UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D C 20549

 

Form 10-K/A

Amendment No.1

 

 

(Mark One)

 

 

 

 

 

 

 

ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

 

 

 

 

 

 

For the fiscal year ended December 31, 2003

 

 

 

 

 

 

 

 

 

OR

 

 

 

 

 

 

 

 

o

Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934

 

 

 

 

 

 

 

 

 

Commission file number 001-31446

 

 

CIMAREX ENERGY CO.

(Exact name of registrant as specified in its charter)

 

Delaware

 

45-0466694

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

707 Seventeenth Street, Suite 3300, Denver, Colorado 80202

(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:

 

Title of Each Class

 

Name of each exchange on which registered

Common Stock ($.01 par value)

 

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/A or any amendment to this Form 10-K/A.

 

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, 2003 was approximately $971,834,366.

 

Number of shares of Cimarex Energy Co. common stock outstanding as of February 29, 2004 was 41,317,563.

 

Documents Incorporated by Reference:  Portions of the Registrant’s Proxy Statement for its 2004 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K/A

 

 



 

TABLE OF CONTENTS

 

DESCRIPTION

 

Item

 

 

 

 

 

Glossary

 

 

 

 

PART I

 

 

 

 

1.

Business

 

2.

Properties

 

3.

Legal Proceedings

 

4.

Submission of Matters to a Vote of Security Holders

 

4A.

Executive Officers of Cimarex

 

 

 

 

PART II

 

 

 

 

5.

Market for the Registrant’s Common Equity and Related Stockholders Matters

 

6.

Selected Financial Data

 

7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

7A.

Quantitative and Qualitative Disclosures About Market Risk

 

8.

Financial Statements

 

9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

9A.

Controls and Procedures

 

 

 

 

PART III

 

 

 

 

10.

Directors and Executive Officers of the Registrant

 

11.

Executive Compensation

 

12.

Security Ownership of Certain Beneficial Owners and Management

 

13.

Certain Relationships and Related Transaction

 

14.

Principal Accountant Fees and Services

 

 

 

 

PART IV

 

 

 

 

15.

Exhibits, Financial Statement Schedules and Reports on Form 8-K

 

 

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Glossary

 

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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PART I

 

Forward-Looking Statements

 

Throughout this Form 10-K/A 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/A.  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/A 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/A 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/A with the Securities and Exchange Commission, except as required by law.

 

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ITEM 1.     BUSINESS

 

General

 

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, 2003, proved reserves totaled 422.2 Bcfe consisting of 337.3 Bcf of gas and 14.1 million barrels of oil.  Of total proved reserves, 80 percent are gas and more than 99 percent are classified as proved developed.  We operate the wells that account for 65 percent of our total proved reserves and production.

 

Approximately 39 percent of our proved reserves are located in Oklahoma.  Properties situated in Texas and Kansas comprised 25 percent and 20 percent of total proved reserves, respectively.  We have active exploration and development programs underway in each of those states as well as in Mississippi, Louisiana, New Mexico, California, and North Dakota.

 

The estimated present value using a 10 percent discount rate of the future net cash flow before income taxes from year-end 2003 proved reserves is $1.03 billion.   The standardized measure of discounted future net cash flow after tax is $711.6 million.  In accordance with standardized measure guidelines established by the Securities and Exchange Commission (SEC), we used an average gas price of $5.54 per Mcf and an average oil price of $30.49 per barrel over the life of the properties to determine these amounts.

 

Cimarex 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 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, Cimarex acquired Key Production Company, Inc. (Key) in a stock-for-stock transaction whereby each of Key’s 14.1 million outstanding common shares were 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 on Form 10-K/A, 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.  As a consequence, financial statements included in this report show results of operations for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the fiscal year ended September 30, 2001.

 

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 707 Seventeenth Street, Suite 3300, Denver, Colorado 80202, 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.”

 

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Business Approach

 

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 supplement our growth, from time to time we also consider acquisitions and mergers but do not view these activities as being our primary growth drivers.  To implement these strategies, 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;

 

                                          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;

 

                                          Evaluate the economic and strategic attractiveness of acquisition and merger opportunities; and

 

                                          Maintain financial flexibility and an appropriate capital structure.

 

Exploration and Development

 

Exploration and development activities are primarily focused in western Oklahoma and the upper Gulf Coast areas of Texas and Louisiana.  We also 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, the northern San Joaquin Valley of California, the Williston Basin of North Dakota and Montana, and the Gulf of Mexico.

 

For each of our core exploration areas we have assembled integrated teams of landmen, geoscientists 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 178 gross wells during 2003, with an overall success rate of 81 percent.  On a net basis, 73 of 97 total wells drilled during 2003 were successful.

 

Our 2003 exploration and development expenditures, excluding leasehold costs, totaled $151.3 million and resulted in 78.2 Bcfe of proved reserve additions.  Including lease acquisition costs, we invested nearly $161 million.  Of total expenditures, 60 percent ($97 million) was invested in projects located in the mid-continent area of the U.S., including Kansas, Oklahoma and north Texas.  Approximately 30 percent, or $48 million, was directed toward prospects located along the Texas and Louisiana Gulf Coast and adjacent shallow waters in the Gulf of Mexico.

 

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One of our most notable discoveries during 2003 was the Mauboules #1 well on the West Gueydan prospect in Vermilion Parish, Louisiana.  As of year-end 2003, the well was awaiting completion operations.  First sales occurred on February 20, 2004 and by month end had risen to daily production of 18.0 MMcf of gas and 280 barrels of oil.

 

The new well was drilled to a total depth of 18,300 feet and found two gas-bearing intervals in the Miogyp formation.  During testing operations, it produced nearly 19 MMcfe per day from the upper interval.  A second well, the Mauboules #2, is situated approximately 2,000 feet north of the #1 well and is being drilled to develop the lower zone.  We operate both wells with a 64.5 percent working interest and have a 46.4 percent revenue interest. We also plan to drill during 2004 one to three additional exploratory wells on separate geologic features in the immediately surrounding area.

 

Elsewhere in the upper Gulf Coast area, we drilled six wells in Liberty County, Texas, three of which  were productive in the the Yegua and Cook Mountain formations.  The two best wells were the Henderson #1 (82 percent working interest) and the Brookhollow #1 (50 percent working interest), that tested at gross rates of 7.8 MMcfe per day and 6.8 MMcfe per day, respectively.  We plan to drill another seven to nine wells in this area during 2004.

 

We continue to have a high level of drilling activity in western Oklahoma, primarily targeting the Red Fork and Granite Wash formations in the Anadarko Basin.  During 2003, we completed 78 of 81 gross wells in this area, and we anticipate drilling over 100 wells there during 2004.

 

In the Mountain Front play of southwestern Oklahoma, each of the six wells drilled were completed as producers.  The larger discoveries in this area produced gas at high initial rates when they were brought on line during November 2003, helping boost our aggregate fourth-quarter 2003 volumes to 187 MMcfe per day.  Of particular importance were the Gwendolyn #3-29, with net production of 9.4 MMcf per day; the Buddy #3-32, producing a net 6.7 MMcf per day; and the Lisa #4-30, with net production of 4.8 MMcf per day.  We plan to drill 13 more wells in this area during 2004.

 

In the Arkoma basin of eastern Oklahoma, we drilled and completed twelve wells during 2003, and have a similar level of activity planned for 2004.  In the Hardeman Basin, we completed nine of 21 wells.  We own approximately 400 square miles of 3-D seismic survey data in the Hardeman and plan to drill an additional six to eight wells on our acreage during 2004.

 

We completed four of seven wells drilled in the Permian Basin during 2003.  Primarily targeting Pennsylvanian-age, gas-bearing formations, we have identified as many as 25 potential drilling locations for 2004.

 

Acquisitions

 

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 primarily 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.

 

Production

 

Production volumes during 2003 averaged 180 MMcfe per day versus 132 MMcfe per day in 2002.  Gas production was 138.5 MMcf per day, compared to 113.2 MMcf per day during 2002.  Oil production was 6,859 barrels per day in 2003 versus 3,209 barrels per day in 2002.  The increase in

 

7



 

volumes primarily stems from the acquisition of Key and 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 if we did not conduct successful drilling operations or acquire existing producing properties.

 

The weighted-average gas price we received during 2003 was $4.96 per Mcf , which was 60 percent higher than the $3.10 per Mcf average price we received during 2002.  Our annual average realized oil price during 2003 increased by 17 percent to $29.30 per barrel from $24.97 per barrel in 2002.  The increase in the prices we received during 2003 was the result of tighter market conditions for oil and gas.

 

Our largest producing area was western Oklahoma, providing nearly 64 MMcfe per day, or 36 percent of our total production during 2003.  We operated 67 percent of this production, of which 93 percent was gas.

 

Production from Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 16 percent of our total production, with 84 percent being gas.  We operated 93 percent of the related volumes.

 

The areas along the Gulf Coast of Texas, Louisiana and Mississippi yielded approximately 30 MMcfe per day of output, which was 17 percent of our total production.  Of these volumes, 70 percent was gas and 42 percent was operated.

 

The Permian basin provided another 22 MMcfe per day or 12 percent of total production, with 80 percent of the related volumes being gas and 68 percent from properties that we operate.

 

We have implemented management systems over our production operations that monitor actual results against plan and measure controllable costs.  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.  Overall, approximately 65 percent of both our production and oil and gas reserves are from properties that we operate.

 

Marketing

 

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, posted platts, as well as daily front-month 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 spot market.

 

We sell our oil and gas to a broad portfolio of customers.  Our largest customer, OGE Energy Resources, Inc., accounted for 10.3 percent of 2003 revenues.  Because approximately two-thirds of our gas production is from wells in Kansas and Oklahoma, most of our customers are from those states or other Midwest market centers.  We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.

 

We 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

 

8



 

activity associated with supplying gas sales arrangements under which our equity gas is also being sold.  Approximately 56 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.

 

Employees

 

We employed 315 people on December 31, 2003.  None of our employees are subject to collective bargaining agreements.

 

Web Site Access

 

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.

 

Competition

 

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 majors, independents 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.

 

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.

 

Government Regulation

 

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.

 

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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 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.

 

Federal and State Income Taxation

 

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.

 

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Certain Risks

 

The following risks and uncertainties, together with other information set forth in this Form 10-K/A, 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.

 

Low oil and gas prices could adversely affect our financial results and future rate of growth in proved reserves and production.

 

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 2003 we sold our gas at an average price of $4.96 per Mcf, which was 60 percent higher than our 2002 average sales price of $3.10 per Mcf.  Similarly, our average 2003 oil price of $29.30 per barrel was 17 percent higher than the price we received in 2002 of $24.97 per barrel.  As a result, our combined 2003 oil and gas sales increased by 106 percent to $324 million from $157 million in 2002, versus a 36 percent increase in our aggregate production volumes.

 

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 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.

 

Failure of our exploration and development  program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth.

 

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

 

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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.

 

Our proved reserve estimates may be inaccurate and future net cash flows are uncertain.

 

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.

 

Estimates of proved reserves and future net cash flow prepared by different engineers or by the same engineers at different times may vary substantially.  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, 2003.

 

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.

 

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines.

 

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.

 

Competition in our industry is intense and many of our competitors have greater financial and technological resources.

 

We operate in the competitive area of oil and gas exploration and production.  Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources than we do.  These companies may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

 

12



 

We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

 

Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex environmental laws.  We may be required to make large expenditures to comply with environmental and other governmental regulations.  Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties.  Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation.  Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water.  In the event of environmental violations, we may be charged with remedial costs.  Pollution and similar environmental risks generally are not fully insurable.  Such liabilities and costs could have a material adverse effect on our financial condition and results of operations.

 

Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control.

 

Other companies operate approximately 35 percent of our net production.  Our success in properties operated by others depends upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards.  Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.

 

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

 

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases.  Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs.

 

In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.

 

We maintain insurance coverage against some, but not all, potential losses.  We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost.  Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage.  The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.

 

Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

 

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

 

13



 

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.

 

Competition for experienced, technical personnel may negatively impact our operations.

 

Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel.  The loss of any key executives or other key personnel could have a material adverse effect on our operations.  As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

 

The tax agreement with Helmerich & Payne, Inc. imposes significant restrictions until October 1, 2004 on our ability to issue or redeem our common stock or to undergo a change of control.

 

On September 30, 2002, Cimarex entered into an agreement with H&P that imposes certain restrictions on Cimarex until October 1, 2004 to redeem or issue a material number of shares of its common stock or for Cimarex to undergo a change of control.  Such actions by Cimarex could cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially resulting in a substantial amount of taxable income to H&P.  Under the terms of the agreement, if Cimarex takes or permits an action to be taken that causes the spin off to be taxable, Cimarex would generally be liable for all or a portion of the resultant tax liability.  It is expected that any such taxes allocated to Cimarex would be material.

 

The Cimarex certificate of incorporation, by-laws and stockholders’ rights plan include provisions that could discourage an unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment.

 

The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders.  In addition, Delaware General Corporation Law imposes restrictions on business combinations with interested parties.  Cimarex also has adopted a stockholders’ rights plan.  The stockholders’ rights plan, the certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to Cimarex stockholders.

 

14



 

ITEM 2.     PROPERTIES

 

Properties

 

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 65 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, 2003.  All information in this Form 10-K/A 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.

 

Proved Oil and Gas Reserves as of December 31, 2003

 

 

 

Gas
(MMcf)

 

Oil, Condensate
and NGL

(MBbls)

 

Equivalent
(MMcfe)

 

 

 

 

 

 

 

 

 

Oklahoma

 

156,895

 

1,390

 

165,235

 

Texas

 

71,707

 

5,590

 

105,245

 

Kansas

 

69,354

 

2,749

 

85,847

 

Louisiana

 

12,380

 

457

 

15,122

 

Wyoming

 

11,222

 

2,286

 

24,935

 

Other

 

15,786

 

1,665

 

25,783

 

Total

 

337,344

 

14,137

 

422,167

 

 

 

 

 

 

 

 

 

Proved Developed

 

336,230

 

13,876

 

419,488

 

 

Significant Properties

 

Although no single property accounts for more than three percent of our total production, collectively our properties in western Oklahoma produced at an average daily rate of 64 MMcfe during 2003, which was 36 percent of our company-wide 2003 production.  These properties consist of varying working interests in approximately 940 wells, mostly located in Roger Mills, Washita, Custer and Beckham counties.  We operate wells that account for 67 percent of our Anadarko Basin output.

 

Elsewhere in the state, we have concentrations of properties in the Arkoma Basin of eastern Oklahoma.  During 2003, net production from the Arkoma Basin, principally the Ashland field, averaged six MMcf of gas per day (45 percent operated).

 

Altogether, at year-end 2003, our Oklahoma properties accounted for 165.2 Bcfe of proved reserves, or 39 percent of our total proved reserves.  Production from these properties during 2003 averaged nearly 70 MMcfe per day and equated to 40 percent of our aggregate output.  Including all wells, our average working interest in Oklahoma is 24 percent.

 

During 2003, oil production from the Hardeman Basin of north-central Texas averaged 2,050 barrels per day, which equated to 30 percent of our total company-wide oil sales.  We have an average working interest of 82 percent in 52 wells and operate 94 percent of our 2003 net production in the Basin.

 

15



 

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 six producing wells in the area with working interests ranging from 35 to 85 percent.

 

Proved reserves in west Texas 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 5 MMcf per day during 2003 and was the most prolific producing well we owned during the year.  The Dixieland #10-1 well produced 1 MMcf per day.

 

Overall, our proved oil and gas reserves in Texas amounted to 105.2 Bcfe, represent 25 percent of total proved reserves and are 68 percent natural gas.  Production volumes during 2003 from our Texas properties averaged 37 MMcfe per day, or 21 percent of total production.

 

In southwest Kansas, our principal properties produce from the Chase and Council Grove formations of the Hugoton field.  During 2003, net production from this area averaged 28 MMcfe per day, or 16 percent of total company output.  We have a 55 percent average working interest in over 500 Hugoton wells, and we operate 93 percent of the related 2003 production.  Our year-end 2003 proved reserves in Kansas of 85.8 Bcfe were 81 percent gas and 20 percent of our total proved reserves.

 

In the coastal areas of Louisiana and Mississippi, our proved reserves are largely derived from properties located in the West Gueydan field of Vermilion Parish, Louisiana and the Mississippi Salt Basin.  In total, our south Louisiana properties have proved reserves equal to 3.6 percent of our company-wide total proved reserves and our Mississippi assets comprise two percent.

 

In the western U.S., our principal properties include small (generally less than three percent) royalty and working interests in over 1,100 non-operated wells in the Powder River, Wind River and Big Horn basins of Wyoming.  In aggregate, these interests accounted for 6 percent of our total proved reserves.

 

In the Williston Basin of North Dakota and Montana, we own an average working interest of 17 percent in 94 producing wells.  During 2003, oil production from this area averaged 209 barrels per day and our total proved reserves amounted to 4.8 Bcfe, of which 92 percent was oil.

 

Although currently exploring in California’s San Joaquin Valley, the bulk of our proved reserves and production in this state stem from 36 producing wells situated in the Sacramento Basin.  We operate almost all of these wells with an average 70 percent working interest.  In total, proved reserves attributable to these interests amount to 7.1 Bcf of gas, which equate to 1.7 percent of our total proved reserves.

 

16



 

Acreage

 

The undeveloped and developed acreage held by us as of December 31, 2003 is set forth below:

 

 

 

Undeveloped Acreage

 

Developed Acreage

 

 

 

Gross Acres

 

Net Acres

 

Gross Acres

 

Net Acres

 

 

 

 

 

 

 

 

 

 

 

Alabama

 

1,600

 

1,400

 

 

 

Arkansas

 

 

 

4,766

 

1,638

 

California

 

17,962

 

13,334

 

8,138

 

6,481

 

Colorado

 

2,944

 

32

 

2,333

 

762

 

Kansas

 

17,343

 

17,079

 

122,489

 

89,720

 

Louisiana

 

5,108

 

2,471

 

26,446

 

5,073

 

Michigan

 

2,135

 

2,020

 

 

 

Mississippi

 

10,606

 

3,897

 

10,547

 

2,747

 

Montana

 

15,412

 

2,329

 

9,751

 

5,511

 

Nebraska

 

12,821

 

969

 

480

 

168

 

New Mexico

 

522

 

53

 

2,480

 

192

 

North Dakota

 

20,702

 

662

 

7,329

 

1,262

 

Oklahoma

 

28,073

 

22,716

 

194,340

 

86,884

 

Texas

 

103,763

 

56,966

 

168,946

 

64,227

 

Utah

 

1,094

 

1,094

 

280

 

2

 

Wyoming

 

39,805

 

7,724

 

17,034

 

1,472

 

 

 

279,890

 

132,746

 

575,359

 

266,139

 

 

Gross Wells Drilled

 

We participated in drilling the following number of gross wells during calendar years 2003 and 2002, the three months ended December 31, 2001 and fiscal year ended September 30, 2001:

 

 

 

Exploratory

 

Developmental

 

 

 

Productive

 

Dry

 

Total

 

Productive

 

Dry

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2003

 

19

 

27

 

46

 

125

 

7

 

132

 

Year ended December 31, 2002

 

13

 

12

 

25

 

84

 

1

 

85

 

Three months ended December 31, 2001

 

3

 

5

 

8

 

6

 

 

6

 

Year ended September 30, 2001

 

24

 

21

 

45

 

70

 

8

 

78

 

 

We were in the process of drilling 15 gross (6.5 net) wells at December 31, 2003.

 

Net Wells Drilled

 

The number of net wells we drilled during calendar years 2003 and 2002, the three months ended December 31, 2001 and the fiscal year ended September 30, 2001 are shown below:

 

 

 

Exploratory

 

Developmental

 

 

 

Productive

 

Dry

 

Total

 

Productive

 

Dry

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

Three months ended December 31, 2001

 

0.92

 

1.63

 

2.55

 

3.66

 

 

3.66

 

Year ended September 30, 2001

 

9.04

 

9.96

 

19.00

 

43.46

 

7.00

 

50.46

 

 

17



 

Reserve Information

 

Our estimated proved oil and gas reserves, as of December 31, 2003, 2002, 2001 and September 30, 2001 are included in Note 16, Supplemental Oil and Gas Disclosures to Notes to Consolidated Financial Statements appearing in this Form 10-K/A.  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
(MMcf)

 

Oil
(MBbls)

 

Total
(MMcfe)

 

Gas
(MMcf)

 

Oil
(MBbls)

 

Total
(MMcfe)

 

As of:

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

December 31, 2001

 

212,326

 

5,304

 

244,150

 

211,874

 

4,607

 

239,513

 

September 30, 2001

 

216,337

 

5,932

 

251,927

 

213,931

 

5,213

 

245,207

 

 

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
Cash Flow
Before Income
Tax
(Discounted at

10 Percent)

 

Standardized
Measure of
Discounted Future
Net Cash Flow
(Discounted at 10
Percent)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average
Price Used in Year-end
Calculation of

Future Net Cash Flow

 

 

 

 

 

Gas

 

Oil

 

As of:

 

 

 

 

 

 

 

 

 

December 31, 2003

 

$

1,030,340

 

$

711,581

 

$

5.54

 

$

30.49

 

December 31, 2002

 

741,209

 

533,859

 

4.22

 

28.56

 

December 31, 2001

 

241,150

 

182,565

 

2.23

 

18.10

 

September 30, 2001

 

191,240

 

144,039

 

1.90

 

20.25

 

 

Productive Wells

 

We have working interests in the following productive oil and gas wells as of December 31, 2003:

 

 

 

Gas

 

Oil

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Kansas

 

441

 

271.0

 

234

 

101.7

 

Louisiana

 

75

 

19.2

 

40

 

3.2

 

Oklahoma

 

1,165

 

308.5

 

391

 

57.2

 

Texas

 

389

 

126.0

 

3,586

 

127.2

 

Wyoming

 

88

 

7.7

 

1,135

 

60.5

 

Other

 

146

 

42.0

 

164

 

26.7

 

 

 

2,304

 

774.4

 

5,550

 

376.5

 

 

18



 

Production and Pricing Information

 

The following table describes for the periods indicated our production, pricing and production cost data:

 

 

 

Gas
(MMcf)

 

Oil
(MBbls)

 

 

 

Average
Production
Cost

Per Mcfe

 

 

 

 

 

 

 

 

 

 

 

 

Average Sales Price

 

 

 

 

 

 

Per Mcf

 

Per Bbl

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2003

 

50,522

 

2,504

 

$

4.96

 

$

29.30

 

$

0.49

 

Year ended December 31, 2002

 

41,300

 

1,171

 

$

3.10

 

$

24.97

 

$

0.40

 

Three months ended December 31, 2001

 

10,174

 

206

 

$

2.24

 

$

19.97

 

$

0.37

 

Year ended September 30, 2001

 

42,387

 

818

 

$

4.70

 

$

27.88

 

$

0.28

 

 

19



 

ITEM 3.     LEGAL PROCEEDINGS

 

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 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 $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.  We have received confirmation from the court that any claim against Cimarex will be limited to our proportionate interest in the two properties.  We cannot predict the outcome of this litigation, and accordingly, no accrual has been recorded in connection with this action.

 

ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

No matters were submitted for a vote of security holders during the fourth quarter of 2003.

 

ITEM 4A.                                            EXECUTIVE OFFICERS

 

The executive officers of Cimarex as of March 7, 2004 were:

 

Name

 

Age

 

Office

 

 

 

 

 

F.H. Merelli

 

67

 

Chairman of the Board, Chief Executive Officer and President

Thomas E. Jorden

 

46

 

Executive Vice President-Exploration

Steven R. Shaw

 

53

 

Executive Vice President-Operations

Paul Korus

 

47

 

Vice President, Chief Financial Officer, Treasurer and Secretary

Stephen P. Bell

 

49

 

Senior Vice President, Business Development and Land

Joseph R. Albi

 

45

 

Senior Vice President-Corporate Engineering

Richard S. Dinkins

 

59

 

Vice President of Human Resources

James H. Shonsey

 

52

 

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.

 

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.

 

20



 

STEVEN R. SHAW was elected executive vice president of operations on September 30, 2002.  From 1985 through September 30, 2002, Mr. Shaw was with H&P, serving as vice president of exploration and production since 1996 and as its vice president of production from 1985 to 1996.

 

PAUL KORUS was elected vice president, chief financial officer and treasurer 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.

 

JOSEPH R. ALBI was named senior vice president of corporate engineering on December 8, 2003.  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.

 

RICHARD S. DINKINS was named vice president of human resources on December 8, 2003.  Mr. Dinkins joined Key Production in March 2002 as its director of human resources.  Prior to joining Key and since February 1999, Mr. Dinkins was with Sprint in Overland Park, Kansas.

 

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.

 

ITEM 5.                                                     MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

 

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 fourth quarter of 2002 and for each quarter during 2003 were:

 

 

 

2003

 

2002

 

 

 

High

 

Low

 

High

 

Low

 

 

 

 

 

 

 

 

 

 

 

First Quarter

 

$

20.42

 

$

17.07

 

 

 

 

 

Second Quarter

 

$

24.40

 

$

18.80

 

 

 

 

 

Third Quarter

 

$

23.70

 

$

19.24

 

 

 

 

 

Fourth Quarter

 

$

28.14

 

$

19.50

 

$

18.00

 

$

13.49

 

 

The closing price of Cimarex stock as reported on the New York Stock Exchange on March 4, 2004, was $28.90.  At December 31, 2003, Cimarex’s 41,063,653 shares of outstanding common stock were held by approximately 2,208 stockholders of record.

 

21



 

ITEM 6.     SELECTED FINANCIAL DATA

 

The following table shows selected financial data for the years ended December 31, 2003 and 2002, together with similar information for each of the three 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/A:

 

 

 

As of and For the Years Ended

 

Three Months
Ended

December 31,
2001

 

 

 

December 31,

 

September 30,

 

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

 

(In thousands, except per share and proved reserve amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating results:

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

454,212

 

$

209,644

 

$

316,778

 

$

237,021

 

$

146,902

 

$

39,596

 

Net income

 

94,633

 

39,819

 

35,253

 

57,386

 

23,559

 

4,479

 

Net income per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

2.28

 

1.32

 

1.33

 

2.16

 

0.89

 

0.17

 

Diluted

 

2.22

 

1.31

 

1.33

 

2.16

 

0.89

 

0.17

 

Cash dividends declared per share

 

 

 

 

 

 

 

Balance sheet data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

805,508

 

674,286

 

246,212

 

286,090

 

234,929

 

251,966

 

Total debt

 

 

32,000

 

 

 

 

 

Stockholders’ equity

 

534,740

 

444,880

 

166,795

 

192,972

 

172,664

 

175,082

 

Other financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

324,119

 

157,299

 

222,136

 

158,502

 

93,808

 

26,857

 

Oil and gas capital expenditures

 

162,627

 

368,503

 

104,975

 

73,821

 

55,933

 

14,425

 

Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (MMcf)

 

337,344

 

318,627

 

216,337

 

262,498

 

239,620

 

212,326

 

Oil (MBbls)

 

14,137

 

15,025

 

5,932

 

6,305

 

4,834

 

5,304

 

Total equivalent (MMcfe)

 

422,167

 

408,779

 

251,927

 

300,329

 

268,623

 

244,150

 

 

22



 

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

INTRODUCTION

 

Cimarex Energy Co. is an independent oil and gas exploration and production company.  Our primary focus is to explore for and discover new reserves.  To supplement our growth, from time to time we also consider acquisitions and mergers.  Our operations are presently focused in Oklahoma, Texas, Kansas and Louisiana.

 

Industry and Economic Factors

 

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.

 

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 2004 exploration and development expenditures will approximate $200-220 million, up from $160 million in 2003.  We are expanding our 2004 program as a result of successful exploration wells drilled in 2003, growth in our western Oklahoma development projects and entry into new basins.  Similar to 2003, a large portion of our 2004 expenditures will be directed to our projects in Oklahoma, Texas and Louisiana. A total of $100 million is anticipated to be spent in the mid-continent area of Oklahoma and north Texas.  In the coastal regions of Texas, Louisiana and Mississippi, we plan to

 

23



 

spend $75 million during 2004. The remainder of our projected expenditures will be focused in the Permian basin, California and other western states.

 

With shareholder equity of $534.7 million, a cash balance of $40.4 million, no debt, and proved reserves of 422.2 Bcfe, we believe we are well positioned to fund the projects identified for 2004 and beyond.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP.  The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses.  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.

 

Revenue Recognition

 

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.

 

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. Revisions of  reserve estimates as of December 31, 2003 equaled an increase of 41 MBbls of oil and an increase of 6.7 Bcf of gas, representing 0.3 percent and 2.0 percent of total proved oil and gas reserves, respectively, as of the end of the year.  Corresponding percentages of revisions of previous oil and gas reserve estimates, respectively, for 2002 equal an increase of 7.3 percent and 9.8 percent.  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 unit-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.  A reduction in the carrying value of oil and gas properties of $78.1 million was incurred during the year ended September

 

24



 

30, 2001.  This reduction was the result of a reduction of the present value of estimated future net cash flows due to a drop in oil and gas prices and not to changes in estimates of proved reserves.

 

Carrying Value of Long-Lived Assets

 

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.

 

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 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 amounts of our properties. In accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related tax effects.  This is referred to as the “full cost ceiling limitation.”  At the end of each quarter,  a full cost ceiling limitation calculation is made.  To date, the only reduction in the carrying value of oil and gas properties was incurred during the year ended September 30, 2001, which amounted to $78.1 million.  See Note 3 of Notes to Consolidated Financial Statements.

 

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 related impairment has been recorded, nor is any currently anticipated.

 

Contingencies

 

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, 2003, no liabilities have been accrued for known contingencies.  See Note 15 of Notes to Consolidated Financial Statements.

 

25


Recent Accounting Developments

 

The FASB is currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, to companies in the extractive industries, including oil and gas companies.  The FASB is considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

 

Cimarex has included oil and gas lease acquisition costs as a component of oil and gas properties.  In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, approximately $32.4 million, less $18.2 million in accumulated depreciation, depletion and amortization, of our proved oil and gas property costs would be separately classified as intangible assets.  In addition, approximately $19.5 million of unproved properties would be classified as intangible assets.  Income and other results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules.  The classification of oil and gas lease acquisition costs as intangible assets would not have any impact on our compliance with covenants under our debt agreements.

 

Overview

 

Our results of operations are impacted by oil and gas prices, which are volatile.  Realized oil and gas prices increased from $24.97 per Bbl and $3.10 per Mcf in 2002 to $29.30 per Bbl and $4.96 per Mcf in 2003.  The majority of our revenues are from oil and gas sales, so price fluctuations can significantly affect our financial results.

 

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

 

26



 

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.

 

Basis of Presentation

 

Cimarex 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 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. (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/A unless expressly noted otherwise, include Key only for the period subsequent to the merger on September 30, 2002.

 

On September 30, 2002, Cimarex changed it fiscal year from September 30 to December 31.  As a consequence, financial statements included in this report show results of operations for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the fiscal year ended September 30, 2001.

 

27



 

RESULTS OF OPERATIONS

 

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

 

SUMMARY DATA:

 

 

 

For the Years Ended
December 31,

 

(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

 

28



 

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.

 

Costs and Expenses (Other than Income tax expense)

 

Overall costs and expenses (not including income taxes) were $176.5 million in 2003 compared to $98.6 million in 2002.  The largest component of this $77.9 million increase between years is a $39.5 million increase in total depreciation, depletion and amortization expense (DD&A) from $49.2 million in 2002 to $88.8 million in 2003, resulting from a larger asset base following the acquisition of Key and higher costs for reserves added during 2003.  On a unit of production basis, DD&A was $1.35 per Mcfe in 2003 compared to $1.02 per Mcfe for 2002.

 

Taxes other than income were $14.3 million greater, rising from $13.2 million in 2002 to $27.5 million in 2003.  This increase resulted from a 106 percent jump in oil and gas sales stemming from higher product prices and volumes.

 

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

 

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.

 

29



 

Year Ended December 31, 2002 Compared with Fiscal Year Ended September 30, 2001

 

On September 30, 2002, we changed our fiscal year end from September 30 to December 31.  As a result, we are comparing the year ended December 31, 2002 to the fiscal year ended September 30, 2001.  Each annual period discussed includes a full twelve months of operations.  The three months ended December 31, 2001 are compared to the three months ended December 31, 2000.

 

SUMMARY DATA:

 

 

 

For the Years Ended

 

(in thousands or as indicated)

 

December 31,
2002

 

September 30,
2001

 

 

 

 

 

 

 

Net income

 

$

39,819

 

$

35,253

 

Per share-basic

 

1.32

 

1.33

 

Per share-diluted

 

1.31

 

1.33

 

 

 

 

 

 

 

Gas sales

 

$

128,060

 

$

199,321

 

Oil sales

 

29,239

 

22,815

 

Total oil and gas sales

 

$

157,299

 

$

222,136

 

 

 

 

 

 

 

Total gas volume-MMcf

 

41,300

 

42,387

 

Gas volume-MMcf per day

 

113.2

 

116.1

 

Average gas price-per Mcf

 

$

3.10

 

$

4.70

 

 

 

 

 

 

 

Total oil volume-thousand barrels

 

1,171

 

818

 

Oil volume-barrels per day

 

3,209

 

2,242

 

Average oil price-per barrel

 

$

24.97

 

$

27.88

 

 

 

 

 

 

 

Marketing sales

 

$

52,350

 

$

93,877

 

Marketing purchases

 

49,671

 

87,460

 

Marketing margin

 

$

2,679

 

$

6,417

 

 

 

 

 

 

 

Reduction to carrying value of oil and gas properties

 

$

 

$

78,082

 

Depreciation, depletion and amortization

 

49,231

 

49,699

 

Production

 

19,427

 

13,091

 

Transportation

 

7,918

 

6,359

 

Taxes other than income

 

13,154

 

18,965

 

General and administrative

 

8,568

 

10,068

 

Financing costs, net

 

171

 

(1,784

)

 

On September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key in a tax-free exchange of stock.  In the acquisition, we issued approximately 14.1 million shares of our common stock for all the outstanding shares of Key common stock on that date, on a one-for-one basis.  The results of operations for Cimarex include Key beginning with the fourth quarter of 2002.  The acquisition of Key increased our proved reserves by 94.7 Bcf of gas and 9.1 MMBbls of oil, or an aggregate of 149.4 Bcfe.  The purchase price allocated to these proved oil and gas properties was approximately $285.0 million.

 

We reported net income of $39.8 million, or $1.31 per diluted share for the year ended December 31, 2002 compared to net income of $35.3 million, or $1.33 per diluted share for the year ended

 

30



 

September 30, 2001. Wide variations in gas prices between and during the years contributed both directly and indirectly to the changes in net income.  In 2002, net income grew by 13 percent compared to fiscal 2001, despite a 34 percent drop in gas prices, because fiscal 2001 results were negatively affected by a $78.1 million reduction to the carrying value of oil and gas properties stemming from a sharp drop in gas prices on September 30, 2001 compared to average prices for that year.

 

Oil and gas sales dropped $64.8 million from $222.1 million in fiscal 2001 to $157.3 million in 2002.  Gas sales decreased $71.3 million between the two periods.  Realized gas prices averaged $3.10 per Mcf for 2002, compared to $4.70 per Mcf for fiscal 2001.  This decrease in price had a negative effect on sales of $66.1 million between the two years. Average daily gas volumes decreased 2.9 MMcf in 2002 to 113.2 MMcf from 116.1 MMcf in 2001, reducing revenues by $5.1 million during 2002.  Lower gas volumes resulted from natural production declines in existing wells, though partially offset by output from new wells that were completed since September 30, 2001, and gas wells acquired through the Key acquisition.

 

Oil sales increased from $22.8 million in fiscal 2001 to $29.2 million in 2002.  Realized oil prices averaged $24.97 per barrel for 2002, compared to $27.88 per barrel for 2001.  The effect on sales between years resulting from this drop in oil prices totaled $3.4 million. The volatility in prices was the result of overall market conditions.  Daily oil volumes averaged 3,209 barrels in 2002, compared to 2,242 barrels in 2001, resulting in increased revenues of $9.8 million during 2002.  Increase in oil volumes between the two years is due to the acquisition of Key, with Key properties contributing 402 MBbls in the fourth quarter of 2002.

 

Marketing sales net of related purchases equaled $2.7 million in 2002 compared to $6.4 million in fiscal 2001. The net decrease in 2002 is due to lower average gas prices in 2002 compared to 2001.

 

Costs and Expenses (Other than Income tax expense)

 

Overall costs and expenses (not including income taxes) were $98.6 million in 2002 compared to $174.5 million in fiscal 2001.  The largest component of this $75.9 million decrease between years is the previously mentioned $78.1 million reduction in carrying value of oil and gas properties in 2001.

 

DD&A expense dropped slightly to $49.2 million in 2002 from $49.7 million in fiscal 2001.

 

Taxes other than income decreased to $13.2 million in 2002 from $19.0 million in 2001.  These taxes equate to 8.4 percent and 8.5 percent of oil and gas sales for 2002 and 2001, respectively.  The expense decreased in 2002 due to lower oil and gas prices realized during the year.

 

Production costs rose from $13.1 million in fiscal 2001 to $19.4 million in 2002.  The biggest contributing factor to the increase was the September 30, 2002 Key acquisition.

 

Financing costs increased $2.0 million due to the settlement of an ad valorem tax contingency settled for less than originally escrowed, resulting in a portion of the interest component of the settlement being reversed in fiscal 2001.

 

Smaller variances that effectively offset each other were general and administrative expenses between the two years decreasing $1.5 million and transportation expense increasing $1.5 million.

 

Income tax expense

 

Income tax expense totaled $21.6 million for 2002 versus $19.6 million for 2001.  Tax expense equaled combined Federal and state effective income tax rates of  35.1 percent in 2002 and 35.7 percent in fiscal 2001.

 

31



 

Three Months Ended December 31, 2001 Compared with Three Months Ended December 31, 2000

 

SUMMARY DATA:

 

 

 

For Three Months Ended December 31,

 

­­(in thousands or as indicated)

 

2001

 

2000

 

 

 

 

 

(unaudited)

 

Net income

 

$

4,479

 

$

27,582

 

Per share-basic

 

0.17

 

1.04

 

Per share-diluted

 

0.17

 

1.04

 

 

 

 

 

 

 

Gas sales

 

$

22,750

 

$

52,004

 

Oil sales

 

4,107

 

7,147

 

Total oil and gas sales

 

$

26,857

 

$

59,151

 

 

 

 

 

 

 

Total gas volume-MMcf

 

10,174

 

10,710

 

Gas volume-MMcf per day

 

110.6

 

116.4

 

Average gas price-per Mcf

 

$

2.24

 

$

4.86

 

 

 

 

 

 

 

Total oil volume-thousand barrels

 

206

 

230

 

Oil volume-barrels per day

 

2,236

 

2,502

 

Average oil price-per barrel

 

$

19.97

 

$

31.04

 

 

 

 

 

 

 

Marketing sales

 

$

12,655

 

$

26,795

 

Marketing purchases

 

10,994

 

22,233

 

Marketing margin

 

$

1,661

 

$

4,562

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

$

8,972

 

$

9,477

 

Production

 

4,197

 

2,638

 

Transportation

 

1,886

 

1,469

 

Taxes other than income

 

2,559

 

4,194

 

General and administrative

 

3,637

 

2,378

 

 

We reported net income of $4.5 million, or $0.17 per diluted share for the fourth quarter ended December 31, 2001 compared to net income of $27.6 million, or $1.04 per diluted share for the three months ended December 31, 2000.  The decline in net income is primarily attributable to a decrease in oil and gas sales of $32.3 million.  Commodity prices were substantially higher in the quarter ended December 31, 2000.

 

Realized gas prices averaged $2.24 per Mcf for the fourth quarter of 2001, compared to $4.86 per Mcf for the fourth quarter of 2000.  This decrease in price had a negative effect on sales of $26.7 million between the two periods. Realized oil prices averaged $19.97 per barrel for the fourth quarter in 2001, compared to $31.04 per barrel for the same period in 2000, resulting in a decrease in sales between periods of $2.3 million.

 

Oil and gas sales also decreased due to lower production volumes.  Average daily gas volumes decreased 5.8 MMcf in the fourth quarter of 2001 to 110.6 MMcf from 116.4 MMcf for the same period in 2000, resulting in lower revenues of $2.6 million during 2001.  Daily oil volumes averaged 2,236 barrels in 2001, compared to 2,502 barrels in 2000, resulting in decreased revenues of $0.7 million during 2001.  Lower gas volumes resulted from natural production declines in wells, partially offset by output from new wells that were completed during 2001.  Oil volumes between the two periods decreased due to natural production declines.

 

32



 

Marketing sales net of related purchases equaled $1.7 million for the fourth quarter in 2001 compared to $4.6 million for the same period in 2000.  Spot market prices were very volatile in November and December 2000, as gas prices were rapidly increasing to relatively high levels.  In the three months ended December 31, 2001, gas prices were substantially lower and more stable.  The $2.9 million variance in net revenues reflects less volatile market conditions that existed during the fourth quarter of 2001 when spot market sales were accomplished at prices only slightly higher than the cost of gas purchases.

 

Costs and Expenses (Other than Income tax expense)

 

Overall costs and expenses (not including income taxes) were $21.3 million in fourth quarter of 2001 compared to $20.1 million for the same period in 2000.

 

DD&A on oil and gas properties decreased slightly to $9.0 million for the fourth quarter in 2001 from $9.5 million for the same period in 2000.

 

Transportation expenses increased to $1.9 million from $1.5 million for the fourth quarters of 2001 and 2000, respectively.

 

Taxes other than income decreased to $2.6 million in the fourth quarter of 2001 from $4.2 million in the same period of 2000, due to lower oil and gas prices realized in 2001.

 

Production costs increased from $2.6 million in the fourth quarter of 2000 to $4.2 million in the same three months of 2001, due primarily to general cost increases on outside operated wells and additional compression costs.

 

G&A expenses increased from $2.4 million in the fourth quarter of 2000 to $3.6 million in the fourth quarter of 2001.  The increase is primarily due to a $0.9 million impairment of receivables from Enron Corporation and costs associated with legal proceedings.  Cimarex has no additional exposure relating to Enron as all sales to Enron were terminated at November 30, 2001.

 

Income tax expense

 

Income tax expense totaled $2.8 million for the fourth quarter of 2001 versus $16.5 million for the same period in 2000.  Tax expense was calculated using a combined Federal and state effective income tax rate of 38.2 percent in 2001 versus 37.4 percent in 2000.  The decrease in the expense between periods was a result of lower revenue resulting from lower oil and gas prices.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Cash Flows

 

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, 2003 was $206.3 million, compared to $104.5 million and $162.4 million for the years ended December 31, 2002 and September 30, 2001, respectively.  The increase in 2003 from the earlier periods results primarily from higher prices and production.

 

33



 

Higher revenues from oil and gas sales facilitated the payment of our long-term debt, funded our exploration and development expenditure program for the year, and built a larger balance of cash at year end than we held in 2002.

 

Cash flow used in investing activities for the year ended December 31, 2003 was $159.6 million, compared to $71.7 million and $101.4 million for the years ended December 31, 2002 and September 30, 2001, respectively.  The increase in 2003 stems from a larger exploration and development program.

 

Cash flow used by financing activities in 2003 was $28.6 million versus $17.6 million in 2002, an increase of $11 million.  The most significant item that occurred during 2003 was the repayment of $32.0 million of our long-term credit facility afforded by higher oil and gas prices in 2003.  Cash flows used by financing activities for the year ended September 30, 2001 were $61.4 million, $43.8 million higher than in 2002.  The decrease in cash used by financing activities in 2002 compared to fiscal year 2001 resulted from a reduction in payments to the previous parent company, H&P.

 

Financial Condition

 

As of December 31, 2003, stockholders’ equity totaled $534.7 million, up from $444.9 million at December 31, 2002.  The increase resulted primarily from 2003 net income of $94.6 million.  During 2003 we repaid all of the $32 million of long-term debt that was outstanding at year end 2002 and increased our cash balance by $18.1 million from $22.3 million at December 31, 2002 to $40.4 million at December 31, 2003.

 

Working Capital

 

Working capital at December 31, 2003 totaled $37.7 million, compared to $21.4 million at December 31, 2002.  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 $68.3 million at December 31, 2003.  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, with associated losses historically not being significant.

 

Financing

 

In October 2002, we closed on a three-year $400 million Senior Secured Revolving Credit Facility.  The Facility has a borrowing base of $275 million and we have elected a $200 million commitment amount.  The borrowing base is subject to redetermination each April and October.  Borrowings under this Facility bear interest at a LIBOR rate plus 1.25 percent to 2.00 percent, based on borrowing base usage.  Unused borrowings are subject to a commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage.  The Credit Facility is secured by mortgages on our oil and gas properties and the stock of our subsidiaries.  We are 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, 2003.  We have not sought a corporate credit rating since we have no outstanding long-term debt.

 

34



 

Contractual Obligations and Material Commitments

 

At December 31, 2003, we had contractual obligations and material commitments as follows:

 

 

 

Payments Due by Period

 

Contractual obligations

 

Total

 

Less than
1 Year

 

1-3
Years

 

3-5
Years

 

More
than
5 Years

 

Operating leases

 

$

18,172

 

$

1,715

 

$

3,898

 

$

4,236

 

$

8,323

 

Drilling commitments

 

23,682

 

23,682

 

 

 

 

Deferred income taxes(1)

 

155,293

 

 

 

 

155,293

 

Asset retirement obligation

 

16,463

 

2,804

 

1,786

 

1,655

 

10,218

 

Deferred compensation(2)

 

11,724

 

2,444

 

4,732

 

2,364

 

2,184

 

Other liabilities

 

1,779

 

158

 

120

 

115

 

1,386

 

 

 

 

 

 

 

 

 

 

 

 

 

Total obligations

 

$

227,113

 

$

30,803

 

$

10,536

 

$

8,370

 

$

177,404

 

 


(1) Deferred income taxes are projected not to be paid within the next five years, due to the anticipated drilling expenditures to be incurred during the periods.

 

(2) The deferred compensation will be paid via the issuance of shares of common stock.

 

In addition to the items in the table above, we have issued parental guarantees of $9.8 million related to our marketing business for the benefit of companies we purchase gas from.

 

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004.  We have a right to extend this contract annually.  Maximum amount that would be payable, if deliveries are not made, would be $0.3 million.

 

Additionally, we have guaranteed to deliver 2.3 Bcf of natural gas from five wells over a three-year period as reimbursement for connection costs to the pipeline.  If the minimum delivery is not met, the maximum exposure is $0.2 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 or a prorated payment based on the total reserves on 17 wells.  The maximum amount that would be payable, if we deliver no natural gas, would be $0.6 million.

 

We also have firm sales contracts to deliver fixed volumes of gas based on an index price.  These contracts vary in length from two months to one year.  As of December 31, 2003, we had an obligation to deliver approximately 3.8 Bcf of natural gas.  If this gas is not delivered, our financial commitment would be approximately $20.7 million based on index prices as of December 31, 2003.  This commitment will fluctuate due to price volatility and actual volumes delivered.  We believe no financial commitment will be due based on our reserves and current production levels.

 

All of the commitments were routine and were made in the normal course of our business.

 

Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available under our existing 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 2004 exploration and development expenditure program of $200 million will require a great deal of coordination and effort.  Though there are a variety of factors that could curtail,

 

35



 

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 2004 are estimated to approximate levels realized in 2003.  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.

 

Estimated production levels for 2004 will range between 195 to 210 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 2003, the average price realized from our gas sales was $4.96 per Mcf and $29.30 per barrel from our oil sales.  Current indications are that anticipated prices for 2004 should approximate 2003 levels.  Prices can be highly volatile, however, and the possibility of realized prices for 2004 to vary from current estimates is high.

 

 

ITEM 7A.  Qualitative and Quantitative Disclosures about Market Risk

 

Price Fluctuations

 

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 2003 ranged from a monthly low of $4.13 per Mcf and $26.34 per barrel, to a monthly high of $7.24 per Mcf and $31.31 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.

 

Interest Rate Risk

 

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 that changes in interest rates would have no affect on our results of operations.

 

36



 

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

CIMAREX ENERGY CO.

 

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

 

Independent Auditors’ Report for the years ended December 31, 2003 and 2002 and the three months ended December 31, 2001

 

Report of Independent Auditors for the year ended September 30, 2001

 

Consolidated balance sheets as of December 31, 2003 and 2002

 

Consolidated statements of operations for the years ended December 31, 2003 and 2002, and September 30, 2001 and for the three months ended December 31, 2001 and 2000

 

Consolidated statements of cash flows for the years ended December 31, 2003 and 2002, and September 30, 2001 and for the three months ended December 31, 2001

 

Consolidated statements of stockholders’ equity for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001

 

Notes to consolidated financial statements

 

 

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



 

Independent Auditors’ Report

 

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, 2003 and 2002 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2003 and 2002 and the three months ended December 31, 2001.  These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with auditing standards generally accepted in the United States of America.  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, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003 and 2002 and the three months ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

 

As discussed in Note 5 to the Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

 

 

KPMG LLP

 

 

Denver, Colorado

February 9, 2004

 

38



 

REPORT OF INDEPENDENT AUDITORS

 

The Board of Directors

Cimarex Energy Co.

 

We have audited the accompanying consolidated statements of operations, stockholder’s equity and cash flows of Cimarex Energy Co., (See Note 1) for the year ended September 30, 2001.  These financial statements are the responsibility of Cimarex Energy Co.’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with auditing standards generally accepted in the 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 audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Cimarex Energy Co. (See Note 1) for the year ended September 30, 2001, in conformity with accounting principles generally accepted in the United States.

 

 

ERNST & YOUNG LLP

 

 

Tulsa, Oklahoma

May 8, 2002, except as to the first paragraph of Note 1

as to which the date is September 30, 2002.

 

39



 

CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share information)

 

 

 

December 31,

 

 

 

2003

 

2002

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

40,420

 

$

22,327

 

Accounts receivable:

 

 

 

 

 

Trade, net of allowance

 

15,847

 

7,524

 

Oil and gas sales, net of allowance

 

21,350

 

28,222

 

Marketing, net of allowance

 

31,096

 

22,530

 

Inventories

 

6,700

 

3,986

 

Deferred income taxes

 

1,631

 

2,073

 

Other current assets

 

6,160

 

2,949

 

Total current assets

 

123,204

 

89,611

 

Oil and gas properties at cost, using the full cost method of accounting:

 

 

 

 

 

Proved properties

 

1,331,095

 

1,172,488

 

Unproved properties and properties under development, not being amortized

 

39,370

 

23,941

 

 

 

1,370,465

 

1,196,429

 

Less – accumulated depreciation, depletion and amortization

 

(746,161

)

(665,711

)

Net oil and gas properties

 

624,304

 

530,718

 

Fixed assets, less accumulated depreciation of $6,422 and $5,163

 

12,092

 

6,849

 

Goodwill

 

44,967

 

45,836

 

Other assets, net

 

941

 

1,272

 

 

 

$

805,508

 

$

674,286

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable:

 

 

 

 

 

Trade

 

$

11,146

 

$

9,500

 

Marketing

 

7,248

 

12,839

 

Accrued liabilities:

 

 

 

 

 

Exploration and development

 

16,964

 

7,415

 

Taxes other than income

 

6,362

 

3,743

 

Other

 

25,013

 

10,734

 

Revenue payable

 

18,776

 

24,022

 

Total current liabilities

 

85,509

 

68,253

 

Long-term debt

 

 

32,000

 

Deferred income taxes

 

155,293

 

127,023

 

Asset retirement obligation

 

16,463

 

 

Deferred compensation

 

11,724

 

 

Other liabilities

 

1,779

 

2,130

 

Total liabilities

 

270,768

 

229,406

 

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, 41,063,653
and 41,410,308 shares issued and outstanding, respectively

 

411

 

414

 

Paid-in capital

 

237,430

 

243,420

 

Unearned compensation

 

(9,540

)

(10,814

)

Retained earnings

 

306,439

 

211,860

 

 

 

534,740

 

444,880

 

 

 

$

805,508

 

$

674,286

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

40



 

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

 

 

 

For the Years Ended

 

For the Three Months Ended
December 31,

 

 

 

December 31,

 

September 30,
2001

 

 

 

 

2003

 

2002

 

 

2001

 

2000

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Gas sales

 

$

250,764

 

$

128,060

 

$

199,321

 

$

22,750

 

$

52,004

 

Oil sales

 

73,355

 

29,239

 

22,815

 

4,107

 

7,147

 

Marketing sales

 

130,156

 

52,350

 

93,877

 

12,655

 

26,795

 

Other

 

(63

)

(5

)

765

 

84

 

461

 

 

 

454,212

 

209,644

 

316,778

 

39,596

 

86,407

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

88,774

 

49,231

 

49,699

 

8,972

 

9,477

 

Reduction to carrying value of oil and gas properties

 

 

 

78,082

 

 

 

Accretion expense

 

1,009

 

 

 

 

 

Production

 

31,801

 

19,427

 

13,091

 

4,197

 

2,638

 

Transportation

 

7,472

 

7,918

 

6,359

 

1,886

 

1,469

 

Taxes other than income

 

27,485

 

13,154

 

18,965

 

2,559

 

4,194

 

Marketing purchases

 

129,503

 

49,671

 

87,460

 

10,994

 

22,233

 

General and administrative

 

17,526

 

8,568

 

10,068

 

3,637

 

2,378

 

Stock compensation

 

1,824

 

125

 

 

 

 

Financing costs:

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

1,285

 

620

 

(1,509

)

141

 

107

 

Capitalized interest

 

(304

)

(206

)

 

 

 

Interest income

 

(332

)

(243

)

(275

)

(43

)

(133

)

 

 

306,043

 

148,265

 

261,940

 

32,343

 

42,363

 

Income before income tax expense and cumulative effect of a change in accounting principle

 

148,169

 

61,379

 

54,838

 

7,253

 

44,044

 

Income tax expense

 

55,141

 

21,560

 

19,585

 

2,774

 

16,462

 

Income before cumulative effect of a change in accounting principle

 

93,028

 

39,819

 

35,253

 

4,479

 

27,582

 

Cumulative effect of a change in accounting principle, net of tax

 

1,605

 

 

 

 

 

Net income

 

$

94,633

 

$

39,819

 

$

35,253

 

$

4,479

 

$

27,582

 

Earnings per share:

 

 

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

Income before cumulative effect of a change in accounting principle

 

$

2.24

 

$

1.32

 

$

1.33

 

$

0.17

 

$

1.04

 

Cumulative effect of a change in accounting principle, net of tax

 

0.04

 

 

 

 

 

Net income

 

$

2.28

 

$

1.32

 

$

1.33

 

$

0.17

 

$

1.04

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

Income before cumulative effect of a change in accounting principle

 

$

2.18

 

$

1.31

 

$

1.33

 

$

0.17

 

$

1.04

 

Cumulative effect of a change in accounting principle, net of tax

 

0.04

 

 

 

 

 

Net income

 

$

2.22

 

$

1.31

 

$

1.33

 

$

0.17

 

$

1.04

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

41,521

 

30,239

 

26,591

 

26,591

 

26,591

 

Diluted

 

42,640

 

30,317

 

26,591

 

26,591

 

26,591

 

 

 

 

 

 

 

 

 

 

 

 

 

Pro forma amounts assuming new method of accounting for asset retirement obligations is applied retroactively

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

$

39,236

 

$

34,659

 

$

4,300

 

$

27,451

 

Earnings per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

 

$

1.30

 

$

1.30

 

$

0.16

 

$

1.03

 

Diluted

 

 

 

$

1.29

 

$

1.30

 

$

0.16

 

$

1.03

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

41



 

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

 

 

Years Ended

 

Three Months Ended
December 31,
2001

 

 

December 31,

 

September 30,
2001

 

 

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

Net income

 

$

94,633

 

$

39,819

 

$

35,253

 

$

4,479

 

Adjustments to reconcile net income to net cash
provided by operating activities:

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

88,774

 

49,231

 

49,699

 

8,972

 

Amortization of restricted stock compensation

 

1,914

 

125

 

 

 

Reduction to carrying value of oil and gas
properties

 

 

 

78,082

 

 

Cumulative effect of a change in accounting
principle, net of taxes

 

(1,605

)

 

 

 

Deferred income taxes

 

30,590

 

21,428

 

(11,138

)

2,805

 

Asset retirement obligation accretion

 

1,009

 

 

 

 

Income tax benefit related to stock options
exercised

 

1,203

 

 

 

 

Other

 

433

 

58

 

(167

)

(241

)

Change in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

(Increase) decrease in accounts receivable

 

(10,123

)

(15,996

)

9,658

 

7,387

 

(Increase) decrease in inventories

 

(2,714

)

1,770

 

(1,994

)

541

 

(Increase) decrease in other current assets

 

(3,242

)

(934

)

6,373

 

(396

)

Decrease in other assets

 

 

 

164

 

 

Increase (decrease) in accounts payable

 

(9,310

)

17,010

 

5,550

 

(16,656

)

Increase (decrease) in accrued liabilities

 

15,626

 

(8,321

)

(9,370

)

(3,319

)

Increase (decrease) in other noncurrent liabilities

 

(875

)

265

 

248

 

32

 

Net cash provided by operating activities

 

206,313

 

104,455

 

162,358

 

3,604

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

Capital expenditures

 

(150,501

)

(66,458

)

(100,201

)

(14,667

)

Acquisition of proved oil and gas properties

 

(2,032

)

 

 

 

Merger costs

 

 

(5,079

)

 

 

Cash received in connection with acquisition

 

 

2,135

 

 

 

Proceeds from sale of assets

 

1,041

 

313

 

205

 

681

 

Other capital expenditures

 

(8,149

)

(2,596

)

(1,387

)

(345

)

Net cash used by investing activities

 

(159,641

)

(71,685

)

(101,383

)

(14,331

)

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

 

(8

)

 

 

 

Net (distributions to) contributions from
Helmerich & Payne, Inc.

 

 

 

(61,430

)

4,808

 

Change in amount due (to) from Helmerich & Payne, Inc.

 

 

(13,089

)

 

13,089

 

Proceeds from issuance of common stock

 

3,429

 

403

 

 

 

Net cash provided by (used in) financing activities

 

(28,579

)

(17,613

)

(61,430

)

17,897

 

Net increase (decrease) in cash and cash equivalents

 

18,093

 

15,157

 

(455

)

7,170

 

Cash and cash equivalents at beginning of period

 

22,327

 

7,170

 

455

 

 

Cash and cash equivalents at end of period

 

$

40,420

 

$

22,327

 

$

 

$

7,170

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

42



 

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

 

 

 

Common Stock

 

Paid-in
Capital

 

Unearned
Compensation

 

Retained
Earnings

 

Total
Stockholders’
Equity

 

 

Shares

 

Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, September 30, 2000

 

26,591

 

$

266

 

$

 

$

 

$

192,706

 

$

192,972

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

35,253

 

35,253

 

Net distributions to Helmerich & Payne, Inc.

 

 

 

 

 

(61,430

)

(61,430

)

Balance, September 30, 2001

 

26,591

 

266

 

 

 

166,529

 

166,795

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

4,479

 

4,479

 

Net contributions from Helmerich & Payne, Inc.

 

 

 

 

 

3,808

 

3,808

 

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

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

43



 

CIMAREX ENERGY CO.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.                                      BASIS OF PRESENTATION

 

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.

 

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.

 

2.                                      DESCRIPTION OF BUSINESS

 

Cimarex is an independent oil and gas exploration and production company.  Our principal areas of operations are located in Oklahoma, Kansas, Texas and Louisiana.

 

44



 

3.                                      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Cash and Cash Equivalents

 

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

 

Inventories, primarily materials and supplies, are valued at the lower of cost or market.

 

Oil and Gas Properties

 

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 oil and gas properties as well as other internal costs that can be directly identified with acquisition, exploration and development activities are also capitalized.  Capitalized costs including estimated future development and abandonment costs are amortized using the unit-of-production method.

 

In accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related tax effects (the “full cost ceiling limitation”).  If capitalized costs exceed this limit, the excess must be charged to expense.  The expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation.  The Company recorded a reduction in the carrying value of oil and gas properties of $78.1 million during the year ended September 30, 2001.

 

The costs of certain unevaluated properties are not being amortized.  On a quarterly basis, such costs are evaluated for transfer to the full cost pool 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 adjustments of capitalized costs to the proved oil and gas properties with no losses recognized.

 

Expenditures for maintenance and repairs are charged to production expense in the period incurred.  Proceeds from the sale of oil and gas properties are credited against capitalized costs, unless such proceeds would significantly alter the amortization base.

 

Goodwill

 

Cimarex recorded goodwill in 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.  However, these assets are reviewed for impairment once a year and when circumstances indicate that an impairment may have occurred.  The evaluation of the estimated fair value of the goodwill is performed on individual

 

45



 

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 the exploration and production segment of our business is based on numerous factors, each individually weighted, to estimate total reporting unit estimated fair value.  If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered 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 of the implied goodwill amount compared to the carrying value of goodwill is recorded as an impairment up to 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 prohibited.

 

Revenue Recognition

 

Cimarex recognizes revenues from oil and gas sales based on actual volumes of oil and gas sold to purchasers.

 

Gas Imbalances

 

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, 2003 and 2002, Cimarex had reduced reserves by 465 MMcf and 420 MMcf, respectively.  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, 2003 and 2002 was $1.4 million and $0.9 million, respectively.

 

Transportation Costs

 

                                                Cimarex accounts for transportation costs under Emerging Issues Task Force (“EITF”) 00-10 Accounting for Shipping and Handling Fees and Costs, whereby 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 themselves the

 

46



 

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.

 

Stock Options

 

We apply Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants and grants of restricted stock.  No compensation cost has been recognized for stock options granted as the option prices were the same as the market price of the underlying common stock on the date of grant.

 

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 our stock option plans 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 the plan 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 2003 and 2002.  For periods prior to the spin off and the issuance of stock options in exchange for H&P options held by employees, pro forma compensation expense was based on the estimated fair value of the H&P options (in thousands except per share amounts).

 

 

 

Years Ended

 

Three Months
Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

Net income, as reported

 

$

94,633

 

$

39,819

 

$

35,253

 

$

4,479

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Less:  Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects

 

2,352

 

1,328

 

1,270

 

318

 

 

 

 

 

 

 

 

 

 

 

Pro forma net income

 

$

92,281

 

$

38,491

 

$

33,983

 

$

4,161

 

 

 

 

 

 

 

 

 

 

 

Earnings per share:

 

 

 

 

 

 

 

 

 

Basic – as reported

 

$

2.28

 

$

1.32

 

$

1.33

 

$

0.17

 

Basic – pro forma

 

$

2.22

 

$

1.27

 

$

1.28

 

$

0.16

 

 

 

 

 

 

 

 

 

 

 

Diluted – as reported

 

$

2.22

 

$

1.31

 

$

1.33

 

$

0.17

 

Diluted – pro forma

 

$

2.16

 

$

1.27

 

$

1.28

 

$

0.16

 

 

47



 

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 2003 and 2002, and fiscal 2001 were $7.64, $8.16 and $6.56, respectively, and was $6.21 for grants made in the quarter ended December 31, 2001. 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

 

Three Months
Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

Expected years until exercise

 

7.5

 

7.5

 

4.5

 

4.5

 

Expected stock volatility

 

26.7

%

38.9

%

43.1

%

47.7

%

Dividend yield

 

0.0

%

0.0

%

0.0

%

0.0

%

Risk-free interest rate

 

3.2

%

3.8

%

5.2

%

4.0

%

 

Earnings per Share

 

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 reflects the impact of potentially dilutive securities on weighted average number of shares.

 

Fair Value of Financial Instruments

 

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, 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.  At December 31, 2002, the allowance for doubtful trade accounts was $0.3 million and the allowance for marketing receivables was $0.7 million.

 

Comprehensive Income

 

Cimarex applies the provisions of SFAS No. 130, Reporting Comprehensive Income. Cimarex had no comprehensive income for the periods presented.

 

4.                                      ACQUISITION OF KEY PRODUCTION COMPANY, INC.

 

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.

 

48



 

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 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
Ended
December 31,
2001

 

 

 

December 31,
2002

 

September 30,
2001

 

 

 

(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

 

 

5.                                      ASSET RETIREMENT OBLIGATIONS

 

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.

 

49


The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the year ended December 31, 2003 (in thousands):

 

Initial adoption amount as of January 1, 2003

 

$

13,784

 

 

 

 

 

Liabilities incurred in the current period

 

1,929

 

Liabilities settled in the current period

 

(259

)

Accretion expense

 

1,009

 

 

 

 

 

Balance as of December 31, 2003

 

$

16,463

 

 

6.                                      LONG-TERM DEBT

 

At December 31, 2003, we had no debt outstanding.  We have the capability to borrow on our $400 million Senior Secured Revolving Credit Facility led by Bank One, N.A.  This facility presently has a borrowing base of $275 million and we have commitments from our lenders totaling $200 million.  The borrowing base is subject to redetermination each April and October.

 

Borrowings under this facility bear interest at a LIBOR rate plus 1.25 to 2.00 percent, based on borrowing base usage.  Unused borrowings are subject to a commitment fee of 0.375 to 0.50 percent, also depending on the borrowing base usage.

 

The credit facility is secured by mortgages on certain of our oil and gas properties and the stock of our operating subsidiaries.  We are also subject to customary financial and non-financial covenants and are in compliance with those covenants.  The term of the credit facility expires in October 2005.

 

7.                                      INCOME TAXES

 

Federal income tax expense for the years ended December 31, 2003 and 2002, September 30, 2001 and the three months ended December 31, 2001 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.

 

Key’s final tax basis has been determined resulting in an increase of $3.9 million from the original estimate made at the time of the merger with Cimarex.  The increase was accounted for at the statutory tax rate of 38 percent and resulted in an adjustment to reduce goodwill by $1.5 million.

 

50



 

The components of the provision for income taxes are as follows (in thousands):

 

 

 

Years Ended

 

Three Months
Ended
December 31,
2001

 

December 31,

 

September 30,
2001

 

2003

 

2002

 

Current taxes:

 

 

 

 

 

 

 

 

 

Federal

 

$

21,136

 

$

 

$

27,219

 

$

103

 

State

 

3,415

 

132

 

3,504

 

(134

)

 

 

24,551

 

132

 

30,723

 

(31

)

Deferred taxes

 

30,590

 

21,428

 

(11,138

)

2,805

 

 

 

$

55,141

 

$

21,560

 

$

19,585

 

$

2,774

 

 

Reconciliations of the income tax expense at the federal statutory rate to the total income tax expense are as follows (in thousands):

 

 

 

Years Ended

 

Three Months Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

Provision at statutory rate

 

$

51,859

 

$

21,482

 

$

19,193

 

$

2,539

 

Effect of state taxes

 

3,254

 

1,841

 

1,024

 

218

 

Non-conventional fuel source credits utilized

 

 

(313

)

(367

)

(92

)

Excess statutory depletion

 

 

(271

)

(323

)

(81

)

Deductible merger related costs

 

 

(1,178

)

 

 

Other

 

28

 

(1

)

58

 

190

 

Income tax expense

 

$

55,141

 

$

21,560

 

$

19,585

 

$

2,774

 

 

51



 

The components of Cimarex’s net deferred tax liabilities are as follows (in thousands):

 

 

 

December 31,

 

 

 

2003

 

2002

 

Long-term:

 

 

 

 

 

Assets -

 

 

 

 

 

Net operating loss carryforwards

 

$

3,921

 

$

323

 

Credit carryforwards

 

1,207

 

3,256

 

Long-term assets and liabilities

 

4,374

 

1,756

 

 

 

9,502

 

5,335

 

Liabilities:

 

 

 

 

 

Property, plant and equipment

 

(164,795

)

(132,358

)

Net, long-term deferred tax liability

 

(155,293

)

(127,023

)

 

 

 

 

 

 

Current:

 

 

 

 

 

Net current deferred tax assets

 

1,631

 

2,073

 

Net deferred tax liabilities

 

$

(153,662

)

$

(124,950

)

 

A net tax operating loss carryforward of approximately $10.3 million exists at December 31, 2003, which expires in the years 2010 through 2022.  These net operating losses (NOLs) were acquired as part of an acquisition, and therefore, are subject to annual limitations.  We believe all NOLs will be utilized before they expire.  An alternative minimum tax credit carryfoward of approximately $1.2 million exists at December 31, 2003.

 

We have recorded a deferred tax asset of $11.1 million of which $3.9 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 asset will be realized.

 

8.                                      STOCK PLANS

 

Stock Options

 

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

 

52



 

economic interest of option holders before and after the spin off was unchanged and the spin off from 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, 2003, and changes during the year:

 

 

 

Options
Outstanding

 

Weighted
Average
Exercise
Price

 

Options
Exercisable

 

 

 

 

 

 

 

 

 

H&P Activity:

 

 

 

 

 

 

 

Outstanding as of September 30, 2000

 

643,778

 

$

23.81

 

 

 

Granted

 

216,000

 

32.31

 

 

 

Exercised

 

(190,830

)

22.76

 

 

 

Forfeited/Expired

 

(6,250

)

27.11

 

 

 

Outstanding as of September 30, 2001

 

662,698

 

26.82

 

160,064

 

Granted

 

205,000

 

29.78

 

 

 

Exercised

 

(4,050

)

16.15

 

 

 

Forfeited/Expired

 

(5,250

)

27.94

 

 

 

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

 

 

 

Acquired 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

 

 

53



 

The following table summarizes information about Cimarex stock options held by employees and directors at December 31, 2003:

 

 

 

Outstanding Stock Options

 

Exercisable Stock Options

 

Range of Exercise Prices

 

Options

 

Weighted-
Average
Remaining
Contractual
Life

 

Weighted-
Average
Exercise
Price

 

Options

 

Weighted-
Average
Exercise
Price

 

$6.11 to $8.14

 

182,298

 

4.7 Years

 

$

7.81

 

182,298

 

$

7.81

 

$8.15 to $10.17

 

177,500

 

5.7 Years

 

9.69

 

177,500

 

9.69

 

$10.18 to $12.21

 

534,472

 

4.4 Years

 

11.52

 

534,472

 

11.52

 

$12.22 to $14.25

 

579,585

 

6.9 Years

 

13.61

 

379,741

 

13.40

 

$14.26 to $16.28

 

352,923

 

6.9 Years

 

15.20

 

248,745

 

15.20

 

$16.29 to $18.32

 

1,425,521

 

8.4 Years

 

16.77

 

424,604

 

16.96

 

$18.33 to $20.36

 

69,000

 

8.1 Years

 

19.32

 

45,000

 

18.77

 

 

Restricted Stock and Units

 

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 and 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. 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 29,087 shares of restricted stock and 688,600 restricted stock units outstanding as of December 31, 2003.  There were 674,973 shares of restricted stock outstanding as of December 31, 2002.

 

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 granted. Compensation cost is being recognized over the associated vesting period. For the year ended December 31, 2003 and 2002, we recorded compensation expense of $1.8 million, net of $0.6 million capitalized to oil and gas properties, and $0.2 million, respectively.

 

Stockholder Rights Plan

 

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.

 

54



 

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.

 

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.

 

9.                                      EARNINGS PER SHARE

 

The calculations of basic and diluted net earnings per common share for the years ended December 31, 2003 and 2002, and September 30, 2001 and the three months ended December 31, 2001 are presented in the table below (in thousands, except per share data):

 

 

 

Years Ended

 

Three Months
Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

Basic earnings per share:

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

94,633

 

$

39,819

 

$

35,253

 

$

4,479

 

Weighted average basic share outstanding

 

41,521

 

30,239

 

26,591

 

26,591

 

Basic earnings per share

 

$

2.28

 

$

1.32

 

$

1.33

 

$

0.17

 

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

94,633

 

$

39,819

 

$

35,253

 

$

4,479

 

Weighted average basic shares outstanding

 

41,521

 

30,239

 

26,591

 

26,591

 

Incremental shares assuming the exercise of stock options and vesting of restricted stock units

 

1,119

 

78

 

 

 

Weighted average diluted shares outstanding

 

42,640

 

30,317

 

26,591

 

26,591

 

Diluted earnings per share

 

$

2.22

 

$

1.31

 

$

1.33

 

$

0.17

 

 

There were stock options outstanding for 3,321,299 and 3,632,087 shares of Cimarex common stock at December 31, 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



 

10.                               EMPLOYEE BENEFIT PLANS

 

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 $3.8 million and $1.9 million, $1.1 million, and $0.3 million in the years ended December 31, 2003 and 2002, and September 30, 2001 and the three months ended December 31, 2001, respectively.

 

11.                               RELATED PARTY TRANSACTIONS

 

H&P provides contract drilling services to Cimarex through its wholly owned subsidiary, Helmerich & Payne International Drilling Company.  Drilling costs of approximately $4.6 million and $1.4 million were incurred by Cimarex related to such services for the years ended December 31, 2003 and 2002, respectively.  During the fiscal year ended September 30, 2001 and the three months ended December 31, 2001, related drilling costs were $4.5 million and $0.3 million, 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 and the three months ended December 31, 2001, non-cash distributions of $0.1 million, $2.9 million and $1.0 million, respectively, were made to H&P pursuant to the tax sharing agreement.

 

12.                               MAJOR CUSTOMERS

 

During 2003, we sold oil and gas production representing 10.3 percent of revenues to OGE Energy Resources, Inc.  For the years ended December 31, 2002 and September 30, 2001 and the three months ended December 31, 2001, no purchasers represented more than 10 percent of our revenues.  Alternative purchasers are readily available; therefore, we believe the loss of OGE Energy as a purchaser would not have a material adverse effect on our revenues.

 

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. This 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.

 

13.                               SEGMENT INFORMATION

 

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, 2003 and 2002, and September 30, 2001 and the three months ended December 31, 2001 is shown in the following table (in thousands):

 

 

 

External
Sales

 

Operating
Profit
Before
Income
Taxes

 

DD&A
and
Reduction
in
Carrying
Value of
Oil and
Gas
Properties

 

Total
Assets

 

Additions
to Long-
Lived
Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended September 30, 2001:

 

 

 

 

 

 

 

 

 

 

 

Exploration and Production

 

$

222,901

 

$

51,638

 

$

127,611

 

$

231,606

 

$

101,319

 

Natural Gas Marketing

 

93,877

 

5,254

 

170

 

14,606

 

269

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

316,778

 

$

56,892

 

$

127,781

 

$

246,212

 

$

101,588

 

Three Months Ended December 31, 2001:

 

 

 

 

 

 

 

 

 

 

 

Exploration and Production

 

$

26,941

 

$

6,694

 

$

8,927

 

$

239,882

 

$

14,834

 

Natural Gas Marketing

 

12,655

 

459

 

45

 

12,084

 

178

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

39,596

 

$

7,153

 

$

8,972

 

$

251,966

 

$

15,012

 

 

57



 

 

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

 

Three Months
Ended
December 31,
2001

 

 

December 31,

 

September 30,
2001

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

Segment operating profit including depreciation, depletion and amortization

 

$

148,881

 

$

61,555

 

$

56,892

 

$

7,153

 

 

 

 

 

 

 

 

 

 

 

Unallocated amounts:

 

 

 

 

 

 

 

 

 

Other revenue (loss)

 

(63

)

(5

)

 

198

 

General and administrative expense allocated from H&P

 

 

 

(3,839

)

 

Interest expense, net

 

(649

)

(171

)

1,785

 

(98

)

 

 

$

148,169

 

$

61,379

 

$

54,838

 

$

7,253

 

 

14.                               SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands)

 

 

 

For the Years Ended

 

Three Months
Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

 

Cash paid during the period for:

 

 

 

 

 

 

 

 

 

Interest (net of amounts capitalized)

 

$

830

 

$

69

 

$

3,358

 

$

55

 

Income taxes (net of refunds received)

 

$

21,382

 

$

14

 

$

30,670

 

$

 

 

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.

 

15.                               COMMITMENTS AND CONTINGENCIES

 

Litigation

 

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 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 its 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

 

58



 

interest share of any actual damages attributable to the alleged drainage.  We have received confirmation from the court that any claim against Cimarex will be limited to our proportionate interest in the two properties.  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 matters in the normal course of business, none of which are material, individually or in aggregate.  We are also party to certain litigation items as plaintiffs that could result in potential gains of between $2.5 million to $3.0 million, net to our interest.

 

Leases

 

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 $2.1 million and $0.6 million for the years ended December 31, 2003 and 2002, respectively, and $0.3 million for the year ended September 30, 2001 and $0.1 million for the three months ended December 31, 2001.

 

The following table summarizes the future minimum lease payments under all noncancelable operating lease obligations.

 

Year Ending December 31,

 

Future
Minimum Lease
Payments

 

 

 

(In thousands)

 

 

 

 

 

2004

 

$

1,715

 

2005

 

1,826

 

2006

 

2,072

 

2007

 

2,106

 

2008

 

2,130

 

2009 and thereafter

 

8,323

 

 

 

$

18,172

 

 

Transportation and Gas Deliveries

 

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004.  We have a right to extend this contract annually.  The maximum amount that would be payable, if deliveries are not made, would be $0.3 million.

 

Additionally, we have guaranteed to deliver 2.3 Bcf of natural gas from five wells over a three-year period as reimbursement for connection costs to the pipeline.  If the minimum delivery is not met, our maximum exposure is less than $0.2 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 or a prorated payment based on the total reserves on 17 wells.  The maximum amount that would be payable, if no gas is delivered, would be $0.6 million.

 

We also have firm sales contracts to deliver fixed volumes of gas based on an index price.  These contracts vary in length from two months to one year.  As of December 31, 2003, we had an obligation to

 

59



 

deliver approximately 3.8 Bcf of natural gas.  If this gas is not delivered, our financial commitment would be approximately $20.7 million based on index prices as of February 1, 2004.  This commitment will fluctuate due to price volatility and actual volumes delivered.  We believe no financial commitment will be due based on our reserves and current production levels.

 

Tax Sharing Agreement

 

On September 30, 2002, Cimarex entered into an agreement with H&P that imposes certain restrictions on Cimarex’s ability to redeem or issue a material number of shares of its common stock or to undergo a change of control.  These restrictions expire on October 1, 2004.  Such actions by Cimarex could cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially resulting in a substantial amount of taxable income to H&P.  Under the terms of the agreement, if Cimarex takes or permits an action to be taken that causes the spin off to be taxable, Cimarex would generally be liable for all or a portion of the resultant tax liability.  It is expected that any such taxes allocated to Cimarex would be material.

 

Cimarex has also provided indemnification of H&P in connection with any future tax claims that may be made relating to the oil and gas exploration and production assets contributed to Cimarex by H&P.

 

Other

 

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2003 of approximately $23.7 million.

 

Parental Guarantees

 

Cimarex has approximately $9.8 million of parental guarantees outstanding.  These guarantee the credit of various CESI agreements and are for the benefit of counterparties from which CESI purchases gas.

 

16.                               SUPPLEMENTAL OIL AND GAS DISCLOSURES

 

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 statutory tax rate for the period.

 

60



 

 

 

Years Ended

 

Three Months
Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

 

 

(In thousands, except per Mcfe data)

 

 

 

 

 

 

 

 

 

 

 

Oil and gas revenues from production

 

$

324,119

 

$

157,299

 

$

223,026

 

$

26,857

 

Less operating costs and income taxes:

 

 

 

 

 

 

 

 

 

Depletion

 

86,390

 

48,272

 

48,931

 

8,792

 

Asset retirement obligation accretion

 

1,009

 

 

 

 

Reduction to carrying value of oil and gas properties

 

 

 

78,082

 

 

Production

 

31,801

 

19,427

 

13,091

 

4,197

 

Transportation

 

7,472

 

7,918

 

6,359

 

1,886

 

Taxes other than income

 

27,485

 

13,154

 

18,965

 

2,559

 

Income taxes

 

63,226

 

25,356

 

20,574

 

3,357

 

 

 

217,383

 

114,127

 

186,002

 

20,791

 

Results of operations from oil and gas producing activities

 

$

106,736

 

$

43,172

 

$

37,024

 

$

6,066

 

Amortization rate per Mcfe

 

$

1.32

 

$

1.00

 

$

1.03

 

$

0.77

 

 

Costs Incurred – The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities (in thousands).

 

 

 

Year Ended

 

Three Months
Ended
December 31,
2001

 

 

 

December 31,

 

September 30,
2001

 

 

2003

 

2002

Costs incurred during the year:

 

 

 

 

 

 

 

 

 

Acquisition of properties

 

 

 

 

 

 

 

 

 

Proved

 

$

2,032

 

$

286,041

 

$

738

 

$

 

Unproved

 

9,330

 

16,008

 

18,612

 

850

 

Exploration

 

50,350

 

29,181

 

44,166

 

7,296

 

Development

 

100,915

 

37,273

 

41,459

 

6,279

 

Oil and gas expenditures

 

162,627

 

368,503

 

104,975

 

14,425

 

Property sales

 

(694

)

(151

)

(977

)

 

Asset retirement obligation (Adoption)

 

10,428

 

 

 

 

Asset retirement obligation (Additions)

 

1,675

 

 

 

 

 

 

$

174,036

 

$

368,352

 

$

103,998

 

$

14,425

 

 

Costs Not Being Amortized – The following table summarizes oil and gas property costs not being amortized at December 31, 2003, by year that the costs were incurred (in thousands):

 

2003

 

$

29,743

 

2002

 

4,838

 

2001

 

3,393

 

2000 and prior

 

1,396

 

 

 

$

39,370

 

 

61



 

We expect the majority of these costs to be evaluated, and to become subject to amortization within the next five years.

 

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, 2003 and 2002.  Netherland, Sewell & Associates, Inc., independent petroleum engineers,  prepared the proved reserve estimates as of September 30, 2001.  The estimates of proved reserves as of December 31, 2001 were prepared by H&P.

 

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, 2003, 2002 and 2001 and at September 30, 2001 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, 2003

 

December 31, 2002

 

December 31, 2001

 

September 30, 2001

 

 

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

 

 

(MMcf)

 

(MBbl)

 

(MMcf)

 

(MBbl)

 

(MMcf)

 

(MBbl)

 

(MMcf)

 

(MBbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves - Developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

318,627

 

15,025

 

212,326

 

5,304

 

216,337

 

5,932

 

262,498

 

6,305

 

Revisions of previous estimates

 

6,699

 

41

 

31,153

 

1,094

 

1,260

 

(432

)

(17,018

)

(700

)

Extensions and discoveries

 

61,545

 

1,625

 

21,064

 

643

 

4,903

 

10

 

12,748

 

1,145

 

Purchases of reserves

 

1,320

 

43

 

95,388

 

9,155

 

 

 

496

 

 

Production

 

(50,552

)

(2,504

)

(41,300

)

(1,171

)

(10,174

)

(206

)

(42,387

)

(818

)

Sales of properties

 

(295

)

(93

)

(4

)

 

 

 

 

 

End of year

 

337,344

 

14,137

 

318,627

 

15,025

 

212,326

 

5,304

 

216,337

 

5,932

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves

 

336,230

 

13,876

 

318,452

 

14,765

 

211,874

 

4,607

 

213,931

 

5,213

 

 

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.

 

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

 

62



 

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,

 

September 30,
2001

 

 

 

2003

 

2002

 

2001

 

 

Cash inflows

 

$

2,258,337

 

$

1,742,435

 

$

560,439

 

$

467,886

 

Production costs

 

(562,124

)

(511,168

)

(189,216

)

(167,914

)

Development costs

 

(16,014

)

(6,909

)

(3,961

)

(6,789

)

Income tax expense

 

(554,746

)

(361,423

)

(89,562

)

(81,253

)

Net cash flow

 

1,125,453

 

862,935

 

277,700

 

211,930

 

10% annual discount rate

 

(413,872

)

(329,076

)

(95,135

)

(67,891

)

Standardized measure of discounted future net cash flow

 

$

711,581

 

$

533,859

 

$

182,565

 

$

144,039

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flow before income taxes

 

$

1,030,340

 

$

741,209

 

$

241,150

 

$

191,240

 

 

The following are the principal sources of change in the Standardized Measure (in thousands):

 

 

 

December 31,

 

September 30,
2001

 

 

 

2003

 

2002

 

2001

 

 

Standardized measure, beginning of period

 

$

533,859

 

$

182,565

 

$

144,039

 

$

488,071

 

Sales, net of production costs

 

(257,362

)

(116,801

)

(18,215

)

(179,776

)

Net change in sales prices, net of production costs

 

202,135

 

200,935

 

52,126

 

(400,679

)

Extensions, discoveries, and improved recovery, net of future production and development costs

 

266,128

 

62,648

 

9,669

 

29,387

 

Net change in future development costs

 

2,120

 

4,039

 

3,691

 

27,978

 

Revision of quantity estimates

 

16,038

 

70,532

 

(1,305

)

(15,298

)

Accretion of discount

 

74,121

 

24,115

 

19,124

 

68,021

 

Change in income taxes

 

(111,409

)

(148,765

)

(11,385

)

160,776

 

Purchases of reserves in place

 

4,174

 

297,394

 

 

619

 

Sales of properties

 

(837

)

(1

)

 

 

Settlement of asset retirement obligation

 

(259

)

 

 

 

Change in production rates and other

 

(17,127

)

(42,802

)

(15,179

)

(35,060

)

 

 

 

 

 

 

 

 

 

 

Standardized measure end of period

 

$

711,581

 

$

533,859

 

$

182,565

 

$

144,039

 

 

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.

 

63



 

The following average prices were used in determining the Standardized Measure as of:

 

 

 

December 31,

 

September 30,
2001

 

 

 

2003

 

2002

 

2001

 

 

Price per Mcf

 

$

5.54

 

$

4.22

 

$

2.23

 

$

1.90

 

Price per Bbl

 

$

30.49

 

$

28.56

 

$

18.10

 

$

20.25

 

 

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.

 

64



 

17.                               UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

 

 

 

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.

 

65



 

ITEM 9.                                                 CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

 

ITEM 9A.                                            CONTROLS AND PROCEDURES

 

As of the end of the period covered by this report, with the participation of management, Cimarex’s Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of Cimarex’s disclosure controls and procedures (as defined in Securities Exchange Act Rules 13a-14(c) and 15(d)-14(c)) to ensure that information required to be disclosed by Cimarex under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.  Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Cimarex’s disclosure controls and procedures are effective.

 

There were no significant changes in Cimarex’s internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date.

 

66



 

PART III

 

ITEM 10.                                              DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX

 

Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders.  The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004.  Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report.

 

ITEM 11.                                              EXECUTIVE COMPENSATION

 

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders.  The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004.

 

ITEM 12.                                              SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

 

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders.  The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004.

 

ITEM 13.                                              CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

 

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders.  The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004.

 

ITEM 14.                                            PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders.  The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004.

 

67



 

PART IV

 

ITEM 15.                                            EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

 

(a)

(1)

The following financial statements are included in Item 8 to this 10-K/A:

 

 

Consolidated balance sheets as of December 31, 2003 and 2002

 

 

Consolidated statements of operations for the years ended December 31, 2003
and 2002, September 30, 2001 and for the three months ended December 31, 2001
and 2000

 

 

Consolidated statements of cash flows for the years ended December 31, 2003
and 2002, September 30, 2001 and for the three months ended December 31, 2001

 

 

Consolidated statements of stockholders’ equity for the year ended December 31,
2003 and 2002, the three months ended December 31, 2001, and the year ended
September 30, 2001

 

 

 

 

 

Notes to consolidated financial statements

 

 

 

 

 

(2)

Financial statement schedules – None

 

 

 

 

 

(3)

Exhibits:

 

 

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.

 

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).

 

 

 

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.

 

 

 

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.

 

 

 

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).

 

 

 

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).

 

68



 

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.  (Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002, file no. 001-31446).

 

 

 

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 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 2003, file no. 001-31446).

 

 

 

10.3

 

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).

 

 

 

10.4

 

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).

 

 

 

10.5

 

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).

 

 

 

10.6

 

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).

 

 

 

10.7

 

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).+

 

 

 

10.8

 

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).+

 

 

 

10.9

 

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).+

 

 

 

10.10

 

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).+

 

 

 

10.11

 

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).+

 

69



 

10.12

 

Change of Control Agreement, dated April 11, 2002, by and between Steven R. Shaw and Helmerich & Payne, Inc. (filed as Exhibit 10.10 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

 

 

 

10.13

 

Key Production Company, Inc. Income Continuance Plan, dated effective June 1, 1994 (incorporated by reference to Exhibit 10.18 to Key Production Company, Inc.’s Form 10-K for the fiscal year ended December 31, 1992, file no.   0-17162).+

 

 

 

10.14

 

Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. (incorporated by reference to Exhibit 10.14 to the Registrant’s From 10-K for the fiscal year ended December 31, 2002, file no. 001-31446).+

 

 

 

10.15

 

Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective March 3, 2003). (incorporated by reference to Exhibit 10.15 to the Registrant’s Form 10-K for the fiscal year ended December 31, 2002, file no. 001-31446). +

 

 

 

14.1

 

Code of Ethics for Chief Executive Officer and Senior Financial Officers*

 

 

 

21.1

 

Subsidiaries of the Registrant*

 

 

 

23.1

 

Consent of KPMG LLP.*

 

 

 

23.2

 

Consent of Ernst & Young LLP.*

 

 

 

23.3

 

Consent of Ryder Scott Company, LP.*

 

 

 

23.4

 

Consent of Netherland, Sewell & Associates, Inc.*

 

 

 

24.1

 

Power of Attorney of directors of the Registrant.*

 

 

 

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.*

 

 

 

31.2

 

Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

 

 

 

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.*

 

 

 

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 filed October 8, 2003, provided an update of operations.

 

 

 

 

 

Form 8-K filed November 5, 2003, announcing financial and operating results for the third quarter and first nine months of 2003.

 

70



 

SIGNATURE

 

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 11, 2004

 

 

CIMAREX ENERGY CO.

 

 

 

 

 

By:

/s/ F.H. Merelli

 

 

 

F.H. Merelli

 

 

Chairman, President and Chief Executive

 

 

Officer

 

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.

 

Signature

 

Title

 

Date

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director, Chairman, President and Chief 

 

March 11, 2004

 

 F.H. Merelli

 

Executive Officer

 

 

 

 

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 /s/ Paul Korus

 

Vice President, Chief Financial Officer

 

March 11, 2004

 

 Paul Korus

 

Corporate Secretary and Treasurer

 

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 /s/ James H. Shonsey

 

Controller, Chief Accounting Officer

 

March 11, 2004

 

 James H. Shonsey

 

(Principal Accounting Officer)

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 Glenn A. Cox

 

 

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 Cortlandt S. Dietler

 

 

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 Hans Helmerich

 

 

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 David A. Hentschel

 

 

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 Paul D. Holleman

 

 

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 L.F. Rooney, III

 

 

 

 

 

 

71



 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 Michael J. Sullivan

 

 

 

 

 

 

 

 

 

 

 

 /s/ F.H. Merelli

 

Director

 

March 11, 2004

 

 Attorney-in-Fact

 

 

 

 

 

 L. Paul Teague

 

 

 

 

 

 

72