminated in consolidation.
Production costs rose $12.4 million from $19.4 million in 2002 to $31.8 million in 2003 due to the acquisition of Key’s properties and higher workover costs incurred during 2003 for the maintenance of our wells. The mix of Key’s wells included proportionately more oil wells, which generally cost more to operate because of additional pumping and electricity charges.
General and administrative (G&A) expenses increased $8.9 million from $8.6 million in 2002 to $17.5 million in 2003, due to the larger organization resulting from the Key acquisition as well as the expanded drilling program that has been implemented.
Stock compensation related to amortization of restricted stock costs increased by $1.7 million between years, because the majority of the restricted stock and stock units were issued in December 2002.
Accretion expense associated with asset retirement obligations was $1.0 million in 2003. Asset retirement obligations were recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003.
Income tax expense totaled $55.1 million for 2003 versus $21.6 million for 2002. Tax expense equaled a combined Federal and state effective income tax rate of 37.2 percent and 35.1 percent in 2003 and 2002, respectively. The increase in effective rates results from greater utilization of tax credits in 2002. We estimate that $24.6 million of our 2003 income tax expense is current.
33
Our primary source of capital is cash flow generated from operating activities. Prices we receive for future oil and gas sales and our level of production will impact these future cash flows. No prediction can be made as to the prices we will receive. Production volumes will in part be dependent upon the amount of future capital expenditures. In turn, actual levels of capital expenditures may vary due to many factors, including drilling results, oil and gas prices, industry conditions, prices and availability of goods and services, and the extent to which proved properties are acquired.
Cash flow provided by operating activities for the year ended December 31, 2004 was $360.7 million, compared to $206.3 million and $104.5 million for the years ended December 31, 2003 and 2002, respectively. The increase in 2004 from the earlier periods results primarily from higher prices and production. Higher revenues from oil and gas sales funded our exploration and development expenditure program for the year, and built a larger balance of cash at year end than we held in 2003.
Cash flow used in investing activities for the year ended December 31, 2004 was $293.1 million, compared to $159.6 million and $71.7 million for the years ended December 31, 2003 and 2002, respectively. The increase in 2004 stems from a larger exploration and development program.
Cash flow provided by financing activities in 2004 was $7.8 million versus $28.6 million used in financing activities in 2003, a change of $36.4 million. The most significant item that occurred during 2003 was the repayment of $32.0 million of bank debt. Cash flows used in financing activities for the year ended December 30, 2002 were $17.6 million.
As of December 31, 2004, stockholders’ equity totaled $700.7 million, up from $534.7 million at December 31, 2003. The increase resulted primarily from 2004 net income of $153.6 million. During 2004 we increased our cash balance by $75.3 million from $40.4 million at December 31, 2003 to $115.7 million at December 31, 2004.
Working capital at December 31, 2004 totaled $93.4 million, compared to $37.7 million at December 31, 2003. The largest component of this increase was the higher cash balance that resulted from cash flow provided by operating activities. Receivables comprise another significant portion of our working capital, totaling $104.0 million at December 31, 2004. Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. The collection of receivables has been timely, and associated losses historically have not being significant.
In October 2002, we closed on a three-year $400 million Senior Secured Revolving Credit Facility. The Facility had a borrowing base of $275 million and we elected a $200 million commitment amount. The borrowing base was subject to re-determination each April and October. Borrowings under this Facility bore interest at a LIBOR rate plus 1.25 percent to 2.00 percent, based on borrowing base usage. Unused borrowings were subject to a commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage. The Credit Facility was secured by mortgages on our oil and gas properties and the stock of our subsidiaries. We were also subject to customary financial and
34
non-financial covenants. We are in compliance with all such covenants. There were no borrowings under the Facility at December 31, 2004 and 2003. On October 1, 2004 the Facility was amended. The amendment maintains a $200 million commitment amount; however it increases the borrowing base from $275 million to $300 million. The amendment also extends the term to October 2009 and does not require any additional mortgages unless outstanding borrowings exceed 50 percent of the borrowing base. Borrowings under the amended facility bear interest at a LIBOR rate plus 1.125 percent to 1.75 percent, based on borrowing base usage. Unused borrowings under the amendment are subject to a commitment fee of 0.25 percent to 0.50 percent, also depending on borrowing base usage. Because we have no publicly-traded debt, we have not sought a corporate credit rating.
At December 31, 2004, we had contractual obligations and material commitments as follows:
|
|
|
Payments Due by Period |
|
|||||||||||||
|
Contractual obligations |
|
Total |
|
Less than |
|
1-3 |
|
3-5 |
|
More than |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Operating leases |
|
$ |
18,629 |
|
$ |
2,465 |
|
$ |
4,745 |
|
$ |
4,696 |
|
$ |
6,723 |
|
|
Drilling commitments |
|
18,088 |
|
18,088 |
|
— |
|
— |
|
— |
|
|||||
|
Asset retirement obligation |
|
19,762 |
|
2,560 |
|
2,611 |
|
2,038 |
|
12,553 |
|
|||||
|
Other liabilities |
|
2,886 |
|
— |
|
306 |
|
102 |
|
2,478 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Total obligations |
|
$ |
59,365 |
|
$ |
23,113 |
|
$ |
7,662 |
|
$ |
6,836 |
|
$ |
21,754 |
|
We have guaranteed delivery of 15.4 Bcf of natural gas from 22 wells over a rolling three-year period as reimbursement for connection costs to a pipeline. If the minimum delivery is not met, our maximum exposure is approximately $1.0 million. We have also agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well for 27 wells. The maximum amount that would be payable, if no gas is delivered, would be approximately $1.1 million.
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 line of credit, will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.
Our projected 2005 exploration and development expenditure program of $350-$375 million will require a great deal of coordination and effort. Though there are a variety of factors that could curtail, delay or even cancel some of our drilling operations, we believe our projected program has a high degree of occurrence. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.
Costs of operations on a per Mcfe basis for 2005 are estimated to approximate levels realized in 2004. Should factors beyond our control fluctuate, our program and realized costs will vary from current projections. These factors could include volatility in commodity prices, changes in the supply of and demand for oil and gas, weather conditions, governmental regulations and more.
Estimates of production levels for 2005 range between 235 to 245 MMcfe per day. The revenues to be realized from the sale of this production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized from the sales. During 2004, the average price
35
realized from our gas sales was $5.76 per Mcf and $40.19 per barrel from our oil sales. Current indications are that anticipated prices for 2005 should approximate 2004 levels. Prices can be highly volatile, however, and the possibility of realized prices for 2005 to vary from current estimates is high.
Our results of operations are highly dependent upon the prices we receive for oil and gas production, and those prices are constantly changing in response to market forces. Nearly all of our revenue is from the sale of oil and gas, so these fluctuations, positive and negative, can have a significant impact on our results of operations and cash flows.
Oil and gas price realizations for 2004 ranged from a monthly low of $4.86 per Mcf and $32.71 per barrel, to a monthly high of $7.12 per Mcf and $50.35 per barrel, respectively. It is impossible to predict future oil and gas prices with any degree of certainty.
If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements. To date, we have not used any of these financial instruments to mitigate commodity price changes.
Any sustained weakness in prices may affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities and could cause us to record a reduction in the carrying value of our oil and gas properties.
Cimarex may be exposed to risk resulting from changes in interest rates as a result of our variable-rate bank credit facility. However, because we presently have no debt outstanding, the potential effect changes in interest rates would have no effect on our results of operations.
36
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.
37
Report of Independent Registered Public Accounting Firm
The Board of Directors
Cimarex Energy Co.:
We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the three year period ended December 31, 2004. 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission, and our report dated March 11, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
As discussed in Note 5 to the Consolidated Financial Statements, the Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.
KPMG LLP
Denver,
Colorado
March 11, 2005
38
CIMAREX ENERGY CO.
(In thousands, except share and per share information)
|
|
|
December 31, |
|
||||
|
|
|
2004 |
|
2003 |
|
||
|
Assets |
|
|
|
|
|
||
|
Current assets: |
|
|
|
|
|
||
|
Cash and cash equivalents |
|
$ |
115,746 |
|
$ |
40,420 |
|
|
Accounts receivable: |
|
|
|
|
|
||
|
Trade, net of allowance |
|
22,465 |
|
15,847 |
|
||
|
Oil and gas sales, net of allowance |
|
29,127 |
|
21,350 |
|
||
|
Marketing, net of allowance |
|
52,397 |
|
31,096 |
|
||
|
Inventories |
|
9,742 |
|
6,700 |
|
||
|
Deferred income taxes |
|
2,149 |
|
1,631 |
|
||
|
Other current assets |
|
4,821 |
|
6,160 |
|
||
|
Total current assets |
|
236,447 |
|
123,204 |
|
||
|
Oil and gas properties at cost, using the full cost method of accounting: |
|
|
|
|
|
||
|
Proved properties |
|
1,596,704 |
|
1,331,095 |
|
||
|
Unproved properties and properties under development, not being amortized |
|
72,249 |
|
39,370 |
|
||
|
|
|
1,668,953 |
|
1,370,465 |
|
||
|
Less - accumulated depreciation, depletion and amortization |
|
(866,660 |
) |
(746,161 |
) |
||
|
Net oil and gas properties |
|
802,293 |
|
624,304 |
|
||
|
Fixed assets, less accumulated depreciation of $8,795 and $6,422 |
|
16,109 |
|
12,092 |
|
||
|
Goodwill |
|
44,967 |
|
44,967 |
|
||
|
Other assets, net |
|
5,630 |
|
941 |
|
||
|
|
|
$ |
1,105,446 |
|
$ |
805,508 |
|
|
Liabilities and Stockholders’ Equity |
|
|
|
|
|
||
|
Current liabilities: |
|
|
|
|
|
||
|
Accounts payable: |
|
|
|
|
|
||
|
Trade |
|
$ |
12,430 |
|
$ |
11,146 |
|
|
Marketing |
|
14,081 |
|
7,248 |
|
||
|
Accrued liabilities: |
|
|
|
|
|
||
|
Exploration and development |
|
31,604 |
|
16,964 |
|
||
|
Taxes other than income |
|
12,702 |
|
6,362 |
|
||
|
Other |
|
33,056 |
|
25,013 |
|
||
|
Revenue payable |
|
39,129 |
|
18,776 |
|
||
|
Total current liabilities |
|
143,002 |
|
85,509 |
|
||
|
Deferred income taxes |
|
225,285 |
|
155,293 |
|
||
|
Asset retirement obligation |
|
17,202 |
|
16,463 |
|
||
|
Deferred compensation |
|
14,683 |
|
11,724 |
|
||
|
Other liabilities |
|
4,562 |
|
1,779 |
|
||
|
Total liabilities |
|
404,734 |
|
270,768 |
|
||
|
Commitments and contingencies |
|
|
|
|
|
||
|
Stockholders’ equity: |
|
|
|
|
|
||
|
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued |
|
— |
|
— |
|
||
|
Common stock, $0.01 par value, 100,000,000 shares authorized, 41,729,280 and 41,063,653 shares issued and outstanding, respectively |
|
417 |
|
411 |
|
||
|
Paid-in capital |
|
250,248 |
|
237,430 |
|
||
|
Unearned compensation |
|
(10,072 |
) |
(9,540 |
) |
||
|
Retained earnings |
|
460,031 |
|
306,439 |
|
||
|
Accumulated other comprehensive income |
|
88 |
|
— |
|
||
|
|
|
700,712 |
|
534,740 |
|
||
|
|
|
$ |
1,105,446 |
|
$ |
805,508 |
|
The accompanying notes are an integral part of these consolidated financial statements.
39
CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
|
|
|
For the Years Ended |
|
|||||||
|
|
|
December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Revenues: |
|
|
|
|
|
|
|
|||
|
Gas sales |
|
$ |
366,260 |
|
$ |
250,764 |
|
$ |
128,060 |
|
|
Oil sales |
|
106,129 |
|
73,355 |
|
29,239 |
|
|||
|
Marketing sales |
|
195,816 |
|
130,156 |
|
52,350 |
|
|||
|
Other, net |
|
6,724 |
|
(63 |
) |
(5 |
) |
|||
|
|
|
674,929 |
|
454,212 |
|
209,644 |
|
|||
|
Costs and expenses: |
|
|
|
|
|
|
|
|||
|
Depreciation, depletion and amortization |
|
124,251 |
|
88,774 |
|
49,231 |
|
|||
|
Asset retirement obligation accretion |
|
1,241 |
|
1,009 |
|
— |
|
|||
|
Transportation |
|
10,003 |
|
7,472 |
|
7,918 |
|
|||
|
Production |
|
37,476 |
|
31,801 |
|
19,427 |
|
|||
|
Taxes other than income |
|
37,761 |
|
27,485 |
|
13,154 |
|
|||
|
Marketing purchases |
|
193,325 |
|
129,503 |
|
49,671 |
|
|||
|
General and administrative |
|
22,483 |
|
17,526 |
|
8,568 |
|
|||
|
Stock compensation |
|
1,957 |
|
1,824 |
|
125 |
|
|||
|
Financing costs: |
|
|
|
|
|
|
|
|||
|
Interest expense |
|
1,075 |
|
1,285 |
|
620 |
|
|||
|
Capitalized interest |
|
— |
|
(304 |
) |
(206 |
) |
|||
|
Interest income |
|
(961 |
) |
(332 |
) |
(243 |
) |
|||
|
|
|
428,611 |
|
306,043 |
|
148,265 |
|
|||
|
Income before income tax expense and cumulative effect of a change in accounting principle |
|
246,318 |
|
148,169 |
|
61,379 |
|
|||
|
Income tax expense |
|
92,726 |
|
55,141 |
|
21,560 |
|
|||
|
Income before cumulative effect of a change in accounting principle |
|
153,592 |
|
93,028 |
|
39,819 |
|
|||
|
Cumulative effect of a change in accounting principle, net of tax |
|
— |
|
1,605 |
|
— |
|
|||
|
Net income |
|
$ |
153,592 |
|
$ |
94,633 |
|
$ |
39,819 |
|
|
Earnings per share: |
|
|
|
|
|
|
|
|||
|
Basic: |
|
|
|
|
|
|
|
|||
|
Income before cumulative effect of a change in accounting principle |
|
$ |
3.70 |
|
$ |
2.24 |
|
$ |
1.32 |
|
|
Cumulative effect of a change in accounting principle, net of tax |
|
— |
|
0.04 |
|
— |
|
|||
|
Net income |
|
$ |
3.70 |
|
$ |
2.28 |
|
$ |
1.32 |
|
|
Diluted: |
|
|
|
|
|
|
|
|||
|
Income before cumulative effect of a change in accounting principle |
|
3.59 |
|
$ |
2.18 |
|
$ |
1.31 |
|
|
|
Cumulative effect of a change in accounting principle, net of tax |
|
— |
|
0.04 |
|
— |
|
|||
|
Net income |
|
$ |
3.59 |
|
$ |
2.22 |
|
$ |
1.31 |
|
|
|
|
|
|
|
|
|
|
|||
|
Weighted average shares outstanding: |
|
|
|
|
|
|
|
|||
|
Basic |
|
41,466 |
|
41,521 |
|
30,239 |
|
|||
|
Diluted |
|
42,763 |
|
42,640 |
|
30,317 |
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
40
CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
Years Ended |
|
|||||||
|
|
|
December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|||
|
Net income |
|
$ |
153,592 |
|
$ |
94,633 |
|
$ |
39,819 |
|
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|||
|
Depreciation, depletion and amortization |
|
124,251 |
|
88,774 |
|
49,231 |
|
|||
|
Amortization of restricted stock compensation |
|
1,957 |
|
1,914 |
|
125 |
|
|||
|
Cumulative effect of a change in accounting principle, net of taxes |
|
— |
|
(1,605 |
) |
— |
|
|||
|
Deferred income taxes |
|
66,849 |
|
30,590 |
|
21,428 |
|
|||
|
Asset retirement obligation accretion |
|
1,241 |
|
1,009 |
|
— |
|
|||
|
Income tax benefit related to stock options exercised |
|
4,805 |
|
1,203 |
|
— |
|
|||
|
Other |
|
798 |
|
433 |
|
58 |
|
|||
|
Change in operating assets and liabilities: |
|
|
|
|
|
|
|
|||
|
(Increase) in receivables, net |
|
(35,696 |
) |
(10,123 |
) |
(15,996 |
) |
|||
|
(Increase) decrease in inventories |
|
(3,042 |
) |
(2,714 |
) |
1,770 |
|
|||
|
(Increase) decrease in other current assets |
|
1,339 |
|
(3,242 |
) |
(934 |
) |
|||
|
Increase (decrease) in accounts payable |
|
28,470 |
|
(9,310 |
) |
17,010 |
|
|||
|
Increase (decrease) in accrued liabilities |
|
14,448 |
|
15,626 |
|
(8,321 |
) |
|||
|
Increase (decrease) in other noncurrent liabilities |
|
1,646 |
|
(875 |
) |
265 |
|
|||
|
Net cash provided by operating activities |
|
360,658 |
|
206,313 |
|
104,455 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|||
|
Oil and gas expenditures |
|
(281,407 |
) |
(150,501 |
) |
(66,458 |
) |
|||
|
Acquisition of oil and gas properties |
|
(324 |
) |
(2,032 |
) |
— |
|
|||
|
Merger costs |
|
— |
|
— |
|
(5,079 |
) |
|||
|
Cash received in connection with acquisition |
|
— |
|
— |
|
2,135 |
|
|||
|
Proceeds from sale of assets |
|
926 |
|
1,041 |
|
313 |
|
|||
|
Other expenditures |
|
(12,296 |
) |
(8,149 |
) |
(2,596 |
) |
|||
|
Net cash used by investing activities |
|
(293,101 |
) |
(159,641 |
) |
(71,685 |
) |
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|||
|
Long-term borrowings |
|
— |
|
— |
|
41,016 |
|
|||
|
Payments on long-term debt |
|
— |
|
(32,000 |
) |
(45,016 |
) |
|||
|
Financing costs incurred |
|
— |
|
— |
|
(927 |
) |
|||
|
Common stock reacquired and retired |
|
(1,254 |
) |
(8 |
) |
— |
|
|||
|
Change in amount due (to) from Helmerich & Payne, Inc. |
|
|
|
— |
|
(13,089 |
) |
|||
|
Proceeds from issuance of common stock |
|
9,023 |
|
3,429 |
|
403 |
|
|||
|
Net cash provided by (used in) financing activities |
|
7,769 |
|
(28,579 |
) |
(17,613 |
) |
|||
|
Net increase in cash and cash equivalents |
|
75,326 |
|
18,093 |
|
15,157 |
|
|||
|
Cash and cash equivalents at beginning of period |
|
40,420 |
|
22,327 |
|
7,170 |
|
|||
|
Cash and cash equivalents at end of period |
|
$ |
115,746 |
|
$ |
40,420 |
|
$ |
22,327 |
|
The accompanying notes are an integral part of these consolidated financial statements.
41
CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
|
|
|
|
|
Paid-in |
|
Unearned |
|
Retained |
|
Accumulated
Other |
|
Total |
|
||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
|
|
Shares |
|
Amount |
|
|
|
|
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Balance December 31, 2001 |
|
26,591 |
|
$ |
266 |
|
$ |
— |
|
$ |
— |
|
$ |
174,816 |
|
$ |
— |
|
$ |
175,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Net income |
|
— |
|
— |
|
— |
|
— |
|
39,819 |
|
— |
|
39,819 |
|
||||||
|
Issuance of restricted stock awards in conjuction with the Cimarex spinoff |
|
38 |
|
— |
|
— |
|
(156 |
) |
156 |
|
— |
|
— |
|
||||||
|
Common stock issued for the acquisition of Key Production Company, Inc. |
|
14,079 |
|
141 |
|
232,212 |
|
(159 |
) |
— |
|
— |
|
232,194 |
|
||||||
|
Net distributions to Helmerich & Payne, Inc. |
|
— |
|
— |
|
— |
|
— |
|
(2,931 |
) |
— |
|
(2,931 |
) |
||||||
|
Issuance of restricted stock awards |
|
644 |
|
6 |
|
10,721 |
|
(10,727 |
) |
— |
|
— |
|
— |
|
||||||
|
Common stock reacquired and retired |
|
(13 |
) |
— |
|
(197 |
) |
— |
|
— |
|
— |
|
(197 |
) |
||||||
|
Amortization of unearned compensation |
|
— |
|
— |
|
— |
|
228 |
|
— |
|
— |
|
228 |
|
||||||
|
Exercise of stock options, net of tax benefit of $282 recorded in paid-in capital |
|
71 |
|
1 |
|
684 |
|
— |
|
— |
|
— |
|
685 |
|
||||||
|
Balance, December 31, 2002 |
|
41,410 |
|
414 |
|
243,420 |
|
(10,814 |
) |
211,860 |
|
— |
|
444,880 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Net income |
|
— |
|
— |
|
— |
|
— |
|
94,633 |
|
— |
|
94,633 |
|
||||||
|
Issuance of restricted stock awards |
|
65 |
|
1 |
|
1,348 |
|
(1,349 |
) |
— |
|
— |
|
— |
|
||||||
|
Common stock reacquired and retired |
|
— |
|
— |
|
(8 |
) |
— |
|
— |
|
— |
|
(8 |
) |
||||||
|
Amortization of unearned compensation |
|
— |
|
— |
|
— |
|
2,394 |
|
— |
|
— |
|
2,394 |
|
||||||
|
Exercise of stock options, net of tax benefit of $1,203 recorded in paid-in capital |
|
295 |
|
3 |
|
4,695 |
|
— |
|
— |
|
— |
|
4,698 |
|
||||||
|
Net distribution to Helmerich & Payne, Inc. |
|
— |
|
— |
|
— |
|
— |
|
(54 |
) |
— |
|
(54 |
) |
||||||
|
Restricted stock forfeited and retired |
|
(17 |
) |
— |
|
(308 |
) |
229 |
|
— |
|
— |
|
(79 |
) |
||||||
|
Shares of restricted stock exchanged for restricted stock units |
|
(689 |
) |
(7 |
) |
(11,717 |
) |
— |
|
— |
|
— |
|
(11,724 |
) |
||||||
|
Balance, December 31, 2003 |
|
41,064 |
|
411 |
|
237,430 |
|
(9,540 |
) |
306,439 |
|
— |
|
534,740 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Net income |
|
— |
|
— |
|
— |
|
— |
|
153,592 |
|
— |
|
153,592 |
|
||||||
|
Issuance of restricted stock awards |
|
15 |
|
— |
|
400 |
|
(400 |
) |
— |
|
— |
|
— |
|
||||||
|
Issuance of restricted stock unit awards |
|
— |
|
— |
|
— |
|
(2,809 |
) |
— |
|
— |
|
(2,809 |
) |
||||||
|
Common stock reacquired and retired |
|
(35 |
) |
— |
|
(1,254 |
) |
— |
|
— |
|
— |
|
(1,254 |
) |
||||||
|
Amortization of unearned compensation |
|
— |
|
— |
|
— |
|
2,677 |
|
— |
|
— |
|
2,677 |
|
||||||
|
Exercise of stock options, net of tax benefit of $4,805 recorded in paid-in capital |
|
691 |
|
6 |
|
13,822 |
|
— |
|
— |
|
— |
|
13,828 |
|
||||||
|
Shares of restricted stock exchanged for restricted stock units |
|
(6 |
) |
— |
|
(150 |
) |
— |
|
— |
|
— |
|
(150 |
) |
||||||
|
Net unrealized gains on marketable sercurities of investments |
|
|
|
|
|
|
|
|
|
|
|
88 |
|
88 |
|
||||||
|
Balance, December 31, 2004 |
|
41,729 |
|
$ |
417 |
|
$ |
250,248 |
|
$ |
(10,072 |
) |
$ |
460,031 |
|
$ |
88 |
|
$ |
700,712 |
|
The accompanying notes are an integral part of these consolidated financial statements.
42
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cimarex Energy Co. (Cimarex or the Company) was formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas exploration and production operations and the common stock of Cimarex Energy Services, Inc. (CESI), which is involved in natural gas marketing, to Cimarex. As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of 26,591,321 shares of Cimarex common stock, Cimarex was spun off and became a stand-alone Company. All par value, common stock and per share amounts have been retroactively restated in the accompanying consolidated financial statements to reflect the spin off.
Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. Cimarex issued one share of its common stock for each of the 14,079,243 shares of Key common stock outstanding as of that date. The acquisition of Key has been accounted for using the purchase method of accounting. The acquisition of Key is reflected in the accompanying balance sheets and in the results of operations and cash flows for the periods subsequent to the acquisition on September 30, 2002.
On September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31, effective January 1, 2002.
The accounts of Cimarex and its subsidiaries are presented in the accompanying consolidated financial statements. All intercompany accounts and transactions were eliminated in consolidation.
We make certain estimates and assumptions to prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period and in disclosures of commitments and contingencies. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.
The more significant areas requiring the use of management’s estimates and judgments relate to preparation of estimated oil and gas reserves, the use of these oil and gas reserves in calculating depletion, depreciation and amortization, the use of the estimates of future net revenues in computing the ceiling test limitations and estimates of abandonment obligations used in such calculations and in recording asset retirement obligations. Estimates and judgments are also required in determining the reserves for bad debts, the impairments of undeveloped properties, the assessment of goodwill and the valuation of deferred tax assets.
Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to the current year presentation.
43
Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value.
Inventories, primarily materials and supplies, are valued at the lower of cost or market.
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, the fair value of estimated future costs of site restoration, dismantlement and abandonment 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.
We perform an impairment analysis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Cash flows used in this impairment analysis are determined based upon estimates of proved oil and gas reserves, future prices, and the costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying amounts of our properties. Under full cost accounting rules, capitalized costs, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued in the full cost pool, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value discounted at 10 percent of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. If capitalized costs exceed this limit, the excess must be charged to expense. This is referred to as the “full cost ceiling limitation.” The expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. At the end of each quarter, a full cost ceiling limitation calculation is made.
Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a monthly and quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.
Proceeds from the sale of oil and gas properties are credited against capitalized costs, unless such proceeds would significantly alter the amortization base. Expenditures for maintenance and repairs are charged to production expense in the period incurred.
Cimarex recorded goodwill in conjunction with the purchase of Key on September 30, 2002. Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets, states that goodwill and other intangibles determined to have an infinite life are no longer amortized.
44
However, it requires that we review these assets for impairment at least once a year. We would also conduct a review, if circumstances indicated that impairment may have occurred. The evaluation of the estimated fair value of the goodwill is performed on individual reporting units. The exploration and production segment is considered the only reporting unit to which goodwill has been assigned.
Cimarex uses the estimated fair value approach to value its goodwill. This approach involves evaluating the estimated fair value of the reporting unit, compared to its carrying amount including goodwill. The estimated fair value of our exploration and production segment is based on numerous factors. Each is individually weighted to estimate fair value of the total reporting unit. If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill is not impaired. If the carrying amount of a reporting unit exceeds its estimated fair value, then a measurement of any impairment loss must be performed. Measuring any indicated impairment is done by comparing the implied fair value of the reporting unit goodwill with the carrying amount of that goodwill. Any deficiency is recorded as an impairment. The impairment cannot exceed the carrying amount. As no deferred taxes have been established for goodwill, any impairment would not be subject to a deferred tax benefit in the income tax provision. Subsequent reversal of a previous goodwill impairment loss is not allowed.
Cimarex recognizes revenues from oil and gas sales based on actual volumes of oil and gas sold to purchasers.
We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. As of December 31, 2004 and 2003, Cimarex had reduced reserves by 504 MMcf and 465 MMcf, respectively for gas imbalances. In situations where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2004 and 2003 was $1.5 million and $1.4 million, respectively.
Cimarex accounts for transportation costs under Emerging Issues Task Force (“EITF”) 00-10 Accounting for Shipping and Handling Fees and Costs. Amounts paid for transportation are classified as an operating expense and not netted against gas sales.
Income Taxes
Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized.
Prior to the spin off of Cimarex from H&P on September 30, 2002, Cimarex’s operating results historically had been included in consolidated federal and state income tax returns filed by H&P. A tax sharing agreement exists between Cimarex and H&P to allocate and settle among them the consolidated tax liability on a shared company basis through September 30, 2002. The allocation was finalized and settled in 2003 with a non-cash distribution to H&P of $0.1 million.
45
We apply Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations, to account for grants of stock options, restricted stock, and restricted stock units. No compensation cost has been recognized for grants of stock options, because on the date of grant, the option prices were the same as the market price of the underlying common stock. Compensation expense related to the issuance of restricted stock and restricted stock units is proportionately recognized over the vesting period of the related shares of stock or unit.
SFAS No. 123, Accounting for Stock Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, requires us to provide pro forma information regarding net income as if the compensation cost for stock options had been determined in accordance with the fair value based method prescribed in SFAS No. 123. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. To provide the required pro forma information, we estimate the theoretical fair value of each stock option at the grant date by using the Black-Scholes option-pricing model.
Had compensation cost for stock options been determined based on the fair value at the grant dates for awards to employees under the plan, consistent with the methodology of SFAS No. 123, pro forma net income would have been as indicated below for calendar 2004, 2003 and 2002 (in thousands except per share amounts).
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net income, as reported |
|
$ |
153,592 |
|
$ |
94,633 |
|
$ |
39,819 |
|
|
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
|
2,121 |
|
2,352 |
|
1,328 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Pro forma net income |
|
$ |
151,471 |
|
$ |
92,281 |
|
$ |
38,491 |
|
|
|
|
|
|
|
|
|
|
|||
|
Earnings per share: |
|
|
|
|
|
|
|
|||
|
Basic – as reported |
|
$ |
3.70 |
|
$ |
2.28 |
|
$ |
1.32 |
|
|
Basic – pro forma |
|
$ |
3.65 |
|
$ |
2.22 |
|
$ |
1.27 |
|
|
|
|
|
|
|
|
|
|
|||
|
Diluted – as reported |
|
$ |
3.59 |
|
$ |
2.22 |
|
$ |
1.31 |
|
|
Diluted – pro forma |
|
$ |
3.54 |
|
$ |
2.16 |
|
$ |
1.27 |
|
As required by SFAS No. 123 and amended by SFAS No. 148, the above pro forma data reflects the effect of stock option grants to employees of Cimarex beginning with H&P options issued in 1997. These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years.
The weighted-average fair values of the Cimarex and H&P stock options granted to employees of Cimarex (adjusted for the spin off conversion ratio) at their grant date during calendar 2004, 2003 and
46
2002 were $12.24, $7.64 and $8.16, respectively. The estimated theoretical fair value of each option granted is calculated using the Black-Scholes option-pricing model. The following summarizes the weighted-average assumptions used in the model:
|
|
|
Years Ended December 31, |
|
||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|
Expected years until exercise |
|
7.5 |
|
7.5 |
|
7.5 |
|
|
Expected stock volatility |
|
25.4 |
% |
26.7 |
% |
38.9 |
% |
|
Dividend yield |
|
0.0 |
% |
0.0 |
% |
0.0 |
% |
|
Risk-free interest rate |
|
3.4 |
% |
3.2 |
% |
3.8 |
% |
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, requiring companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation to employees for fiscal periods after June 15, 2005. This Statement amends SFAS No. 123. The Company anticipates it will adopt the provision of SFAS 123R in the first quarter of 2005 and that the impact, based on outstanding options at December 31, 2004, will result in future charges to compensation expense similar to the pro forma amounts reflected above.
Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares.
The carrying amounts of our cash, accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2004, the allowance for doubtful accounts for trade, oil and gas sales, and marketing receivables was $0.4 million, $0.2 million and $0.7 million, respectively. At December 31, 2003, the allowance for doubtful accounts for trade, oil and gas sales and marketing receivables was $0.2 million, $0.4 million and $0.7 million, respectively.
Cimarex applies the provisions of SFAS No. 130, Reporting Comprehensive Income. Cimarex reported other comprehensive income in 2004 of $88 thousand related to the change in fair value of Marketable securities available for sale. We had no comprehensive income in 2003 or 2002.
On September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key in a tax-free exchange pursuant to which Key became a wholly owned subsidiary of Cimarex. The acquisition of Key was accounted for using the purchase method of accounting.
Our consolidated balance sheets include the assets and liabilities of Key as well as the adjustments required to record the acquisition in accordance with the purchase method of accounting. The final purchase price and the final allocation of the purchase price were finalized at September 30, 2003 based on the actual fair value of current assets and liabilities, and long-term liabilities. The results
47
of operations of Key are included in our consolidated statements of operations for the period since the acquisition on September 30, 2002. The following unaudited pro forma financial information presents the combined results of Cimarex and Key, and was prepared as if the acquisition had occurred at the beginning of the periods presented. The unaudited pro forma data presented is based on numerous assumptions and is not necessarily indicative of actual results of operations, had the companies been operating as one. The unaudited pro forma results of operations for the year ended September 30, 2001 includes Key’s results of operations for the year ended December 31, 2001. Included in the pro forma results for the year ended December 31, 2002 is $11.0 million of merger related and severance expenses incurred by Key.
|
|
|
Years Ended |
|
Three Months |
|
|||||
|
|
|
December 31, |
|
September 30, |
|
December 31, |
|
|||
|
|
|
(In thousands, except per share amounts) |
|
|||||||
|
|
|
|
|
|
|
|
|
|||
|
Total revenues |
|
$ |
267,935 |
|
$ |
425,663 |
|
$ |
57,493 |
|
|
|
|
|
|
|
|
|
|
|||
|
Net income (loss) |
|
34,474 |
|
(6,595 |
) |
3,395 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Diluted earnings (loss) per share |
|
0.84 |
|
(0.16 |
) |
0.08 |
|
|||
On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability upon acquiring or drilling a well.
The adoption of the Statement resulted in recording an increase to the full cost pool of approximately $10.4 million, a decrease to accumulated depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term liabilities for plugging and abandonment costs of approximately $13.8 million, an increase to the deferred tax liability of approximately $0.9 million and income reported as a cumulative effect of a change in accounting principle of approximately $1.6 million, net of income taxes of $1.0 million. On a pro forma basis, the asset retirement obligation would have been approximately $12.6 million as of January 1, 2002.
48
The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2004 and 2003 (in thousands):
|
|
|
2004 |
|
2003 |
|
||
|
Asset retirement obligation at January 1 |
|
$ |
16,463 |
|
$ |
13,784 |
|
|
Liabilities incurred in the current period |
|
2,427 |
|
1,929 |
|
||
|
Liabilities settled in the current period |
|
(348 |
) |
(259 |
) |
||
|
Accretion expense |
|
1,220 |
|
1,009 |
|
||
|
|
|
|
|
|
|
||
|
Asset retirement obligation at December 31 |
|
19,762 |
|
16,463 |
|
||
|
Less: Current asset retirement obligation |
|
2,560 |
|
— |
|
||
|
Longterm asset retirement obligation |
|
$ |
17,202 |
|
$ |
16,463 |
|
The following table shows the pro forma effect on the Company’s net income and earnings per share, had SFAS No. 143 been applied during the year ended December 31, 2002 (in thousands):
|
Net income: |
|
|
|
|
|
As reported |
|
$ |
39,819 |
|
|
Pro forma |
|
$ |
39,236 |
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
As reported |
|
$ |
1.32 |
|
|
Pro forma |
|
$ |
1.30 |
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
As reported |
|
$ |
1.31 |
|
|
Pro forma |
|
$ |
1.29 |
|
In October 2002, we closed on a three-year $400 million Senior Secured Revolving Credit Facility. The Facility had a borrowing base of $275 million and we elected a $200 million commitment amount. The borrowing base was subject to re-determination each April and October. Borrowings under this Facility bore interest at a LIBOR rate plus 1.25 percent to 2.00 percent, based on borrowing base usage. Unused borrowings were subject to a commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage. The Credit Facility was secured by mortgages on our oil and gas properties and the stock of our subsidiaries. We were also subject to customary financial and non-financial covenants. We are in compliance with all such covenants. There were no borrowings under the Facility at December 31, 2004 and 2003.
On October 1, 2004 the Facility was amended with substantially the same terms. The amendment maintains a $200 million commitment amount; however it increases the borrowing base from $275 million to $300 million. The amendment also extends the term to October 2009 and does not require any additional mortgages unless outstanding borrowings exceed 50 percent of the borrowing base. Borrowings under the amended facility bear interest at a LIBOR rate plus 1.125 percent to 1.75 percent, based on borrowing base usage. Unused borrowings under the amendment are subject to a commitment
49
fee of 0.25 percent to 0.50 percent, also depending on borrowing base usage. Because we have no publicly-traded debt, we have not sought a corporate credit rating.
Federal income tax expense for the years ended December 31, 2004, 2003 and 2002 differ from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state income taxes, percentage depletion and deductible merger costs. The components of the provision for income taxes are as follows (in thousands):
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Current taxes: |
|
|
|
|
|
|
|
|||
|
Federal |
|
$ |
23,255 |
|
$ |
21,136 |
|
$ |
— |
|
|
State |
|
2,622 |
|
3,415 |
|
132 |
|
|||
|
|
|
25,877 |
|
24,551 |
|
132 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Deferred taxes: |
|
|
|
|
|
|
|
|||
|
Federal |
|
61,571 |
|
28,175 |
|
19,736 |
|
|||
|
State |
|
5,278 |
|
2,415 |
|
1,692 |
|
|||
|
|
|
66,849 |
|
30,590 |
|
21,428 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
|
|
$ |
92,726 |
|
$ |
55,141 |
|
$ |
21,560 |
|
Reconciliations of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense are as follows (in thousands):
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Provision at statutory rate |
|
$ |
86,212 |
|
$ |
51,859 |
|
$ |
21,482 |
|
|
Effect of state taxes |
|
6,472 |
|
3,254 |
|
1,841 |
|
|||
|
Non-conventional fuel source credits utilized |
|
— |
|
— |
|
(313 |
) |
|||
|
Excess statutory depletion |
|
— |
|
— |
|
(271 |
) |
|||
|
Deductible merger related costs |
|
— |
|
— |
|
(1,178 |
) |
|||
|
Other |
|
42 |
|
28 |
|
(1 |
) |
|||
|
Income tax expense |
|
$ |
92,726 |
|
$ |
55,141 |
|
$ |
21,560 |
|
50
The components of Cimarex’s net deferred tax liabilities are as follows (in thousands):
|
|
|
December 31, |
|
||||
|
|
|
2004 |
|
2003 |
|
||
|
Long-term: |
|
|
|
|
|
||
|
Assets: |
|
|
|
|
|
||
|
Net operating loss carryforwards |
|
$ |
1,743 |
|
$ |
3,921 |
|
|
Credit carryforwards |
|
1,207 |
|
1,207 |
|
||
|
Long-term assets and liabilities |
|
2,606 |
|
4,374 |
|
||
|
|
|
5,556 |
|
9,502 |
|
||
|
Liabilities: |
|
|
|
|
|
||
|
Property, plant and equipment |
|
(230,841 |
) |
(164,795 |
) |
||
|
Net, long-term deferred tax liability |
|
(225,285 |
) |
(155,293 |
) |
||
|
|
|
|
|
|
|
||
|
Current: |
|
|
|
|
|
||
|
Net current deferred tax assets |
|
2,149 |
|
1,631 |
|
||
|
Net deferred tax liabilities |
|
$ |
(223,136 |
) |
$ |
(153,662 |
) |
The company has a net tax operating loss (NOL) carryforward of approximately $4.5 million at December 31, 2004, which expires in 2021. The NOL carryforward was acquired as part of an acquisition, and therefore, is subject to annual limitations on its use. We believe that the carryforward will be utilized before it expires. The Company has an alternative minimum tax credit carryfoward of approximately $1.2 million at December 31, 2004.
We have recorded deferred tax assets of $7.7 million of which $1.7 million is attributable to the NOL carryforward. Realization is dependent on generating sufficient taxable income in the future. Although realization is not assured, we believe it is more likely than not all of the deferred tax assets will be realized.
Cimarex’s 2002 Stock Incentive Plan reserves seven million shares of common stock for issuance to directors and employees, including officers. Options granted under the plan after December 5, 2002, expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. All grants are made at the closing price of our common stock as reported on the New York Stock Exchange on the date of grant. Upon the exercise of the options for shares of common stock, the employee is required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date.
At the date of distribution on September 30, 2002, H&P stock options held by former H&P employees who became Cimarex employees were converted into Cimarex stock options exercisable for 1,630,269 shares of Cimarex common stock based on the intrinsic value at the date of the distribution. The weighted average exercise price for the new options was $13.24 per share. The tables below show the former H&P stock option activity through September 30, 2002, at which time these options were converted to Cimarex stock options. No accounting charge resulted from this exchange because the economic interest of option holders before and after the spin off was unchanged and the spin off from
51
H&P was for a fixed number of shares of Cimarex common stock. No activity associated with option exercises prior to September 30, 2002, is shown in the statements of stockholders’ equity.
On September 30, 2002, stock options for 785,501 shares of Key common stock held by former employees of Key were converted to Cimarex stock options on a one-for-one basis. These options vested upon closing of the merger. The weighted average exercise price for these options was $11.06 per share.
The following summary reflects the status of stock options granted to employees and directors as of December 31, 2004, and changes during the year:
|
|
|
Options |
|
Weighted |
|
Options |
|
|
|
|
|
|
|
|
|
|
|
|
|
H&P Activity: |
|
|
|
|
|
|
|
|
|
Outstanding as of December 31, 2001 |
|
858,398 |
|
$ |
27.56 |
|
355,897 |
|
|
Exercised |
|
(68,073 |
) |
20.70 |
|
|
|
|
|
Forfeited/Expired |
|
(23,500 |
) |
29.48 |
|
|
|
|
|
Outstanding on September 30, 2002, pre spin off |
|
766,825 |
|
28.15 |
|
|
|
|
|
Cimarex Activity: |
|
|
|
|
|
|
|
|
|
Incremental options issued for conversion to Cimarex stock options |
|
863,444 |
|
— |
|
|
|
|
|
Outstanding on September 30, 2002, post spin off |
|
1,630,269 |
|
13.24 |
|
|
|
|
|
Issued in Key acquisition |
|
785,501 |
|
11.06 |
|
|
|
|
|
Granted |
|
1,290,800 |
|
16.69 |
|
|
|
|
|
Exercised |
|
(71,294 |
) |
5.65 |
|
|
|
|
|
Forfeited/Expired |
|
(3,189 |
) |
14.01 |
|
|
|
|
|
Outstanding as of December 31, 2002 |
|
3,632,087 |
|
14.14 |
|
1,720,486 |
|
|
|
Granted |
|
24,000 |
|
20.36 |
|
|
|
|
|
Exercised |
|
(294,921 |
) |
11.59 |
|
|
|
|
|
Forfeited/Expired |
|
(39,867 |
) |
16.02 |
|
|
|
|
|
Outstanding as of December 31, 2003 |
|
3,321,299 |
|
14.39 |
|
1,992,360 |
|
|
|
Granted |
|
30,300 |
|
33.28 |
|
|
|
|
|
Exercised |
|
(691,327 |
) |
13.07 |
|
|
|
|
|
Forfeited/Expired |
|
(3,190 |
) |
14.41 |
|
|
|
|
|
Outstanding as of December 31,2004 |
|
2,657,082 |
|
$ |
14.95 |
|
1,773,755 |
|
52
The following table summarizes information about Cimarex stock options held by employees and directors at December 31, 2004:
|
|
|
Outstanding Stock Options |
|
Exercisable Stock Options |
|
||||||||
|
Range of Exercise Prices |
|
Options |
|
Weighted- |
|
Weighted- |
|
Options |
|
Weighted- |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
$6.59 |
|
7,104 |
|
0.9 Years |
|
$ |
6.59 |
|
7,104 |
|
$ |
6.59 |
|
|
$7.91 to $9.69 |
|
133,314 |
|
4.1 Years |
|
8.29 |
|
133,314 |
|
8.29 |
|
||
|
$11.38 to $12.26 |
|
464,460 |
|
3.1 Years |
|
11.51 |
|
464,460 |
|
11.51 |
|
||
|
$13.31 to $15.20 |
|
727,244 |
|
6.3 Years |
|
14.35 |
|
628,381 |
|
14.40 |
|
||
|
$16.65 to $18.77 |
|
1,270,660 |
|
7.8 Years |
|
16.75 |
|
535,696 |
|
16.86 |
|
||
|
$20.36 |
|
24,000 |
|
8.7 Years |
|
20.36 |
|
4,800 |
|
20.36 |
|
||
|
$33.28 |
|
30,300 |
|
9.7 Years |
|
33.28 |
|
— |
|
— |
|
||
We have a long-term incentive program whereby grants of restricted stock and/or units are awarded to certain employees. The restrictions related to these awards are associated with the continued employment of the grantee for one to five years from the date of the original grant, at which time these shares will vest. In addition there is a three year required holding period subsequent to vesting. The restricted stock and stock unit agreements provide that the grantees will be entitled to receive dividends, when, as and if declared. We do not currently intend to pay dividends on our common stock.
Cimarex awarded 65,000 restricted shares during 2003. On December 1, 2003, certain employees elected to exchange their restricted stock for restricted stock units (“Units”), in accordance with the provisions of the Stock Incentive Plan. As such, 688,600 restricted shares were cancelled and a like number of Units were issued. The Units issued have been recorded as long-term deferred compensation in an amount equal to the original value attributed to the restricted shares exchanged, with a corresponding adjustment to common stock and paid-in capital. Upon vesting, the Units are exchanged for a like number of shares of common stock and are issued to the employee.
There were 19,145 shares of restricted stock and 775,787 restricted stock units outstanding as of December 31, 2004. As of December 31, 2003 there were 29,087 shares of restricted stock and 688,600 restricted stock units outstanding.
Compensation expense for restricted shares or units is based upon the market price of the restricted stock multiplied by the number of shares of restricted stock or units granted. Compensation cost is being recognized over the associated vesting period. For the year ended December 31, 2004, 2003 and 2002, we recorded compensation expense of $2.7 million, net of $0.7 million capitalized to oil and gas properties; $1.8 million, net of $0.6 million capitalized; and $0.2 million, respectively.
Proposed Merger Between Cimarex and Magnum Hunter
The proposed merger will constitute a “change of control event” under the Cimarex incentive plan because of the number of shares of Cimarex common stock that will be issued to Magnum Hunter stockholders in the merger. As a result, all participants in the plan, including executive officers and directors, will be entitled to the acceleration of vesting of options and vesting and payment of restricted stock and restricted stock units and, in the case of directors, extension of the time to exercise options
53
following termination of service as a director. Cimarex is seeking agreements from certain executive officers and directors to waive acceleration of vesting and payment. As consideration for the waivers sought from F.H. Merelli, Thomas E. Jorden, Paul Korus, Joseph R. Albi, Stephen P. Bell and Richard S. Dinkins, Cimarex will agree to amend the unit and option agreements to provide that (1) if the restricted stock units are not redeemable when they vest, Cimarex will pay a participant holding a unit a cash bonus equal to the amount of Social Security taxes payable grossed up for taxes payable on the bonus, (2) if a participant holding a unit terminates employment on account of death or disability, vesting will be accelerated, and (3) if a participant holding an option terminates employment on account of death or disability, vesting will be accelerated. In consideration for the waivers sought from all other holders of restricted stock, restricted stock units and stock options, Cimarex will agree to amend the unit and option agreements as described in the preceding sentence and, in addition, will agree to grant, upon the closing of the merger, to participants holding units an additional grant of restricted stock units equal to 25% of the original grant, which will vest and become payable on the third anniversary of the closing of the merger. Cimarex may not be able to obtain the waivers from all of the executive officers or other employees. Cimarex has elected not to seek waivers from the directors holding options because the unexercisable options will fully vest by their terms on October 1, 2005 and only two directors (Messrs. Helmerich and Rooney) will receive an extension of the exercise period as a result of the change of control event.
With respect to the acceleration of vesting of options, holders who are not requested to or do not execute a waiver will have the right to exercise their options at and after closing until the option terminates in accordance with its terms. All restricted stock and restricted stock units held by those individuals will become payable at closing.
Cimarex anticipates adopting the provisions of Statement of Financial Accounting Standards (SFAS) No. 123R, Share-Based Payment, as of January 1, 2005. For those holders who do not execute waivers, related unearned compensation reflected in Cimarex’s stockholders’ equity would become fully amortized at closing. At December 31, 2004, total unearned compensation was approximately $10.1 million. For those holders who execute waivers, the waiver agreements will be accounted for as a modification of the original awards and Cimarex will record additional deferred compensation equal to the difference between the fair value of the original award and the fair value of the modified award. The incremental deferred compensation will be amortized over the remaining term of the awards. Cash bonuses resulting from Social Security taxes payable when the awards vest will be accrued as of the end of each reporting period after the closing of the merger, using the related period-end stock price. The additional 25% grant of units will be recorded at fair market value on the date of grant, as unearned compensation to be amortized over the vesting period of the award.
Cimarex has a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock of the Company. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15 percent or more of our common stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent dilution. The proposed merger between Cimarex and Magnum Hunter does not activate the provisions of the plan.
54
Cimarex generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time prior to the close of business on the tenth business day after there has been a public announcement of the acquisition of the beneficial ownership by any person or group of 15 percent or more of our common stock. The Rights may not be exercised until our board’s right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012.
The calculations of basic and diluted net earnings per common share for the years ended December 31, 2004, 2003 and 2002 are presented in the table below (in thousands, except per share data):
|
|
|
December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Basic earnings per share: |
|
|
|
|
|
|
|
|||
|
Income available to common stockholders |
|
$ |
153,592 |
|
$ |
94,633 |
|
$ |
39,819 |
|
|
Weighted average basic share outstanding |
|
41,466 |
|
41,521 |
|
30,239 |
|
|||
|
Basic earnings per share |
|
$ |
3.70 |
|
$ |
2.28 |
|
$ |
1.32 |
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|||
|
Income available to common stockholders |
|
$ |
153,592 |
|
$ |
94,633 |
|
$ |
39,819 |
|
|
Weighted average basic shares outstanding |
|
41,466 |
|
41,521 |
|
30,239 |
|
|||
|
Incremental shares assuming the exercise of stock options and vesting of restricted stock units |
|
1,297 |
|
1,119 |
|
78 |
|
|||
|
Weighted average diluted shares outstanding |
|
42,763 |
|
42,640 |
|
30,317 |
|
|||
|
Diluted earnings per share |
|
$ |
3.59 |
|
$ |
2.22 |
|
$ |
1.31 |
|
There were stock options outstanding for 2,657,082, 3,321,299 and 3,632,087 shares of Cimarex common stock at December 31, 2004, 2003 and 2002, respectively. The weighted average common shares for the diluted earnings per share calculation for the year ended December 31, 2002 excludes the incremental effect related to outstanding stock options exercisable for 1,516,401 shares of Cimarex common stock whose exercise price was in excess of the average price of Cimarex’s stock of $15.66 for the period the options were outstanding in 2002 and therefore were antidilutive
55
Cimarex maintains and sponsors contributory health care plans and a contributory 401(k) plan. Cimarex employees participate in these plans and costs related to these plans were $4.7 million, $3.8 million and $1.9 million in the years ended December 31, 2004, 2003 and 2002, respectively.
H&P provides contract drilling services to Cimarex through its wholly owned subsidiary, Helmerich & Payne International Drilling Company. Drilling costs of approximately $10.4 million, $4.6 million and $1.4 million were incurred by Cimarex related to such services for the years ended December 31, 2004, 2003 and 2002, respectively. Cimarex also reimbursed H&P an additional $0.6 million related to costs incurred by H&P on behalf of Cimarex for the Cimarex stand-alone Oklahoma tax return for the year ended September 30, 2002 and other miscellaneous payments. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of H&P. Additionally, in the years ended December 31, 2003 and 2002, non-cash distributions of $0.1 million, and $2.9 million, respectively, were made to H&P pursuant to the tax sharing agreement. No such distributions were required to be made in 2004.
No purchasers represented more than 10 percent of our revenues for the year ended December 31, 2004. During 2003, we sold oil and gas production to OGE Energy Resources, Inc. representing 10.3 percent of our revenues. For the year ended December 31, 2002, no purchasers represented more than 10 percent of our revenues.
Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.
Cimarex operates in the oil and gas industry, and is comprised of an exploration and production segment and a natural gas marketing segment. Exploration and production activities are located primarily in Oklahoma, Kansas, Texas, Louisiana and Wyoming. Information presented for our natural gas marketing segment represents business conducted with third parties, usually incidental to sales of our own production.
56
Summarized financial information of Cimarex’s reportable segments for the years ended December 31, 2004, 2003 and 2002 is shown in the following table (in thousands):
|
|
|
External |
|
Operating |
|
DD&A |
|
Total |
|
Additions |
|
|||||
|
Year ended December 31 2004: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Exploration and Production |
|
$ |
472,389 |
|
$ |
237,526 |
|
$ |
123,989 |
|
$ |
1,050,178 |
|
$ |
307,787 |
|
|
Natural Gas Marketing |
|
195,816 |
|
2,182 |
|
262 |
|
55,268 |
|
880 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Total |
|
$ |
668,205 |
|
$ |
239,708 |
|
$ |
124,251 |
|
$ |
1,105,446 |
|
$ |
308,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Year Ended December 31, 2003: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Exploration and Production |
|
$ |
324,119 |
|
$ |
148,474 |
|
$ |
88,560 |
|
$ |
773,041 |
|
$ |
169,844 |
|
|
Natural Gas Marketing |
|
130,156 |
|
407 |
|
214 |
|
32,467 |
|
241 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Total |
|
$ |
454,275 |
|
$ |
148,881 |
|
$ |
88,774 |
|
$ |
805,508 |
|
$ |
170,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Year Ended December 31, 2002: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Exploration and Production |
|
$ |
157,299 |
|
$ |
59,922 |
|
$ |
49,040 |
|
$ |
650,243 |
|
$ |
419,026 |
|
|
Natural Gas Marketing |
|
52,350 |
|
1,633 |
|
191 |
|
24,043 |
|
409 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Total |
|
$ |
209,649 |
|
$ |
61,555 |
|
$ |
49,231 |
|
$ |
674,286 |
|
$ |
419,435 |
|
The following table reconciles segment operating profit per the above table to income before taxes as reported on the consolidated statements of operations (in thousands).
|
|
|
Years Ended |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Segment operating
profit |
|
$ |
239,708 |
|
$ |
148,881 |
|
$ |
61,555 |
|
|
|
|
|
|
|
|
|
|
|||
|
Unallocated amounts: |
|
|
|
|
|
|
|
|||
|
Other revenue (expense) |
|
6,724 |
|
(63 |
) |
(5 |
) |
|||
|
Interest income |
|
961 |
|
332 |
|
243 |
|
|||
|
Interest expense |
|
(1075 |
) |
(981 |
) |
(414 |
) |
|||
|
|
|
$ |
246,318 |
|
$ |
148,169 |
|
$ |
61,379 |
|
57
|
|
|
For the Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Cash paid during the period for: |
|
|
|
|
|
|
|
|||
|
Interest (net of amounts capitalized) |
|
$ |
972 |
|
$ |
830 |
|
$ |
69 |
|
|
Income taxes (net of refunds received) |
|
$ |
20,932 |
|
$ |
21,382 |
|
$ |
14 |
|
In connection with the acquisition of Key in 2002 for $237.3 million, we acquired assets with a fair value of $367.5 million and assumed liabilities of $130.2 million. This acquisition was a non-cash transaction except for the cash and cash equivalents of $2.1 million received from Key as more fully described in Note 4.
Cimarex is a defendant to certain claims relating to drainage of gas from two properties that it operates. The royalty owner plaintiffs have filed suit on behalf of themselves and a class of allegedly similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was in an amount that significant. The plaintiffs have stated that the royalty owner class has sustained actual damages of approximately $20 million exclusive of interest and costs. We estimate that the share of such alleged damages attributable to our working interest ownership would total approximately $3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, should not exceed our working interest share of any actual damages attributable to the alleged drainage. In this regard, the court granted our request to assert third-party claims against all of the other working interest owners. Our contention is that the other working interest owners should bear responsibility for their respective pro rata shares of damages, if any. We cannot predict the outcome of this litigation, and accordingly, no accrual has been recorded in connection with this action.
Cimarex has other various litigation related matters in the normal course of business, none of which are material, individually or in aggregate. We are also party to certain litigation as plaintiffs that could result in potential gains. Net settlements of $3.4 million have been received during 2004 related to litigation for which we were plaintiffs. Such amounts were recorded as other income. Any future contingent gains are not considered significant.
Cimarex has noncancelable operating leases for office and parking space in Denver and Tulsa and for small district and field offices. Rental expense for the operating leases totaled $2.5 million, $2.1 million and $0.6 million for the years ended December 31, 2004, 2003 and 2002, respectively.
58
The following table summarizes the future minimum lease payments under all noncancelable operating lease obligations.
|
Year Ending December 31, |
|
Future Minimum |
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
2005 |
|
$ |
2,465 |
|
|
2006 |
|
2,411 |
|
|
|
2007 |
|
2,334 |
|
|
|
2008 |
|
2,361 |
|
|
|
2009 |
|
2,335 |
|
|
|
2010 and thereafter |
|
6,723 |
|
|
|
|
|
$ |
18,629 |
|
We have guaranteed delivery of 15.4 Bcf of natural gas from 22 wells over a rolling three-year period as reimbursement for connection costs to a pipeline. If the minimum delivery is not met, our maximum exposure is approximately $1.0 million. We have also agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well for 27 wells. The maximum amount that would be payable, if no gas is delivered, would be approximately $1.1 million.
The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2004 of approximately $18.1 million.
59
Oil and Gas Operations – The following tables contain direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income taxes related to our oil and gas operations are computed using the effective tax rate for the period.
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Oil and gas revenues from production |
|
$ |
472,389 |
|
$ |
324,119 |
|
$ |
157,299 |
|
|
Less operating costs and income taxes: |
|
|
|
|
|
|
|
|||
|
Depletion |
|
120,499 |
|
86,390 |
|
48,272 |
|
|||
|
Asset retirement obligation accretion |
|
1,241 |
|
1,009 |
|
— |
|
|||
|
Production |
|
37,476 |
|
31,801 |
|
19,427 |
|
|||
|
Transportation |
|
10,003 |
|
7,472 |
|
7,918 |
|
|||
|
Taxes other than income |
|
37,761 |
|
27,485 |
|
13,154 |
|
|||
|
Income taxes |
|
99,794 |
|
63,226 |
|
25,356 |
|
|||
|
|
|
306,774 |
|
217,383 |
|
114,127 |
|
|||
|
Results of operations from oil and gas producing activities |
|
$ |
165,615 |
|
$ |
106,736 |
|
$ |
43,172 |
|
|
Amortization rate per Mcfe |
|
$ |
1.52 |
|
$ |
1.32 |
|
$ |
1.00 |
|
Costs Incurred – The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities (in thousands).
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Costs incurred during the year: |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Acquisition of properties |
|
|
|
|
|
|
|
|||
|
Proved |
|
$ |
324 |
|
$ |
2,032 |
|
$ |
286,041 |
|
|
Unproved |
|
17,177 |
|
9,330 |
|
16,008 |
|
|||
|
Exploration |
|
57,370 |
|
50,170 |
|
29,135 |
|
|||
|
Development |
|
221,500 |
|
100,550 |
|
37,215 |
|
|||
|
Oil and gas expenditures |
|
296,371 |
|
162,082 |
|
368,399 |
|
|||
|
Property sales |
|
(662 |
) |
(694 |
) |
(151 |
) |
|||
|
Amortization of restricted stock |
|
720 |
|
545 |
|
104 |
|
|||
|
Asset retirement obligation, net |
|
2,059 |
|
12,103 |
|
— |
|
|||
|
|
|
$ |
298,488 |
|
$ |
174,036 |
|
$ |
368,352 |
|
60
Costs Not Being Amortized – The following table summarizes oil and gas property costs not being amortized at December 31, 2004, by year that the cost were incurred (in thousands):
|
2004 |
|
$ |
66,968 |
|
|
2003 |
|
2,844 |
|
|
|
2002 |
|
811 |
|
|
|
2001 and prior |
|
1,626 |
|
|
|
|
|
$ |
72,249 |
|
Costs not being amortized include the costs of wells in progress and certain unevaluated properties. On a monthly and quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.
Oil and Gas Reserve Information (Unaudited) – Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, has reviewed the proved reserve estimates associated with approximately 80 percent of the discounted future net cash flows before income taxes for the years ended December 31, 2004, 2003 and 2002.
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following reserve data at December 31, 2004, 2003 and 2002 represents estimates only and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico.
|
|
|
December 31, 2004 |
|
December 31, 2003 |
|
December 31, 2002 |
|
||||||
|
|
|
Gas |
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
Oil |
|
|
|
|
(MMcf) |
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves - Developed and undeveloped |
|
337,344 |
|
14,137 |
|
318,627 |
|
15,025 |
|
212,326 |
|
5,304 |
|
|
Beginning of year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates |
|
20,068 |
|
1,154 |
|
6,699 |
|
41 |
|
31,153 |
|
1,094 |
|
|
Extensions and discoveries |
|
70,748 |
|
1,443 |
|
61,545 |
|
1,625 |
|
21,064 |
|
643 |
|
|
Purchases of reserves |
|
134 |
|
2 |
|
1,320 |
|
43 |
|
95,388 |
|
9,155 |
|
|
Production |
|
(63,611 |
) |
(2,641 |
) |
(50,552 |
) |
(2,504 |
) |
(41,300 |
) |
(1,171 |
) |
|
Sales of properties |
|
(42 |
) |
(32 |
) |
(295 |
) |
(93 |
) |
(4 |
) |
— |
|
|
End of year |
|
364,641 |
|
14,063 |
|
337,344 |
|
14,137 |
|
318,627 |
|
15,025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves |
|
364,566 |
|
13,372 |
|
336,230 |
|
13,876 |
|
318,452 |
|
14,765 |
|
Standardized Measure of Future Net Cash Flows (Unaudited) – The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing Activities. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.
61
Under the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10 percent annual discount rate to arrive at the Standardized Measure.
The following summary sets forth the Company’s Standardized Measure (in thousands):
|
|
|
December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Cash inflows |
|
$ |
2,570,347 |
|
$ |
2,258,337 |
|
$ |
1,742,435 |
|
|
Production costs |
|
(658,658 |
) |
(562,124 |
) |
(511,168 |
) |
|||
|
Development costs |
|
(9,246 |
) |
(16,014 |
) |
(6,909 |
) |
|||
|
Income tax expense |
|
(641,485 |
) |
(554,746 |
) |
(361,423 |
) |
|||
|
Net cash flow |
|
1,260,958 |
|
1,125,453 |
|
862,935 |
|
|||
|
10% annual discount rate |
|
(462,925 |
) |
(413,872 |
) |
(329,076 |
) |
|||
|
Standardized measure of discounted future net cash flow |
|
$ |
798,033 |
|
$ |
711,581 |
|
$ |
533,859 |
|
|
Discounted future net cash flow before income taxes |
|
$ |
1,172,230 |
|
$ |
1,030,340 |
|
$ |
741,209 |
|
The following are the principal sources of change in the Standardized Measure (in thousands):
|
|
|
December 311, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Standardized measure, beginning of period |
|
$ |
711,581 |
|
$ |
533,859 |
|
$ |
182,565 |
|
|
Sales, net of production costs |
|
(387,150 |
) |
(257,362 |
) |
(116,801 |
) |
|||
|
Net change in sales prices, net of production costs |
|
45,614 |
|
202,135 |
|
200,935 |
|
|||
|
Extensions, discoveries, and improved recovery, net of future production and development costs |
|
313,417 |
|
266,128 |
|
62,648 |
|
|||
|
Net change in future development costs |
|
16,380 |
|
2,120 |
|
4,039 |
|
|||
|
Revision of quantity estimates |
|
71,374 |
|
16,038 |
|
70,532 |
|
|||
|
Accretion of discount |
|
103,034 |
|
74,121 |
|
24,115 |
|
|||
|
Change in income taxes |
|
(55,438 |
) |
(111,409 |
) |
(148,765 |
) |
|||
|
Purchases of reserves in place |
|
221 |
|
4,174 |
|
297,394 |
|
|||
|
Sales of properties |
|
(289 |
) |
(837 |
) |
(1 |
) |
|||
|
Change in production rates and other |
|
(20,711 |
) |
(17,386 |
) |
(42,802 |
) |
|||
|
Standardized measure end of period |
|
$ |
798,033 |
|
$ |
711,581 |
|
$ |
533,859 |
|
Impact of Pricing (Unaudited) – The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations are largely due to the seasonal pricing nature of natural gas, supply perceptions for natural gas and significant worldwide volatility in oil prices.
62
The following average prices were used in determining the Standardized Measure as of:
|
|
|
December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Price per Mcf |
|
$ |
5.58 |
|
$ |
5.54 |
|
$ |
4.22 |
|
|
Price per Bbl |
|
$ |
40.76 |
|
$ |
30.49 |
|
$ |
28.56 |
|
Under SEC rules, companies that follow full cost accounting methods are required to make quarterly “ceiling test” calculations. Under this test, capitalized costs of oil and gas properties, net of accumulated DD&A, and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the “year-by-year” method for purposes of the supplemental oil and gas disclosures and use the “short-cut” method for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs.
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
||||
|
|
|
(In thousands, except for per share data) |
|
||||||||||
|
2004 |
|
|
|
|
|
|
|
|
|
||||
|
Revenues |
|
$ |
135,919 |
|
$ |
170,193 |
|
$ |
170,273 |
|
$ |
198,544 |
|
|
Expenses, net |
|
106,054 |
|
133,723 |
|
131,091 |
|
150,469 |
|
||||
|
Net income |
|
$ |
29,865 |
|
$ |
36,470 |
|
$ |
39,182 |
|
$ |
48,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
$ |
0.72 |
|
$ |
0.88 |
|
$ |
0.94 |
|
$ |
1.15 |
|
|
Diluted |
|
$ |
0.70 |
|
$ |
0.85 |
|
$ |
0.91 |
|
$ |
1.12 |
|
63
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
||||
|
|
|
(In thousands, except for per share data) |
|
||||||||||
|
2003 |
|
|
|
|
|
|
|
|
|
||||
|
Revenues |
|
$ |
136,559 |
|
$ |
99,270 |
|
$ |
112,762 |
|
$ |
105,621 |
|
|
Expenses, net |
|
105,416 |
|
78,230 |
|
90,221 |
|
87,317 |
|
||||
|
Income before cumulative effect of change in accounting principle |
|
31,143 |
|
21,040 |
|
22,541 |
|
18,304 |
|
||||
|
Cumulative effect of change in accounting principle, net |
|
1,605 |
|
— |
|
— |
|
— |
|
||||
|
Net income |
|
$ |
32,748 |
|
$ |
21,040 |
|
$ |
22,541 |
|
$ |
18,304 |
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
||||
|
Basic: |
|
|
|
|
|
|
|
|
|
||||
|
Income before cumulative effect of change in accounting principle |
|
$ |
0.75 |
|
$ |
0.51 |
|
$ |
0.54 |
|
$ |
0.44 |
|
|
Cumulative effect of change in accounting principle, net |
|
0.04 |
|
— |
|
— |
|
— |
|
||||
|
Net income |
|
$ |
0.79 |
|
$ |
0.51 |
|
$ |
0.54 |
|
$ |
0.44 |
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
||||
|
Income before cumulative effect of change in accounting principle |
|
$ |
0.74 |
|
$ |
0.50 |
|
$ |
0.53 |
|
$ |
0.43 |
|
|
Cumulative effect of change in accounting principle, net |
|
0.04 |
|
— |
|
— |
|
— |
|
||||
|
Net income |
|
$ |
0.78 |
|
$ |
0.50 |
|
$ |
0.53 |
|
$ |
0.43 |
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
||||
|
|
|
(In thousands, except for per share data) |
|
||||||||||
|
2002 |
|
|
|
|
|
|
|
|
|
||||
|
Revenues |
|
$ |
34,575 |
|
$ |
46,134 |
|
$ |
51,809 |
|
$ |
77,126 |
|
|
Expenses, net |
|
30,317 |
|
36,290 |
|
41,879 |
|
61,339 |
|
||||
|
Net income |
|
$ |
4,258 |
|
$ |
9,844 |
|
$ |
9,930 |
|
$ |
15,787 |
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
$ |
0.16 |
|
$ |
0.37 |
|
$ |
0.37 |
|
$ |
0.39 |
|
|
Diluted |
|
$ |
0.16 |
|
$ |
0.37 |
|
$ |
0.37 |
|
$ |
0.38 |
|
The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period’s computation is based on the weighted average number of shares outstanding during that period.
64
None.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The Company’s principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of the Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the Company’s last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Cimarex Energy Co. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2004, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2004, based on those criteria.
Effective February 1, 2005, the Company implemented a new accounting information system, affecting on a going forward basis, the Company’s internal control over financial reporting. Such change was planned and performed as scheduled. Ongoing evaluation of the Company’s internal control environment and assessment of this change resulting from changes in the new accounting system is underway.
KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. The report, which expresses unqualified opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, is included in this Item.
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Report of Independent Registered Public Accounting Firm
The Board of Directors
Cimarex Energy Co.:
We have audited management’s assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that Cimarex Energy Co. and subsidiaries (Cimarex or the Company) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles; (3) that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Cimarex maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Cimarex maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cimarex and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2004, and our report dated March 11, 2005 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Denver, Colorado
March 11, 2005
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None.
Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than May 2, 2005. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report.
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than May 2, 2005.
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than May 2, 2005.
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than May 2, 2005.
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than May 2, 2005.
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(1) |
The following financial statements are included in Item 8 to this 10-K: |
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Consolidated balance sheets as of December 31, 2004 and 2003. |
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Consolidated statements of operations for the years ended December 31, 2004, 2003 and 2002. |
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Consolidated statements of cash flows for the years ended December 31, 2004,2003 and 2002. |
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Consolidated statements of stockholders’ equity for the year ended December 31, 2004, 2003 and 2002. |
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(2) |
Financial statement schedules – None |
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(3) |
Exhibits: |
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Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.
Exhibits designed by a plus sign (+) are management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15.
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2.1 |
Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as Exhibit 2.1 to the Registrant’s Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). |
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2.2 |
Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). |
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2.3 |
Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). |
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3.1 |
Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-87948), and incorporated herein by reference). |
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3.2 |
By-laws of Cimarex Energy Co. (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-387948) and incorporated herein by reference). |
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4.1 |
Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). |
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4.2 |
Rights Agreement, dated as of February 23, 2002, by and between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to dated May 9, 2002 the Registration Statement on Form S-4 (Registration No. 333-87948) and incorporated herein by reference). |
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10.1 |
Credit Agreement, dated October 2, 2002, among Cimarex Energy Co., the lenders party thereto, Bank One, NA, as Administrative Agent, Royal Bank of Canada, as Co-Documentation Agent, Wachovia Bank, National Association, as Co-Documentation Agent, and Banc One Capital Markets, Inc., as Lead Arranger and Sole Book Runner. (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002, file no. 001-31446, and incorporated herein by reference). |
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10.2 |
First Amendment to Credit Agreement, dated as of April 21, 2003, among Cimarex Energy Co., BankOne, NA, as Administrative Agent, and the Lenders under the Credit Agreement (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 2003, file no. 001-31446, and incorporated herein by reference). |
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10.3 |
Second Amendment to Credit Agreement dated as of October 1, 2004 among Cimarex Energy Co., BankOne, NA, as Administrative Agent, and the Lenders under the Credit Agreement (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2004 file no. 001-31446, and incorporated herein by reference). |
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10.4 |
Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). |
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10.5 |
Tax Sharing Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.2 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). |
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10.6 |
Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). |
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10.7 |
First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). |
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10.8 |
Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+ |
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10.9 |
Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+ |
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10.10 |
Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+ |
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10.11 |
Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+ |
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10.12 |
Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+ |
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10.13 |
Key Production Company, Inc. Income Continuance Plan, dated effective June 1, 1994 (originally filed as Exhibit 10.18 to Key Production Company, Inc.’s Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162 and refiled as Exhibit 10.13 to the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). |
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10.14 |
Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. (filed as Exhibit 10.14 to the Registrant’s From 10-K for the fiscal year ended December 31, 2002, file no. 001-31446, and incorporated herein by reference).+ |
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10.15 |
Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective March 3, 2003). (filed as Exhibit 10.15 to the Registrant’s Form 10-K for the fiscal year ended December 31, 2002, file no. 001-31446, and incorporated herein by reference).+ |
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10.16 |
Employment Agreement, dated March 11, 2002, by and between Richard Dinkins and Cimarex Energy Co. (filed as Exhibit 10.16 to the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference).+ |
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10.17 |
Voting Agreement, dated as of January 25, 2005, among Cimarex Energy Co., Gary C. Evans and Jacquelyn Evelyn Enterprises, Inc. (filed as Exhibit 99.1 to the Registrant’s Current Report on Form 8-K dated January 28, 2005, file no. 001-31446, and incorporated herein by reference). |
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10.18 |
Director Compensation Table as of March 10, 2005 (filed as Exhibit 10.1 to the Current Report on Form 8-K dated March 10, 2005, file no. 001-31446, and incorporated herein by reference).+ |
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14.1 |
Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and incorporated herein by reference). |
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21.1 |
Subsidiaries of the Registrant.* |
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23.1 |
Consent of KPMG LLP.* |
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23.2 |
Consent of Ryder Scott Company, LP.* |
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24.1 |
Power of Attorney of directors of the Registrant.* |
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31.1 |
Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* |
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31.2 |
Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* |
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32.1 |
Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* |
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32.2 |
Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* |
(b) Form 8-K furnished October 8, 2004, providing an update of operations.
Form 8-K furnished November 5, 2004, announcing financial and operating results for the third quarter and first nine months of 2004.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: March 10, 2005
CIMAREX ENERGY CO.
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By: |
/s/ F.H. Merelli |
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F.H. Merelli |
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Chairman, President and Chief Executive |
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Officer |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Signature |
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Title |
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Date |
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/s/ F.H. Merelli |
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Director, Chairman, President and Chief |
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March 10, 2005 |
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F.H. Merelli |
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/s/ Paul Korus |
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Vice President, Chief Financial Officer, |
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March 10, 2005 |
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Paul Korus |
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/s/ James H. Shonsey |
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Controller, Chief Accounting Officer |
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March 10, 2005 |
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James H. Shonsey |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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Glenn A. Cox |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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Cortlandt S. Dietler |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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Hans Helmerich |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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David A. Hentschel |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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Paul D. Holleman |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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L.F. Rooney, III |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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Michael J. Sullivan |
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/s/ F.H. Merelli |
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Director |
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March 10, 2005 |
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Attorney-in-Fact |
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L. Paul Teague |
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74