Annual Reports

  • 10-K (Apr 30, 2009)
  • 10-K (Mar 16, 2009)
  • 10-K (Apr 29, 2008)
  • 10-K (Mar 13, 2008)
  • 10-K (Mar 12, 2007)
  • 10-K (Mar 14, 2006)

 
Quarterly Reports

 
8-K

 
Other

Edge Petroleum 10-K 2007

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x

 

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

 

 

 

For the fiscal year ended December 31, 2006

 

 

 

OR

 

 

 

o

 

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

 

For the transition period from         to         

Commission file number:  0-22149

EDGE PETROLEUM CORPORATION

(Exact name of Registrant as specified in its charter)

Delaware

 

76-0511037

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

 

 

1301 Travis, Suite 2000

 

 

Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip code)

 

713-654-8960

(Registrant’s telephone number, including area code)


Securities registered pursuant to Section 12(b) of the Act:

Title of each class

 

Name of each exchange on which registered

Common Stock, Par Value $0.01 Per Share

 

NASDAQ

5.75% Series A Cumulative Convertible Perpetual

 

NASDAQ

Preferred Stock, Par Value $0.01 Per Share

 

 

 

Securities registered pursuant to Section 12(g) of the Act:  None


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

o Yes  x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

¨ Yes  x No

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.        x Yes  o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.       x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and larger accelerated filer” in Rule 12b-2 of the Exchange Act.:

o Large accelerated filer          x Accelerated Filer                  o Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  o Yes  x No

As of June 30, 2006, the aggregate market value of the voting stock held by non-affiliates of the registrant was $334.3 million (based on a value of $19.98 per share, the closing price of the Common Stock as quoted by NASDAQ Global Select Market on such date).

As of March 8, 2007, 28,383,455 shares of Common Stock, par value $.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the registrant’s 2007 Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference into Part III of this report.

 




TABLE OF CONTENTS

 

 

 

 

 

 

PART I

 

 

 

 

 

 

 

ITEMS 1 AND 2.

 

BUSINESS AND PROPERTIES

 

 

 

 

 

 

 

ITEM 1A.

 

RISK FACTORS

 

 

 

 

 

 

 

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

 

 

 

 

 

 

 

ITEM 3.

 

LEGAL PROCEEDINGS

 

 

 

 

 

 

 

ITEM 4.

 

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

 

 

 

 

 

 

 

 

PART II

 

 

 

 

 

 

 

ITEM 5.

 

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

 

 

 

 

 

 

ITEM 6.

 

SELECTED FINANCIAL DATA

 

 

 

 

 

 

 

ITEM 7.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

 

 

 

 

 

 

 

ITEM 7A.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

 

 

 

 

 

 

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

 

 

 

 

 

 

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

 

 

 

 

 

 

 

ITEM 9A.

 

CONTROLS AND PROCEDURES

 

 

 

 

 

 

 

ITEM 9B.

 

OTHER INFORMATION

 

 

 

 

 

 

 

 

 

PART III

 

 

 

 

 

 

 

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

 

 

 

 

 

 

ITEM 11.

 

EXECUTIVE COMPENSATION

 

 

 

 

 

 

 

ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

 

 

 

 

 

 

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

 

 

 

 

 

 

ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PART IV

 

 

 

 

 

 

 

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

 

 

2




EDGE PETROLEUM CORPORATION

Unless otherwise indicated by the context, references herein to the “Company”, “Edge”, “we”, “our” or “us” mean Edge Petroleum Corporation, a Delaware corporation, and its corporate and partnership subsidiaries and predecessors.  Certain terms used herein relating to the oil and natural gas industry are defined in ITEMS 1 AND 2. “BUSINESS AND PROPERTIES CERTAIN DEFINITIONS.

FORWARD LOOKING INFORMATION

Certain of the statements contained in all parts of this Annual Report on Form 10-K including, but not limited to, those relating to our drilling plans (including scheduled and budgeted wells), the effect of changes in strategy and business discipline, future tax matters, our 3-D project portfolio, future general and administrative expenses on a per unit of production basis, changes in wells operated and reserves, future growth and expansion, future exploration, future seismic data (including timing and results), expansion of operation, our ability to generate additional prospects, review of outside generated prospects and acquisitions, additional reserves and reserve increases, replace production and manage our asset base, enhancement of visualization and interpretation strengths, expansion and improvement of capabilities, integration of new technology into operations, credit facilities, redetermination of our borrowing base, attraction of new members to the technical team, future compensation programs, new focus on core areas, new prospects and drilling locations, new alliances, future capital expenditures (or funding thereof) and working capital, sufficiency of future working capital, borrowings and capital resources and liquidity, projected rates of return, retained earnings and dividend policies, projected cash flows from operations, future commodity price environment, expectation or timing of reaching payout, outcome, effects or timing of any legal proceedings or contingencies,  the impact of any change in accounting policies on our financial statements, the number, timing or results of any wells, the plans for timing, interpretation and results of new or existing seismic surveys or seismic data, future production or reserves, future acquisition of leases, lease options or other land rights, any other statements regarding future operations, financial results, opportunities, growth, business plans and strategy and other statements that are not historical facts are forward-looking statements.  These forward-looking statements reflect our current view of future events and financial performance.  When used in this document, the words “budgeted,” “anticipate,” “estimate,” “expect,” “may,” “project,” “believe,” “intend,” “plan,” “potential,” “forecast,” “might,” “predict,” “should” and similar expressions are intended to be among the expressions that identify forward-looking statements. These forward-looking statements speak only as of their dates and should not be unduly relied upon.  We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise.   Such statements involve risks and uncertainties, including, but not limited to, those set forth under ITEM 1A. “RISK FACTORS and other factors detailed in this document and our other filings with the Securities and Exchange Commission.  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.  All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties.

AVAILABLE  INFORMATION

Our website address is www.edgepet.com.  We make our website content available for information purposes only.  It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under “Investor Relations - SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission (“SEC”).  The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.

3




PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

Overview

Edge Petroleum Corporation is an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and natural gas properties in the United States. Edge was founded in 1983 as a private company and went public in 1997.  We have evolved over time from a prospect generation organization focused on high-risk, high-reward exploration projects to a team-driven organization focused on a balanced program of exploration, exploitation, development and acquisition of oil and natural gas properties. Following a top-level management change in late 1998, a more disciplined style of business planning and management was integrated into our technology-driven drilling activities and strategy. We believe the continuation of this disciplined business model and strategy will result in continued growth in reserves, production and financial strength and flexibility.

Recent Developments & Accomplishments

Overview

At year-end 2006, our net proved reserves were 102.1 Bcfe, comprised of 76.1 billion cubic feet of natural gas, 1.9 million barrels of natural gas liquids and 2.4 million barrels of crude oil and condensate. Natural gas and natural gas liquids accounted for approximately 86% of those proved reserves.  Approximately 77% of total proved reserves were developed as of year-end 2006 and they were all located onshore, in the United States. During 2006, we focused on developing and exploiting assets in south Texas, our largest core area.  Our 2006 drilling program did not meet our expectations as it was adversely impacted by drilling delays on our nonoperated properties, mainly at the Chapman Ranch Field, shortages of oilfield services and qualified personnel, and the drilling of a larger than originally planned number of proved undeveloped locations.  These events, along with falling natural gas prices, the disappointment of drilling a total of nine dry holes, and the deferment of portions of our drilling program targeting potential new reserves, including the Chapman Ranch Field properties, resulted in a slight decrease in our estimated proved reserves at December 31, 2006 of 102.1 Bcfe compared to the prior year of 102.8 Bcfe.  Despite these factors, we were able to drill 52 wells with an apparent success rate of 83% in 2006.  As described below, in December 2006, we completed an acquisition involving additional working interests and operatorship in the Chapman Ranch Field, where we already owned working interests as a result of two acquisitions late in 2005.  Obtaining operatorship strategically positions us in 2007 and beyond to develop and exploit what we believe is an essential asset in our south Texas portfolio.

Kerr-McGee Acquisition

On December 28, 2006, we completed an acquisition of certain working interests in the Chapman Ranch Field from Kerr-McGee Oil and Gas Onshore, L.P. (“Kerr-McGee”), a wholly-owned subsidiary of Anadarko Petroleum Corporation, for approximately $25 million (the “Kerr-McGee acquisition”). In late 2005, we acquired working interests in this field, including interests in several producing wells, ranging from approximately 44% to 50%. In the Kerr-McGee acquisition, we acquired an additional 44% to 50% working interest in the same wells in the field, and acquired two additional wells, bringing our working interests in those Chapman Ranch properties, including a total of nine producing wells, to 88% to 100%. As of December 31, 2006, the Kerr-McGee assets had approximately 9.0 Bcfe of proved reserves, of which approximately 30% were proved developed. We financed the acquisition with borrowings under our then-existing credit facility.

Smith Acquisition

On January 31, 2007, we completed the purchase of certain oil and natural gas properties located in 13 counties in south and southeast Texas and other associated assets from Smith Production Inc. (“Smith”). We paid approximately $389.8 million for these assets (“Smith assets”).  Although a 2007 event for us, as of December 31, 2006, the Smith assets contained approximately 123.0 Bcfe of proved reserves, which were 81% natural gas and 64% proved developed. In total, the Smith assets include approximately 150 gross producing wells (74 net) and an ownership interest in approximately 17,000 gross (12,250 net) developed acres and 56,000 gross (16,000 net) undeveloped acres of leasehold, all as of December 31, 2006.

4




In addition to the properties and related acreage, we acquired from Smith certain gathering facilities and ownership of approximately 13 miles of natural gas gathering pipelines and related infrastructure serving certain producing assets in southeast Texas. The pipeline system transports our natural gas as well as third-party natural gas.

We also acquired 25% of Smith’s option and leasehold rights in an approximate 95 square mile 3-D exploration area with approximately 30,000 gross acres of leases and options located in the Mission project area in Hidalgo County in south Texas, with a primary focus on the Vicksburg formation.  We acquired a 12.5% working interest in an approximate 160 square mile 3-D exploration area with approximately 55,000 gross acres of leases and options located in the Yates Ranch/Hostetter project area in McMullen and Duval Counties in south Texas. The 160 mile 3-D area increases our exposure to the Middle and Deep Wilcox trend. Furthermore, this venture allows us to participate in a proposed additional 3-D shoot covering approximately 120 square miles near the Yates Ranch within the Wilcox trend. We also acquired 25% of Smith’s option and leasehold rights in an approximate 105 square mile 3-D exploration area with approximately 60,000 gross acres of leases and options in Newton County in southeast Texas and Beauregard Parish in Louisiana with a focus on prospects in the Frio, Yegua and Wilcox formations at depths ranging between 4,000 and 10,000 feet.

Public Offerings

In January 2007, we completed concurrent public offerings of 10,925,000 shares of our common stock for net proceeds of approximately $138.1 million and 2,875,000 shares of our 5.75% Series A cumulative convertible perpetual preferred stock for net proceeds of approximately $138.6 million.  We used the net proceeds from these offerings, along with borrowings under our current credit facility, to finance the Smith acquisition and to repay our prior credit facility.

Strategy

Our business strategy is based on the following six main elements:

1. Grow reserves through acquisitions and the drilling of a balanced portfolio of prospects. We seek to maintain a prudent balance between higher risk/reward wells and more moderate risk/reward wells. In 2006, we drilled 52 wells (28.93 net), primarily in Texas, with 43 (23.40 net) of those wells completed as productive for an apparent success rate of approximately 83%. This drilling program, along with our acquisition of certain oil and gas assets on the Chapman Ranch Field, helped us to replace 97% of our production (see Oil and Natural Gas Reserve Replacement”).  Over the last three years, we drilled 166 wells (91.29 net).  Of the drilled wells, 145 gross (78.27 net) have been completed as apparent successes, for a success rate of approximately 87%.  As a result of our acquisitions and drilling program, we have grown production and proved reserves since December 31, 2004.  Production has grown from 12.1 Bcfe at December 31, 2004 to 17.3 Bcfe at December 31, 2006, an increase of approximately 43%.  Also, we have grown proved reserves from approximately 89.1 Bcfe at year-end 2004 to 102.1 Bcfe at December 31, 2006.  We expect our drilling program for 2007 to be focused primarily in south Texas, and to a lesser extent in the Mississippi Salt Basin, southeast New Mexico and the Fayetteville Shale in Arkansas.  We expect to drill between 80 and 90 wells (37 and 42 net, respectively) in 2007 and we estimate capital spending for the year to be approximately $140 million. In addition, we have a contingent drilling program that could add wells and costs to this estimate.

2. Seek acquisitions that we believe have upside potential.  We seek acquisitions of producing properties that typically have exploration or exploitation upside potential. As illustrated by the Kerr-McGee acquisition and the Smith acquisition, we primarily seek properties in our existing core areas or as a means to establish new core areas. We continue to work diligently to identify and evaluate acquisition opportunities with the goal of implementing those that we believe would fit our strategic plan and add stockholder value.

3. Focus on specific geographic areas where we believe we can add value. We believe geographic focus is a critical element of success. Long-term success requires detailed knowledge of both geologic and geophysical attributes, as well as operating conditions in the areas in which we operate. As a result, we focus on a select number of geographic areas where our experience and strengths can be applied with a significant influence on the outcome. We believe this focus will allow us to manage a growing asset base and add value to additional properties while controlling incremental costs and staffing requirements.

5




4. Integrate technological advances into our exploration, drilling, production operations and administration.  We use advanced technologies as risk-reduction tools in our exploration, development, drilling and completion activities. Data analysis and advanced processing techniques, combined with our more traditional sub-surface interpretation techniques, allow our team of technical personnel to more easily identify features, structural details and fluid contacts that could be overlooked using less sophisticated data interpretation techniques.

5. Maintain a conservative financial structure and control our cost structure.  We believe that a conservative financial structure is crucial to consistent, positive financial results, management of cyclical swings in our industry and the ability to move quickly to take advantage of acquisitions and attractive drilling opportunities. In order to maximize our financial flexibility, we try to maintain a target range of 30% to 40% for our total debt-to-capital ratio.  At December 31, 2006, our debt-to-total capital ratio was 45.3%, resulting from the use of debt to finance our acquisition programs in 2005 and 2006.  Subsequent to December 31, 2006, we issued 10,925,000 shares of common stock and 2,875,000 shares of 5.75% Series A cumulative convertible perpetual preferred stock, which reduced our total debt-to-capital ratio.

We try to fund most of our ongoing capital expenditures using cash flow from operations, reserving our debt capacity for potential investment opportunities that we believe can profitably add to our program. Part of a sound financial structure is constant attention to costs, both operating and overhead. Over the past several years, we have worked diligently to control our operating and overhead costs and instituted a formal, disciplined budgeting process.

6. Use equity ownership and performance based compensation programs to attract and retain a high-quality workforce. Following a management change in late 1998, we eliminated the previous overriding royalty compensation system and replaced it with a system designed to reward all employees through performance-based compensation that is competitive with our peers and through equity ownership. As of February 28, 2007, our directors and employees, including executive officers, owned or had options to acquire an aggregate of approximately 7% of our outstanding common stock.

Employees

As of March 9, 2007, we had 75 full-time employees.  We believe that our relationships with our employees are good.  None of our employees are covered by a collective-bargaining agreement.  From time to time, we utilize the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site surveillance, permitting and environmental assessment.  Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing are generally provided by independent contractors.

Offices

We lease executive and corporate office space located in Travis Tower in Houston, Texas.

Oil and Natural Gas Reserves

The following table sets forth our estimated net proved oil and natural gas reserves and the present value of estimated future net cash flows related to such reserves as of December 31, 2006.  We engaged Ryder Scott Company, L.P. (“Ryder Scott”) and W. D. Von Gonten & Co. (“WDVG”) to estimate our net proved reserves, projected future production, estimated future net revenue attributable to our proved reserves, and the present value of such estimated future net revenue as of December 31, 2006.  Ryder Scott and WDVG’s estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by us.  Ryder Scott has independently evaluated our reserves for the past thirteen years and WDVG has independently reviewed the reserves we acquired from Contango Oil and Gas Company late in 2004 for the past five years.  In estimating the reserve quantities that are economically recoverable, Ryder Scott and WDVG used oil and natural gas prices in effect at December 31, 2006 and estimated development and production costs that were in effect during December 2006 without giving effect to hedging activities.  In accordance with SEC regulations, no price or cost escalation or reduction was considered by Ryder Scott and WDVG.  For further information concerning Ryder Scott and WDVG’s estimates of our proved reserves at December 31, 2006, see the summaries of the reserve reports of Ryder Scott and WDVG included as exhibits to this Form 10-K (respectively, the “Ryder Scott Report” and the

6




“WDVG Report”).  In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, Disclosures About Oil and Natural Gas Producing Activities, the present value of estimated future net revenues after income taxes was prepared using constant prices as of the calculation date, discounted at 10% per annum, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us.  For further information concerning the present value of future net revenue from these proved reserves, see Note 21 to our consolidated financial statements.  See also ITEM 1A. “RISK FACTORS.”  The oil and natural gas reserve data included in or incorporated by reference in this document are only estimates and may prove to be inaccurate.

 

 

Proved Reserves as of December 31, 2006

 

 

 

Developed (1)

 

Undeveloped (2)

 

Total

 

 

 

 

 

 

 

 

 

Oil and condensate (MBbls)(3)

 

3,158

 

1,167

 

4,325

 

Natural gas (MMcf)

 

60,163

 

15,984

 

76,147

 

Total MMcfe

 

79,114

 

22,984

 

102,098

 

 

 

 

 

 

 

 

 

In thousands:

 

 

 

 

 

 

 

Estimated future net revenue before income taxes

 

$

351,433

 

$

57,857

 

$

409,290

 

 

 

 

 

 

 

 

 

Present value of estimated future net revenue before income taxes (discounted 10% per annum) (4)

 

$

240,971

 

$

30,545

 

$

271,516

 

Future income taxes (discounted 10% per annum)

 

(35,116

)

(3,194

)

(38,310

)

Standardized measure of discounted future net cash flows

 

$

205,855

 

$

27,351

 

$

233,206

 

 


(1)          Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.

(2)          Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

(3)          Includes natural gas liquids.

(4)          Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production and development costs, using year-end NYMEX oil and natural gas prices in effect at December 31, 2006, which were $5.62 per MMbtu of natural gas and $61.06 per Bbl of oil. Management believes that the presentation of the present value of future net cash flows attributable to estimated proved reserves, discounted at 10% per annum (the “PV-10 Value”), may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K, therefore the Company has included this reconciliation of the measure to the most directly comparable GAAP financial measure (Standardized measure of discounted future net cash flows). Management believes that the presentation of PV-10 Value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of the Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 Value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. PV-10 Value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The reserve data set forth herein represents estimates only.  Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.  As a result, estimates made by different engineers often vary from one another.  In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material.  Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.  Furthermore, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including current prices, production levels and costs that may not be what is actually incurred or realized. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

In accordance with SEC regulations, the Ryder Scott Report and the WDVG Report each used year-end oil and natural gas prices in effect at December 31, 2006, adjusted for basis and quality differentials. The prices used in

7




calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to December 31, 2006. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced. In particular, natural gas prices at December 31, 2006 were significantly lower than natural gas prices in effect at the previous year-end.  The average natural gas price used in the December 31, 2005 estimation of pre-tax future net cash flows of proved reserves, using a 10% discount rate (“PV10”), was $10.05 per MMBtu of gas, which is considerably higher than the $5.62 per MMBtu used to calculate the PV10 at December 31, 2006.  Decreases in the assumed commodity prices result in decreases in estimated future net revenue as well as in estimated reserves.

Oil and Natural Gas Reserve Replacement

Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. Our business, as with other extractive businesses, is a depleting one in which each gas equivalent unit produced must be replaced or our asset base and ability to generate revenues in the future will shrink. Given the inherent decline of reserves resulting from the production of those reserves, it is important for an exploration and production company to demonstrate a long-term trend of more than offsetting produced volumes with new reserves that will provide for future production. We use the reserve replacement ratio, as defined below, as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production and income. We believe that reserve replacement is relevant and useful information that is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and to a greater extent the prospects of entities engaged in the production and sale of depleting natural resources. These measures are often used as a metric to evaluate an entity’s historical track record of replacing the reserves that it produced. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, acquisitions, extensions and discoveries) by the actual production for the corresponding period. Additions to our reserves are proven developed and proven undeveloped reserves. We expect to continue adding to our reserve base through these activities, but certain factors outside our control may impede our ability to do so (see ITEM 1A. “RISK FACTORS”). The values for these reserve additions and production are derived directly from the proved reserves table in Note 21 to our consolidated financial statements. Accordingly, we do not use unproved reserve quantities.  The reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The ratio does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop. In that regard, the percentage of reserves that were developed was 77%, 74% and 75% for the years ended December 31, 2006, 2005 and 2004, respectively. Set forth below is our reserve replacement ratio for the periods indicated.

 

For the Year Ended December 31,

 

 

 

 

 

2006

 

2005

 

2004

 

Three Year Average

 

Reserve Replacement Ratio

 

97

%

184

%

308

%

184

%

 

Oil and Natural Gas Volumes, Prices and Operating Expense

The following table sets forth certain information regarding production volumes, average sales prices and average operating expenses associated with our sale of oil and natural gas for the periods indicated.

8




 

 

 

Year Ended December 31,

 

 

 

2006

 

2005

 

2004

 

Production:

 

 

 

 

 

 

 

Oil and condensate (MBbls)

 

345

 

324

 

215

 

Natural gas liquids (MBbls)

 

222

 

308

 

276

 

Natural gas (MMcf)

 

13,850

 

12,597

 

9,148

 

Natural gas equivalent (MMcfe)

 

17,251

 

16,384

 

12,093

 

Average sales price - before hedging and derivatives:

 

 

 

 

 

 

 

Oil and condensate ($ per Bbl)

 

$

63.10

 

$

53.57

 

$

39.77

 

Natural gas liquids ($ per Bbl)

 

25.52

 

18.45

 

15.83

 

Natural gas ($ per Mcf)

 

6.68

 

7.97

 

5.91

 

Natural gas equivalent ($ per Mcfe)

 

6.96

 

7.53

 

5.54

 

Average sales price - after hedging and derivatives:

 

 

 

 

 

 

 

Oil and condensate ($ per Bbl)

 

$

64.10

 

$

50.36

 

$

33.03

 

Natural gas liquids ($ per Bbl)

 

25.52

 

18.45

 

15.83

 

Natural gas ($ per Mcf)

 

7.36

 

7.87

 

5.80

 

Natural gas equivalent ($ per Mcfe)

 

7.52

 

7.40

 

5.33

 

Average oil and natural gas operating expenses ($ per Mcfe)(1)

 

$

0.53

 

$

0.52

 

$

0.41

 

Average production and ad valorem taxes ($ per Mcfe)

 

$

0.53

 

$

0.52

 

$

0.36

 

 


(1)          Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), expensed workover costs, the administrative costs of field production personnel, and insurance costs.

Exploration, Development and Acquisition Capital Expenditures

The following table sets forth certain information regarding the total costs incurred in connection with exploration, development and acquisition activities.

 

Year Ended December 31,

 

 

 

2006

 

2005

 

2004

 

 

 

(in thousands)

 

Acquisition costs:

 

 

 

 

 

 

 

Unproved properties

 

$

21,661

 

$

33,948

 

$

12,163

 

Proved properties (1)

 

36,573

 

66,472

 

33,980

 

Exploration costs

 

17,898

 

20,426

 

8,297

 

Development costs

 

64,724

 

58,685

 

34,549

 

Subtotal

 

140,856

 

179,531

 

88,989

 

Asset retirement costs

 

416

 

436

 

278

 

Total costs incurred

 

$

141,272

 

$

179,967

 

$

89,267

 

 


(1)          Includes $17.8 million added to property acquired in the Cinco acquisition in 2005 associated with recording a deferred tax liability at the date of acquisition for taxable temporary differences existing at the purchase date in accordance with SFAS No. 109, Accounting for Income Taxes.   This amount was adjusted to $16.8 million in 2006 as a result of the final purchase price adjustment for the Cinco acquisition.  See Notes 6 and 15 to our consolidated financial statements.

Net costs incurred excludes sales of proved oil and natural gas properties, which are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

Drilling Activity

The following table sets forth our drilling activity for the periods indicated.  In the table, “Gross” refers to the total wells in which we have a working interest or back-in working interest after payout and “Net” refers to gross wells multiplied by our working interest therein.

 

Year Ended December 31,

 

 

 

2006

 

2005

 

2004

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Exploratory:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

13

 

5.12

 

16

 

6.44

 

5

 

2.35

 

Non-productive

 

5

 

2.66

 

1

 

0.75

 

5

 

2.50

 

Total

 

18

 

7.78

 

17

 

7.19

 

10

 

4.85

 

Development:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

30

 

18.28

 

46

 

26.51

 

35

 

19.33

 

Non-productive

 

4

 

2.87

 

2

 

1.75

 

4

 

2.73

 

Total

 

34

 

21.15

 

48

 

28.26

 

39

 

22.06

 

Grand Total

 

52

 

28.93

 

65

 

35.45

 

49

 

26.91

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Success Ratio

 

83

%

81

%

95

%

93

%

82

%

81

%

 

9




Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2006.

 

Company-Operated

 

Non-Operated

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

25

 

12.59

 

72

 

19.45

 

97

 

32.04

 

Natural gas

 

87

 

72.97

 

235

 

86.22

 

322

 

159.19

 

Total

 

112

 

85.56

 

307

 

105.67

 

419

 

191.23

 

 

Acreage Data

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2006.  Developed acres refer to acreage within producing units and undeveloped acres refer to acreage that has not been placed in producing units.

 

Developed Acres

 

Undeveloped Acres

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Arkansas

 

 

 

5,448

 

4,629

 

5,448

 

4,629

 

Montana

 

 

 

12,446

 

9,329

 

12,446

 

9,329

 

Michigan

 

160

 

160

 

498

 

498

 

658

 

658

 

Alabama

 

750

 

47

 

 

 

750

 

47

 

Louisiana

 

1,906

 

470

 

236

 

126

 

2,142

 

596

 

New Mexico

 

7,328

 

2,281

 

92,687

 

17,555

 

100,015

 

19,836

 

Mississippi

 

10,262

 

3,220

 

55,641

 

43,833

 

65,903

 

47,053

 

Texas

 

60,139

 

25,051

 

14,412

 

5,918

 

74,551

 

30,969

 

Total

 

80,545

 

31,229

 

181,368

 

81,888

 

261,913

 

113,117

 

 

Leases covering approximately 15,404 gross (11,793 net), 24,716 gross (19,984 net) and 17,248 gross (12,178 net) undeveloped acres are scheduled to expire in 2007, 2008 and 2009, respectively.  In general, our leases will continue past their primary terms if oil and natural gas production in commercial quantities is being produced from a well on such lease or other drilling or reworking operations are being continuously prosecuted.

The table above does not include 93,362 gross (41,785 net) undeveloped acres in Texas for which we have the option to acquire leases based upon a commitment of continuous drilling subject to the following:

Options Expire*

 

Gross Acres

 

Net Acres

 

2007

 

92,351

 

41,613

 

2008

 

1,011

 

172

 

Total

 

93,362

 

41,785

 

 


* This is an estimate of the expiration of our option to acquire leased acreage based on our current well and 3-D seismic acquisition schedule.

10




Core Areas of Operation

As of December 31, 2006, 70% of our proved reserves were in south Texas, 14% in Mississippi, 8% in New Mexico, and 8% in south Louisiana, Michigan, Alabama and Arkansas.  During 2006, we added reserves and production through our drilling program, focused in south Texas, and our acquisition program.

The table below sets forth the gross and net number of our gas, oil and service wells in each of our core areas of operation as of December 31, 2006.

 

Gas Wells

 

Oil Wells

 

Service Wells (1)

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Texas

 

289

 

145.27

 

42

 

17.24

 

4

 

1.90

 

Louisiana

 

6

 

1.16

 

 

 

3

 

0.64

 

Mississippi

 

9

 

5.44

 

25

 

5.00

 

4

 

1.57

 

Alabama

 

 

 

5

 

0.22

 

3

 

0.26

 

Michigan

 

1

 

1.00

 

 

 

 

 

New Mexico

 

17

 

6.32

 

25

 

9.58

 

 

 

Total

 

322

 

159.19

 

97

 

32.04

 

14

 

4.37

 

 


(1)          Service wells are wells drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Texas

As of December 31, 2006, we owned an interest in 74,551 gross (30,969 net) acres in south Texas.  Our areas of focus in this region are predominantly in the Wilcox, Queen City, Vicksburg and Frio producing trends. As of December 31, 2006, we operated approximately 80 producing wells, which along with our 255 non-operated wells accounted for about 81% of our total net production in 2006.  We drilled 33 wells during 2006 in Texas, 76% of which were an apparent success. The majority of our 2006 drilling activity took place in the Queen City project area. We drilled 21 apparently successful wells in the Queen City project area, one at Chapman Ranch and one at Encinitas.  In 2007, we currently expect to drill 45 to 49 wells (23 to 25 net, respectively) in our core areas in Texas.  The majority of these wells are planned in the Vicksburg, Frio, Wilcox and Queen City project areas.

South Louisiana

As of December 31, 2006, we owned an interest in 2,142 gross (596 net) acres in south Louisiana primarily located in Acadia, Calcasieu, Lafayette, St. Landry and Vermilion Parishes. As of December 31, 2006, we had an interest in 9 wells, none of which we operate. We did not drill any wells in south Louisiana in 2006 and we have no current plans to drill additional wells in this area in 2007.  We did, however, acquire new properties in Louisiana in our Smith acquisition in 2007.

Mississippi Interior Salt Basin

As of December 31, 2006, we owned an interest in 65,903 gross (47,053 net) acres in the Mississippi Interior Salt Basin area, including undeveloped acreage in the Floyd Shale play. We acquired reserves and production in the Mississippi Interior Salt Basin in south central Mississippi as part of the 2003 merger with Miller Exploration Company (“Miller”).  The primary producing horizons in the Mississippi Interior Salt Basin around the Miller properties include the Hosston, Sligo, Rodessa and James Lime sections.  As of December 31, 2006, we operated eleven producing wells in this area.  Production from wells in the Mississippi Interior Salt Basin accounted for approximately 7% of our total net production in 2006. In 2006, we drilled one well (0.75 net) in this area. In 2007, we plan to drill 3 to 5 wells (2 to 4 net, respectively) in the Mississippi Interior Salt Basin.

Michigan

As of December 31, 2006, we owned an interest in 658 gross (658 net) acres in Michigan.  We acquired acreage and one producing well in south central Michigan as part of the 2003 merger with Miller.  We operate this well which produces from the Trenton/Black River formation at approximately 3,000 feet and this well accounted for

11




approximately 1% of our total net production in 2006.  We have no plans for additional activity in Michigan in 2007 at this time.

Southeast New Mexico

We established a new core area in southeast New Mexico through an alliance with two private companies in 2003.  As of December 31, 2006, we owned an interest in 100,015 gross (19,836 net) acres in this area that we earned through a drilling obligation we fulfilled during 2004 and 2005 and through subsequent purchases. The objectives in this area are shallow oil in the Yeso, San Andres, Queen and Grayburg formations, and deep natural gas in the Atoka and Morrow formations. Additional objectives are the Strawn, Cisco, Wolfcamp and Devonian formations. In 2006, we participated in the drilling of 16 gross (5.6 net) wells, of which 94% were apparent successes.  Production from wells in the southeast New Mexico area represented approximately 10% of our total net production in 2006.  During 2007, we anticipate drilling 10 to 12 wells (2 to 3 net, respectively) in southeast New Mexico.

Arkansas

As of December 31, 2006, we owned an interest in 5,448 gross (4,629 net) undeveloped acres in the Fayetteville Shale play in south central Arkansas. In 2006, we drilled two wells (0.9 net), both of which were apparently successful, although not yet producing.  During 2007, we anticipate drilling 20 to 24 wells (6 to 8 net, respectively) in this area.

Title to Properties

We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry.  Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties.  As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records).  Detailed investigations, including a title opinion rendered by a licensed attorney, are made before commencement of drilling operations.

We have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Union Bank of California, as agent, to secure our credit facility.  These mortgages and the credit facility contain substantial restrictions and operating covenants that are customarily found in loan agreements of this type.  See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES – CREDIT FACILITY” and Notes 10 and 12 to our consolidated financial statements.

Marketing

Our production is marketed to third parties consistent with industry practices. We market our own production where feasible, but on occasion engage a third-party marketing agent. Typically, oil is sold at the well-head at field-posted prices and natural gas is sold under contract at a negotiated monthly price based upon factors normally considered in the industry, such as conditioning or treating to make gas marketable, distance from the well to the transportation pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply/demand conditions.

Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production on the Gulf Coast. We take an active role in determining the available pipeline alternatives for each property based upon historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.

There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales.  We have not experienced any significant

12




difficulties in marketing our oil and natural gas. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers.  Where feasible, we use a combination of market-sensitive pricing and forward-fixed pricing.  Forward pricing is utilized to take advantage of anomalies in the futures market.

Due to the instability of oil and natural gas prices, we may enter into, from time to time, pricerisk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure to price fluctuations.  While the use of these arrangements may limit our ability to benefit from increases in the price of oil and natural gas, it also reduces our potential exposure to adverse price movements.  Our price-risk management arrangements, to the extent we enter into any, apply to only a portion of our production, provide only partial price protection against declines in oil and natural gas prices and limit our potential gains from future increases in prices.  None of these instruments are used for trading purposes.  All such derivative transactions provide for financial rather than physical settlement.  On a quarterly basis, our management reviews all of our price-risk management transaction policies, including volumes, accounting treatment, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation with and concurrence by the President and Chairman of the Board.  Our Board of Directors continuously monitors our price-risk management policies and trades.  We account for these transactions as hedging and derivative activities and, accordingly, certain gains and losses are included in revenue during the period the transactions occur (see Note 9 to our consolidated financial statements and ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CRITICAL ACCOUNTING POLICIES AND ESTIMATES – DERIVATIVES AND HEDGING ACTIVITIES.”).

All of these price-risk management transactions are considered derivative instruments and are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended). These derivative instruments are intended to hedge our price-risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value and the cash flows resulting from settlement of these derivative transactions are classified in operating activities on the statement of cash flows. For those derivatives to which mark-to-market accounting treatment is applied, the changes in fair value are not deferred through other comprehensive income on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivatives that are designated and qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in other comprehensive income on the balance sheet and the ineffective portion of the changes in the fair value of the contracts is recorded in total revenue on the statement of operations, in either case as such changes occur. When the hedged production is sold, the realized gains and losses on the contracts are removed from other comprehensive income and recorded in revenue. While the contract is outstanding, the unrealized and ineffective gain or loss may increase or decrease until settlement of the contract depending on the fair value at the measurement dates.

During the first quarter of 2006, we determined that the cash flow hedge accounting treatment previously applied to our natural gas derivative contracts should be discontinued due to projected changes in the 2006 physical production volumes hedged and to give us more flexibility in how we market our physical production. Beginning in the first quarter of 2006, we applied mark-to-market accounting treatment to all outstanding derivative contracts, therefore the changes in fair value are not deferred through other comprehensive income, but rather recorded in revenue immediately as unrealized gains or losses. Going forward, we will continue to evaluate the terms of new contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. In the past, we used mark-to-market accounting treatment for our crude oil derivative contracts and cash flow hedge accounting treatment for our natural gas derivative contracts. Therefore, unrealized gains and losses on the change in fair value of natural gas derivative contracts between periods may not be comparable.

Included within total revenue for the years ended December 31, 2006, 2005, and 2004 was approximately $9.7 million in net gains, $2.3 million in net losses and $2.5 million in net losses, respectively, from hedging and derivative activity as shown in the table below.

13




 

 

 

Year Ended December 31,

 

 

 

2006

 

2005

 

2004

 

 

 

(in thousands)

 

Natural gas contract settlements (Mcf)

 

$

4,699

 

$

(1,230

)

$

(328

)

Crude oil contract settlements (Bbl)

 

 

(1,757

)

(881

)

Hedge premium reclassification (Mcf)

 

 

 

(686

)

Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)

 

4,686

 

 

 

Mark-to-market reversal of prior period unrealized change in fair value of oil derivative contracts (Bbl)

 

(155

)

565

 

 

Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)

 

500

 

155

 

(565

)

Gain (loss) on hedging and derivatives

 

$

9,730

 

$

(2,267

)

$

(2,460

)

 

The table below summarizes our outstanding derivative contracts reflected on the balance sheet at December 31, 2006 and 2005.

 

 

 

 

 

 

 

 

 

 

 

Fair Value of Outstanding Hedging and
Derivative Contracts as of

 

 

 

 

 

 

 

 

 

Price

 

Volumes

 

December 31,

 

Transaction Date

 

Transaction Type

 

Beginning

 

Ending

 

Per Unit

 

Per Day

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

Natural Gas (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

08/05

 

Natural Gas Collar

 

01/01/2006

 

12/31/2006

 

$7.00-$10.50

 

10,000MMbtu

 

$

 

$

(2,498

)

08/05

 

Natural Gas Collar

 

01/01/2006

 

12/31/2006

 

$7.00-$16.10

 

10,000MMbtu

 

 

(137

)

08/06

 

Natural Gas Collar

(3)

01/01/2007

 

12/31/2007

 

$7.50-$11.50

 

5,000 MMbtu

 

2,301

 

 

08/06

 

Natural Gas Collar

(3)

01/01/2007

 

12/31/2007

 

$7.50-$12.00

 

5,000 MMbtu

 

2,385

 

 

Crude Oil (2):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

08/05

 

Crude Oil Collar

 

01/01/2006

 

12/31/2006

 

$55.00-$80.00

 

400Bbl

 

 

156

 

08/06

 

Crude Oil Collar

 

01/01/2007

 

12/31/2007

 

$70.00-$87.50

 

400 Bbl

 

1,047

 

 

12/06

 

Crude Oil Swap

 

01/01/2007

 

12/31/2007

 

$66.00

 

600 Bbl

 

212

 

 

12/06

 

Crude Oil Swap

 

01/01/2008

 

12/31/2008

 

$66.00

 

1,500 Bbl

 

(758

)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

5,187

 

$

(2,479

)

 


(1)                Our current natural gas derivative contracts were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index.  Cash flow hedge accounting, which was applied to these contracts in 2005, was discontinued in 2006. During 2006, mark-to-market accounting treatment was applied to these contracts and the change in fair value is reflected in total revenue during the year.

(2)                Cash flow hedge accounting is not applied to our crude oil contracts, which were entered into on a per barrel delivered price basis, using the West Texas Intermediate Light Sweet Crude Oil Index. Mark-to-market accounting treatment is applied to these contracts and the change in fair value is reflected in total revenue during the year.

(3)                Subsequent to December 31, 2006, two natural gas collars covering a portion of our 2007 estimated production were terminated and replaced with new collars.  The terms of the new contracts are detailed below.

Derivative contracts entered into after December 31, 2006 were as follows:

Transaction

 

 

 

Effective Dates

 

 

 

Volume Per

 

Date

 

Transaction Type (1)

 

Beginning

 

Ending

 

Price Per Unit

 

Day

 

01/07

 

Natural Gas Collar

 

01/01/08

 

12/31/08

 

$7.50-$9.00

 

10,000 MMbtu

 

01/07

 

Natural Gas Collar

 

01/01/08

 

12/31/08

 

$7.50-$9.02

 

10,000 MMBtu

 

01/07

 

Natural Gas Collar

(2)

02/01/07

 

12/31/07

 

$7.02-$9.00

 

15,000 MMBtu

 

01/07

 

Natural Gas Collar

(2)

02/01/07

 

12/31/07

 

$7.00-$9.00

 

15,000 MMBtu

 

01/07

 

Natural Gas Collar

 

02/01/07

 

12/31/07

 

$7.00-$9.00

 

10,000 MMbtu

 

01/07

 

Natural Gas Collar

 

01/01/08

 

12/31/08

 

$7.50-$9.00

 

20,000 MMBtu

 

 


(1)                Our January 2007 natural gas collars were entered into on a per MMbtu delivered price basis, using the NYMEX Natural Gas Index. Mark-to-market accounting treatment will be applied to these contracts and the change in fair value will be reflected in total revenue.

14




(2)                These natural gas collars replaced contracts that were cancelled subsequent to December 31, 2006.

Sales to Major Customers

We sold natural gas and crude oil production representing 10% or more of our total revenues to the following major customers for the years ended December 31, 2006, 2005, and 2004.

 

For the Year Ended December 31,

 

Purchaser

 

2006

 

2005

 

2004

 

Kinder Morgan

 

37

%

29

%

*

 

Chevron Corporation

 

12

%

18

%

22

%

Copano Field Services

 

10

%

17

%

19

%

Kerr-McGee Oil & Gas

 

10

%

*

 

*

 

Upstream Energy Services (1)

 

3

%

5

%

22

%

 


* Zero or less than 1%.

(1) Upstream Energy Services is an agent that sells our production to other purchasers on our behalf.

NOTE: Amounts disclosed are approximations and those that are less than 10% are presented for information and comparison purposes only. These percentages do not consider the effects of financial derivative instruments.

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all our customers are concentrated in the oil and gas industry, and our revenue can be materially affected by current economic conditions and the price of certain commodities such as natural gas and crude oil, the cost of which is passed through to the customer. However, based on the current demand for natural gas and crude oil and the fact that alternate purchasers are readily available, we believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

Competition

We compete with other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties.  Our ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.  We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively. (See ITEM 1A. “RISK FACTORS – We face strong competition from larger oil and natural gas companies.”)

INDUSTRY REGULATIONS

The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control.  These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels.  For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations.  State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment.  Pipelines are subject to the jurisdiction of various federal, state and local agencies.  We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.  The following discussion summarizes the regulation of the United States oil and natural gas industry.  We believe that we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although there can be no assurance that this is or will remain the case.  Moreover, such statutes, rules, regulations and

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government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect our results of operations and financial condition.  The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

Regulation of Oil and Natural Gas Exploration and Production.  Our operations are subject to various types of regulation at the federal, state and local levels.  Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of oil and natural gas properties.  In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases.  In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project, if the operator owns less than 100% of the leasehold.  In addition, state conservation laws which establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  The regulatory burden on the oil and natural gas industry increases our costs of doing business and, consequently, affects our profitability.  Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas.   Federal legislation and regulatory controls have historically affected the price of natural gas produced by us, and the manner in which such production is transported and marketed.  Under the Natural Gas Act (“NGA”) of 1938, the Federal Energy Regulatory Commission (the “FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas.  Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all sales by us of our own production.  As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect.  However, the Decontrol Act did not affect the FERC’s jurisdiction over natural gas transportation.  Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas, and the FERC has issued new regulations to implement this prohibition. In addition, under the 2005 Act the FERC has been directed to establish new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold. The 2005 Act also has significantly increased the penalties for violations of the NGA.

Our natural gas sales are affected by intrastate and interstate gas transportation regulation.  Following the Congressional passage of the Natural Gas Policy Act of 1978 (“NGPA”), the FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas.  Beginning with the adoption of Order No. 436, issued in October 1985, the FERC has implemented a series of major restructuring orders that have required pipelines, among other things, to perform “open access” transportation of gas for others, “unbundle” their sales and transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties.  We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.  It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business.  We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities.  We do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural gas with which we compete.

In the past, Congress has been very active in the area of gas regulation.  However, as discussed above, the more recent trend has been in favor of deregulation, or “lighter handed” regulation, and the promotion of competition in the gas industry.  There regularly are other legislative proposals pending in the Federal and state legislatures that, if enacted, would significantly affect the petroleum industry.  At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such

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proposals might have on us.  Similarly, and despite the trend toward federal deregulation of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas.  Again, we do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas with which we compete.

We own certain natural gas pipelines that we believe meet the standards the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction under the NGA. These gathering facilities are regulated for safety compliance by the U.S. Department of Transportation (“DOT”) and/or by state regulatory agencies. In 2004, the DOT implemented regulations requiring that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of certain pipeline facilities within ten years, and at least every seven years thereafter. In addition, beginning in early 2006, the DOT’s Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. We are not able to predict with certainty the final outcome of this rulemaking proposal.

The intrastate pipeline system in Texas is regulated for safety compliance by the DOT and the Texas Railroad Commission. In 2002, the United States Congress enacted the Pipeline Safety Improvement Act of 2002, which contains a number of provisions intended to increase pipeline operating safety. The DOT’s final regulations implementing the 2002 act became effective in February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission pipeline and nonrural gathering facilities within the next ten years, and at least every seven years thereafter. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorizes the programs adopted under the 2002 Act, proposes enhancements for state programs to reduce excavation damage to pipelines, establishes increased federal enforcement of one-call excavation programs, and establishes a new program for review of pipeline security plans and critical facility inspections. In addition, beginning in October 2005, the DOT’s Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. On March 15, 2006, the DOT revised its regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in nonrural areas, and adopt new compliance deadlines. We are not able to predict with certainty the final impact of these new rules on the pipelines that we will acquire in the Smith acquisition.  In addition to safety regulation, state regulation of gathering facilities generally includes various environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation.  Natural gas gathering may receive greater regulatory rate and service scrutiny at the state level in the post-restructuring environment.

Oil Price Controls and Transportation Rates.  Sales of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices.  The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of the transportation is through interstate common carrier pipelines.  Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations.  The FERC’s regulation of oil transportation rates may tend to increase the cost of transporting oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry.  In March 2006, to implement the second of the required five-yearly re-determinations, the FERC established an upward adjustment in the index to track oil pipeline cost changes. The FERC determined that the Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning July 1, 2006.  We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with oil production from our oil producing operations.

Environmental Regulations.  Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within wilderness,

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wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations.  Public interest in the protection of the environment has increased dramatically in recent years.  The trend of more expansive and stricter environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.  To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

We generate wastes that may be subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes.  The U.S. Environmental Protection Agency (“EPA”) and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes.  Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as “hazardous wastes,” and therefore be subject to more rigorous and costly operating and disposal requirements.

We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and natural gas.  Although we believe that we have used good operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for disposal.  In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control.  These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws as well as state laws governing the management of oil and natural gas wastes.  Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

Our operations may be subject to the Clean Air Act (“CAA”) and comparable state and local requirements.  Amendments to the CAA were adopted in 1990 and contain provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations.  The EPA and states developed and continue to develop regulations to implement these requirements.  We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.  However, we do not believe our operations will be materially adversely affected by any such requirements.

The U.S. Congress and various states are currently considering proposed legislation directed at reducing “greenhouse gas emissions.”  It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact the oil and gas exploration and production business.  However, future federal laws and regulations, if enacted, could result in increased compliance costs or additional operating restrictions and adversely affect our business and prospects.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as Edge, to prepare and implement spill prevention, control, countermeasure (“SPCC”) and response plans relating to the possible discharge of oil into surface waters.  SPCC plans at our producing properties were developed and implemented in 1999.  The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.  The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters.  Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.  Our operations are also subject to the federal Clean Water Act (“CWA”) and analogous state laws.  In accordance with the CWA, the state of Louisiana has issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997.    Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground.

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CERCLA, also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment.  These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We also are subject to a variety of federal, state and local permitting and registration requirements relating to protection of the environment. Management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse effect on us.

OPERATING HAZARDS AND INSURANCE

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosion, blow-out, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations.

In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above.  Our insurance does not cover business interruption or protect against loss of revenue.  There can be no assurance that any insurance obtained by us will be adequate to cover any losses or liabilities.  We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase.  The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and operations.

ITEM 1A. RISK FACTORS

Oil and gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs which could adversely affect us.

Our growth will be materially dependent upon the success of our future drilling program.  Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered.  The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.  Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition.  Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all.  We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location.  Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

·                  the results of exploration efforts and the acquisition, review and analysis of the seismic data;

·                  the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

·                  the approval of the prospects by other participants after additional data has been compiled;

·                  economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews;

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·                  our financial resources and results; and

·                  the availability of leases and permits on reasonable terms for the prospects.

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas.  See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – GENERAL OVERVIEW - INDUSTRY AND ECONOMIC FACTORS and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – CORE AREAS OF OPERATION.”

Oil and natural gas prices are highly volatile in general and low prices negatively affect our financial results.

Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.  Our reserves are predominantly natural gas, therefore changes in natural gas prices may have a particularly large impact on our financial results.  Lower oil and natural gas prices also may reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future.  Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control.  These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions.  Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations.  See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – RISK MANAGEMENT ACTIVITIES - DERIVATIVES AND HEDGING” and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – OIL AND NATURAL GAS RESERVES” and “–  MARKETING.”

We have in the past (most recently in the third quarter of 2006) and may in the future be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile.  Whether we will be required to take such a charge will depend on the prices for oil and natural gas at the end of any quarter and the effect of reserve additions or revisions and capital expenditures during such quarter.  If a write down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities.

We have hedged and may continue to hedge a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter into hedging arrangements.  Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and natural gas prices.  Such hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, our hedging arrangements may limit the benefit to us of increases in the price of oil and natural gas.  See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – RISK MANAGEMENT ACTIVITIES – DERIVATIVES AND HEDGING” and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – MARKETING.”

We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.  Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline.  Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we could be adversely affected.

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We are subject to substantial operating risks that may adversely affect the results of our operations.

The oil and natural gas business involves certain operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. We could suffer substantial losses as a result of any of these events.  We are not fully insured against all risks incident to our business.

We are not the operator of some of our wells.  As a result, our operating risks for those wells and our ability to influence the operations for these wells are less subject to our control. Operators of these wells may act in ways that are not in our best interests. See ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – OPERATING HAZARDS AND INSURANCE.”

We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability.

We do not operate all of the properties in which we have an interest.  As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties.  The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues.  The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s

·                  timing and amount of capital expenditures;

·                  expertise and financial resources;

·                  inclusion of other participants in drilling wells; and

·                  use of technology.

The loss of key personnel could adversely affect us.

We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of which could have a material adverse effect on our operations.  We do not maintain key-man life insurance with respect to any of our employees.  We believe that our success is also dependent upon our ability to continue to employ and retain skilled technical personnel.  See ITEM 4.  “SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS – EXECUTIVE OFFICERS OF THE REGISTRANT” and “-SIGNIFICANT EMPLOYEES.”

Our operations have significant capital requirements which, if not met, will hinder operations.

We have experienced and expect to continue to experience substantial working capital needs due to our active exploration, development and acquisition programs.  Additional financing may be required in the future to fund our growth.  We may not be able to obtain such additional financing, and financing under existing or new credit facilities may not be available in the future.  In the event such capital resources are not available to us, our drilling and other activities may be curtailed. See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES.”

High demand for field services and equipment and the ability of suppliers to meet that demand may limit our ability to drill and produce our oil and natural gas properties.

Due to current industry demands, well service providers and related equipment and personnel are in short supply. This is causing escalating prices, delays in drilling and other exploration activities, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the over use of equipment and inexperienced personnel.

Government regulation and liability for environmental matters may adversely affect our business and results of operations.

Oil and natural gas operations are subject to various federal, state and local government regulations, which may be changed from time to time.  Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and

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taxation.  From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas.  There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations.   In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease.  As a result, we may incur substantial liabilities to third parties or governmental entities.  We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.  The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us.  See ITEMS 1 AND 2.BUSINESS AND PROPERTIES – INDUSTRY REGULATIONS.”

We may have difficulty managing any future growth and the related demands on our resources and may have difficulty in achieving future growth.

We have experienced growth in the past through the expansion of our drilling program and, more recently, acquisitions. This expansion was curtailed in 1998 and 1999, but resumed in 2000 and increased in subsequent years. Further expansion is anticipated in 2007 both through increased drilling efforts and possible acquisitions.  Any future growth may place a significant strain on our financial, technical, operational and administrative resources.  In particular, the Smith acquisition, which was completed in January 2007, has resulted in a significant growth in our assets, reserves and revenues and may place a significant strain on our financial, technical, operational and administrative resources. We may not be able to integrate the operations of the acquired assets without increases in costs, losses in revenues or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, costs savings or other benefits expected from the Smith acquisition. Any unexpected costs or delays incurred in connection with the integration could have an adverse effect on our business, results of operations or financial condition.  We currently do not expect to hire any personnel associated with Smith. We have added to our staffing levels as a result of the Smith acquisition,and we intend to hire approximately 5 additional employees that we expect will be required to manage the increased scale of our business.  However, we may experience difficulties in finding the additional qualified personnel. In an effort to stay on schedule with our planned activities in 2007, we intend to supplement our staff with contract and consultant personnel until we are able to hire new employees.

Our ability to grow will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects, our ability to develop existing prospects, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, hydrocarbon prices and access to capital.   We may not be successful in achieving or managing growth and any such failure could have a material adverse effect on us.

We face strong competition from larger oil and natural gas companies.

The oil and gas industry is highly competitive. We encounter competition from oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and productive oil and natural gas properties. Our competitors range in size from the major integrated oil and natural gas companies to numerous independent oil and natural gas companies, individuals and drilling and income programs.  Many of these competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to conduct our operations successfully, evaluate and select suitable properties, consummate transactions, and obtain technical, managerial and other professional personnel in this highly competitive environment.  Specifically, these larger competitors may be able to pay more for exploratory prospects, productive oil and natural gas properties and competent personnel 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. In addition, such competitors may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. See ITEMS 1 AND 2. “BUSINESS AND PROPERTIES COMPETITION.”

The oil and natural gas reserve data included in or incorporated by reference in this document are estimates based on assumptions that may be inaccurate and existing economic and operating conditions that may differ from future economic and operating conditions.

Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based upon assumptions that may vary considerably

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from actual results.  Accordingly, reserve estimates may be subject to downward or upward adjustment.  Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties.  As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.  Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation.  In addition, the 10% discount factor, which is required by Financial Accounting Standards Board in SFAS No. 69, Disclosures About Oil and Natural Gas Producing Activities to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.  See ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – OIL AND NATURAL GAS RESERVES.”

Our credit facility has substantial operating restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect operations.

Over the past few years, increases in commodity prices, in proved reserve amounts and the resultant increase in estimated discounted future net revenue, has allowed us to increase our available borrowing amounts.  In the future, commodity prices may decline, we may increase our borrowings or our borrowing base may be adjusted downward.  Our credit facility is secured by a pledge of substantially all of our assets and has covenants that limit additional borrowings, sales of assets and the distributions of cash or properties and that prohibit the payment of dividends on our common stock and the incurrence of liens.  The credit facility also requires that specified financial ratios be maintained.  The restrictions of our credit facility and the difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results, including our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes.  In addition,  such financing may be on terms unfavorable to us and we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities. Further, a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and require us to modify operations and we may become more vulnerable to downturns in our business or the economy generally.

Our ability to obtain and service indebtedness will depend on our future performance, including our ability to manage cash flow and working capital, which are in turn subject to a variety of factors beyond our control.  Our business may not generate cash flow at or above anticipated levels or we may not be able to borrow funds in amounts sufficient to enable us to service indebtedness, make anticipated capital expenditures or finance our drilling program.  If we are unable to generate sufficient cash flow from operations or to borrow sufficient funds in the future to service our debt, we may be required to curtail portions of our drilling program, sell assets, reduce capital expenditures, refinance all or a portion of our existing debt or obtain additional financing.  We may not be able to refinance our debt or obtain additional financing, particularly in view of current industry conditions, the restrictions on our ability to incur debt under our existing debt arrangements, and the fact that substantially all of our assets are currently pledged to secure obligations under our credit facility.  See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES” and “– CREDIT FACILITY.”

We may not have enough insurance to cover all of the risks we face.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face.  We do not carry business interruption insurance.  We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.  In addition, we cannot insure fully against pollution and environmental risks.  The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

Our acquisition program may be unsuccessful.

Acquisitions have become increasingly important to our business strategy in recent years. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices,

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operating costs, potential environmental and other liabilities and other factors.  Such assessments, even when performed by experienced personnel, are necessarily inexact and their accuracy inherently uncertain. Our review of subject properties will not reveal all existing or potential problems, deficiencies and capabilities.  We may not always perform inspections on every well, and may not be able to observe structural and environmental problems even when we undertake an inspection.  Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. We may be left with no recourse for liabilities and other problems associated with acquisitions that we do not discover prior to the closing date.  Any acquisition of property interests by us may not be successful and, if unsuccessful, such failure may have an adverse effect on our future results of operations and financial condition.

Approximately 36% of the proved reserves associated with the Smith acquisition in January 2007 and approximately 23% of our proved reserves were undeveloped as of December 31, 2006, and those reserves may not ultimately be developed.

As of December 31, 2006, approximately 36% of the proved reserves associated with the Smith acquisition in January 2007 and approximately 23% of our proved reserves were undeveloped. Proved undeveloped reserves, by their nature, are less certain than other categories of proved reserves. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations and involves greater risks. Our reserve data for the properties assumes that to develop our reserves we will make significant capital expenditures and conduct these operations successfully. Although we have prepared estimates of these natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards and SEC requirements, the estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future.  We are currently restricted from paying dividends on common stock by our existing credit facility agreement and, in some circumstances, by the terms of our Series A preferred stock. Any future dividends also may be restricted by our then-existing debt agreements.  See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES” and Notes 10 and 12 to our consolidated financial statements.

Our reliance on third parties for gathering and distributing could curtail future exploration and production activities.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities.  The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition.  In addition, federal and state regulation of oil and natural gas production and transportation affect our ability to produce and market our oil and natural gas on a profitable basis.

Provisions of Delaware law and our charter and bylaws may delay or prevent transactions that would benefit stockholders.

Our Certificate of Incorporation and Bylaws and the Delaware General Corporation Law contain provisions that may have the effect of delaying, deferring or preventing a change of control of the Company.  These provisions, among other things, provide for a classified Board of Directors with staggered terms, restrict the ability of stockholders to take action by written consent, authorize the Board of Directors to set the terms of Preferred Stock, and restrict our ability to engage in transactions with stockholders with 15% or more of outstanding voting stock.

Because of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts.  As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.

24




ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

25




CERTAIN DEFINITIONS

The definitions set forth below shall apply to the indicated terms as used in this Annual Report.  All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

After payout.  With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d.  Stock tank barrels per day.

Bcf.  Billion cubic feet.

Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Before payout.  With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

Completion.  The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage.  The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed the related oil and natural gas operating expenses and taxes.

Exploratory well.  A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farm-in or farm-out.  An agreement whereunder the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage.  Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.  The assignor usually retains a royalty and/or reversionary interest in the lease.  The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding costs.  Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by us pursuant to generally accepted accounting principles in the United States, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells, excluding those costs attributable to unproved property.

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

MBbls.  One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf.  One thousand cubic feet.

Mcf/d.  One thousand cubic feet per day.

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Mcfe.  One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas.  Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.

MMcf.  One million cubic feet.

MMcf/d.  One million cubic feet per day.

MMcfe.  One million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas.

MMcfe/d.  One million cubic feet equivalent per day.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells.

NGL’s.  Natural gas liquids measured in barrels.

NRI or Net Revenue Interests.  The share of production after satisfaction of all royalty, overriding royalty, oil payments and other nonoperating interests.

Normally pressured reservoirs.  Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI per foot of depth from the surface.  For example, if the formation pressure is 4,650 PSI at 10,000 feet, then the pressure is considered to be normal.

Over-pressured reservoirs.  Reservoirs subject to abnormally high pressure as a result of certain types of subsurface formations.

Plant Products.  Liquids generated by a plant facility and include propane, iso-butane, normal butane, pentane and ethane.

Present value.  When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to nonproperty-related expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation, and amortization, discounted using an annual discount rate of 10%.

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed nonproducing reserves.  Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves.  Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

Proved developed reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves.  The 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 undeveloped location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

27




Proved undeveloped reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion.  The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest.  An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

3-D seismic.  Advanced technology method of detecting accumulations of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest or WI.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover.  Operations on a producing well to restore or increase production.

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ITEM 3.  LEGAL PROCEEDINGS

From time to time we are a party to various legal proceedings arising in the ordinary course of our business.  While the outcome of lawsuits cannot be predicted with certainty, we are not currently a party to any proceeding that we believe, if determined in a manner adverse to us, could have a material adverse effect on our financial condition, results of operations or cash flows, except as set forth below.

Texas Comptroller Audit - During the second quarter of 2004, we received notice that a subsidiary’s franchise tax returns for the State of Texas would be audited for the tax years 1999 through 2002. After reviewing the documents submitted, the agent representing the Office of the Comptroller of the State of Texas proposed adjustments to the calculation that would result in an increased franchise tax liability.  The agent maintained that transfers by us to our subsidiary, which were classified as intercompany loans, should instead be classified as equity investments in the subsidiary. The State of Texas originally proposed that the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

During the third quarter of 2006, we and the Comptroller agreed upon a method of computing our franchise tax liability to the State of Texas for the tax years 1999 through 2002 that resulted in a total one-time payment of $144,474, plus penalties of $9,228 which was recorded in 2006.  Interest on this settlement of $40,150 was paid in the fourth quarter of 2006.

Wade and Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidated with Rolland L. Broussard, et al., v. Edge Petroleum Corp of Texas, et al. - This is a consolidated suit, filed in state court in Vermilion Parish, Louisiana in September 2003. Plaintiffs are mineral/royalty owners under the Norcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, Sand Unit A (Edge’s old Bayou Vermilion Prospect).  They claim the operator at the time, Norcen Explorer, now Anadarko, failed to “block squeeze” the sections of the No. 2 well, as a prudent operator, according to their allegations, would have done, to protect the gas reservoir from being flooded with water from adjacent underground formations. Plaintiffs further allege Norcen was negligent in not creating a field-wide unit to protect their interests.  The allegations relate to actions taken beginning in the early 1990’s. Plaintiffs have named us and other working interest owners in the leases as defendants, including Norcen Explorer’s successors in interest, Anadarko. Plaintiffs originally sought unspecified damages for lost royalties and damages due to alleged devaluation of their mineral and property interests, plus interest and attorneys’ fees. In early 2005, we filed a motion for summary judgment in the case asserting, among other defenses, that:  (i) there has been no breach of contract, (ii) there is no express or implied duty imposed on us to block squeeze the well or form a field-wide unit, (iii) the units were properly formed by the Conservation Commissioner in accordance with the statutory scheme in Louisiana, (iv) plaintiffs’ claims are barred by limitations, and (v) other defenses. Along with the other defendants, we also filed a special peremptory challenge of no cause of action under the leases and the Louisiana Mineral Code for failure to exhaust administrative remedies and due to lack of a demand. In May and June 2005, the court ruled against us on the motion for summary judgment and the peremptory challenges. Of the 18.75% after-payout working interest that was originally reserved in the leases, we owned a 2.8% working interest at the time of the alleged acts or omissions. On September 6, 2005, we filed a third-party demand to join the other working interest owners who hold the remainder of the 18.75% working interest as third-party defendants in this case. These third-parties consist, for the most part, of partnerships that are directly or indirectly controlled by John Sfondrini, a director of ours, and hold an aggregate 14.7% working interest (the “Sfondrini Partnerships”). Vincent Andrews, also a director of ours, owns a minority interest in the corporate general partner of one of the partnerships. The Sfondrini Partnerships consist of (1) Edge Group Partnership, a general partnership composed of limited partnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondrini are general partners; (2) (A) Edge Option I Limited Partnership, (B) Edge Option II Limited Partnership and (C) Edge Option III Limited Partnership, limited partnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondrini are general partners; and (3) BV Partners Limited Partnership, a limited partnership of which a company controlled by Messrs. Sfondrini and Andrews is general partner and of which Mr. Sfondrini is manager (and of which company Mr. Andrews is an officer).  These partnerships were among the third party defendants that we have sought to join in the case, and these partnerships have for the most part filed answers denying any liability to us. We participated for our 2.8% share of the well costs and revenues for the Broussard No. 2 well, as did the other defendants for their share, including the third-party defendant partnerships who participated for 14.7%. We strongly believe the parties should only be liable for their proportionate share of any damages award should a finding of liability occur in the case. We intend to vigorously contest the plaintiffs’ claims.

As of the date of this report, it is not possible to determine what, if any, our ultimate exposure might be in this matter. Prior to the settlement described below, plaintiffs had asserted damages, including interest, to be as high as

29




$63 million.  The plaintiffs’ expert witness, in his December 2005 deposition, offered his theory that plaintiffs’ gross damages are in the range of $19 to $22 million. That number is based on his theory that the alleged failure to block squeeze the well resulted in the under-production of gas worth $300 million. Plaintiffs’ royalty share of that figure yields the $19 to $22 million range of alleged damages. Based on the expert’s testimony, damages attributable to the full 18.75% interest would be in the range of $3.75 million gross or net to our 2.8% share would be in the range of $560,000 (excluding interest and attorneys’ fees). Along with the other defendants, we hired our own expert witnesses who have refuted these claims, particularly the expert’s assertions that failure to block squeeze the well caused any damages to the reservoir. The deposition of a Norcen engineer who prepared the completion plan for the Broussard No. 2 well and supervised the completion operations, taken in April 2006, confirms the testimony of the defense experts as to why the well was not block squeezed.  The plaintiffs have also retained a damages expert who has given a report that the damages in this case are in the range of $30 million, excluding interest and attorneys’ fees.  Our share of that amount based on the full 18.75% would be approximately $5.6 million and net to our 2.8% share would be approximately $840,000. We participated in mediation of this lawsuit on July 18, 2006, but the parties failed to reach an agreement.  In July 2006, the plaintiffs’ attorney sent a demand to the defendants for total damages claimed by plaintiffs, with legal interest, totaling $63 million.  Our share of that amount based on the full 18.75% interest would be approximately $12.2 million and net to our 2.8% interest would be approximately $1.8 million. On July 31, 2006 the Judge granted the defendant groups’ motion for partial summary judgment dismissing plaintiffs’ tort-based claims. Also on the same date, the Judge granted the defendant groups’ motion for partial summary judgment seeking to deny the plaintiffs an award of attorneys’ fees and also to dismiss any claim of plaintiffs that defendants had an obligation to form a field-wide unit.

Broussard Plaintiff Settlement.

On December 19, 2006, we, along with the other defendants in this suit, reached a settlement agreement with the Broussard Plaintiffs in full settlement of their 72% of the total claims made in this consolidated action.  This settlement was finalized in January 2007.  Our share of this settlement totaled approximately $208,000, which was recorded in December 2006, and the Sfondrini Partnerships’ share totaled $1,109,759.  The settlement with the Broussard Plaintiffs was finalized on February 1, 2007, and the defendants and the third-party defendants including the Sfondrini Partnerships were released from all claims by the Broussard Plaintiffs.

The Sfondrini Partnerships did not have sufficient cash to fund their respective full portion of the settlement.  Therefore, in order to facilitate the settlement, we purchased certain oil and gas properties from certain of the Sfondrini Partnerships, with the proceeds of such sale and purchase generally being directed to payment of the Broussard settlement, in full satisfaction of the Sfondrini Partnerships’ share of such settlement.  The oil and gas properties that we purchased from the Sfondrini Partnerships and their respective purchase prices are as follows:

(1)          100% of each of Edge Group Partnership’s, Edge Option I Limited Partnership’s, Edge Option II Limited Partnership’s and Edge Option III Limited Partnership’s interest in the Ilse Miller No. 2 Well and leases, Wharton County, Texas, for a total combined value of $51,243.

(2)          100% of each of Edge Group Partnership’s, Edge Option I Limited Partnership’s, Edge Option II Limited Partnership’s and Edge Option III Limited Partnership’s interest in the Wm Baas 2-16 No. 1 Well and leases, Monroe County, Alabama, for a total combined value of $14,407.

(3)          55.953% of Edge Group Partnership’s interest in certain wells and leases in the Company’s Austin and Nita prospects, for a total value of $1,044,109.

In the purchase and sale transaction between us and the Sfondrini Partnerships, BV Partners Limited Partnership, whose 2.48% share of the Broussard settlement amount was $186,000 (as determined by us and Mr. Sfondrini on behalf of the BV Partners Limited Partnership), did not sell any assets to us and did not have sufficient funds to satisfy their share of the settlement amount.  In addition, the Edge Option I, II and III Limited Partnerships did not have sufficient assets to satisfy their respective .34%, .34% and 2.25% shares of the settlement amount, which we and Mr. Sfondrini determined to be $25,750, $25,750 and $169,102, respectively.  The shortfall amounts of Edge Option I, II and III Limited Partnerships were, net of assets that they sold to us, determined by us and Mr. Sfondrini to be $24,333, $24,333 and $163,276, respectively.  As a result, Edge Group Partnership sold additional properties (over the amount necessary to fund its portion of the settlement) to us at fair market value in an amount sufficient to allow it to have proceeds from such sale to fund BV Partners Limited Partnership’s share of the settlement and the remaining shortfall amounts owed by Edge Option I, II and III.  In return, BV Partners and Edge Option I, II and III contributed all of their interest in the Bayou Vermilion Prospect leases and the Trahan No. 3 well

30




located thereon to Edge Group Partnership.  The fair market value of these interests contributed to Edge Group by BV Partners Limited Partnership and Edge Option I, II and III were determined by us and Mr. Sfondrini on behalf of such partnerships to be $27,793, $3,847, $3,847 and $25,263, respectively.

The valuations of the interests of the Sfondrini Partnerships purchased by us and the interests contributed to Edge Group Partnership by BV Partners and Edge Option I, II and III were made at an agreed value, using a PV10 model and assuming $7.50/MMBtu gas and $60/BBl oil, which we believed represented current pricing levels for oil and gas properties at the time, and were agreed to by us and Mr. Sfondrini, on behalf of the Sfondrini Partnerships.

The trial on the remaining claims, those of the Montet plaintiffs (approximately 28% of the original aggregate claims in the case), is now set for trial beginning August 27, 2007.  The Montet plaintiffs’ calculation of their alleged damages has not changed.  If the jury were to adopt the plaintiffs’ damage figures, the total damages attributable to the Montet plaintiffs could be approximately $17.6 million.  The defendants’ exposure for an 18.75% share of that number would be approximately $3.31 million.  The exposure for our approximate 2.8% share would be approximately $493,000.  If there were a damage award against the defendants, we believe that ultimately we should only be liable for our 2.8% share of any such award unless a co-party defendant, including any of the third-party defendants, cannot satisfy their share of any final judgment or settlement amount or are found not to be liable to us on our third-party demand.  In that event, we could be held responsible for more than our 2.8% share.  We believe we have meritorious defenses and intend to continue to vigorously contest this suit and our third-party demands against the partnerships.  We have not established a reserve with respect to these claims.

We may have insurance coverage for all or part of this claim up to the policy limits of $1 million per occurrence and $2 million in the aggregate. A claim was submitted to Mid-Continent Casualty Company, our casualty carrier, who is currently providing a defense under a reservation of rights letter.   However, on July 3, 2006, Mid-Continent filed a suit for declaratory judgment against us in federal district court in Houston, Texas seeking to determine whether it has a duty to indemnify us and certain other defendants for this loss under the policies at issue.   Mid-Continent has asked the court to declare they have no obligation to indemnify us and the third-party defendants based on certain technical definitions under the policies and the fact that the plaintiffs’ claims are based on alleged breaches of contract. We are both vigorously defending the declaratory judgment action, and actively seeking indemnity under the policies at issue for our potential liabilities, if any, to the plaintiffs in the Louisiana actions.  We are also pursuing coverage claims under other insurance policies that could cover a portion of our share of a loss in this case.

David Blake, et al. v. Edge Petroleum Corporation – On September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake 1992 Children’s Trust filed suit against us in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in at least five leases in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortuous interference; and (5) attorneys’ fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants.  We have served plaintiffs with discovery and have filed a counterclaim and an amended counterclaim joining various related entities that are controlled by plaintiffs.  In addition, plaintiffs have filed an amended complaint alleging claims of slander of title and tortuous interference related to its alleged right to receive an overriding royalty interest from a third party.  Plaintiffs currently have on file an amended motion for summary judgment, to which we have filed a response.  In addition, we have filed a motion for summary judgment on the plaintiffs’ case.  In December 2006, the court denied our motion for summary judgment.  The court has not ruled on Blake’s motion.  The trial setting in March 2007 has been postponed by agreement of the parties and reset to September 15, 2007.  Discovery in the case has commenced and is continuing. We have responded aggressively to this lawsuit, and believe we have meritorious defenses and counterclaims.

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

None.

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Executive Officers of the Registrant

Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G (3) to Form 10-K, the following information is included in Part I of this Form 10-K.

John W. Elias has served as the Chief Executive Officer and Chairman of the Board of the Company since November 1998.  From April 1993 to September 30, 1998, he served in various senior management positions, including Executive Vice President, of Seagull Energy Corporation, a company engaged in oil and natural gas exploration, development and production and pipeline marketing.  Prior to April 1993, Mr. Elias served in various positions for more than 30 years, including senior management positions with Amoco Corporation, a major integrated oil and gas company.  Mr. Elias has more than 40 years of experience in the oil and natural gas exploration and production business.  He is 66 years old.

Michael G. Long has served as Executive Vice President and Chief Financial Officer of the Company since April 2005 and as Senior Vice President and Chief Financial Officer since December 1996, and as Treasurer of the Company since October 2004.  Mr. Long served as Vice President-Finance of W&T Offshore, Inc., an oil and natural gas exploration and production company, from July 1995 to December 1996.  From May 1994 to July 1995, he served as Vice President of the Southwest Petroleum Division for Chase Manhattan Bank, N.A.  Prior thereto, he served in various capacities with First National Bank of Chicago, most recently that of Vice President and Senior Corporate Banker of the Energy and Transportation Department, from March 1992 to May 1994.  Mr. Long received a B.A. in Political Science and a M.S. in Economics from the University of Illinois.  Mr. Long is 54 years old.

John O. Tugwell has served as Chief Operating Officer and Executive Vice President since April 2005 and prior to that served as Chief Operating Officer and Senior Vice President of Production for the Company since March 2004 and prior to that as Vice President of Production since March 1997. He served as Senior Petroleum Engineer of the Company’s predecessor corporation since May 1995.  From 1986 to May 1995, Mr. Tugwell held various reservoir/production engineering positions with Shell Oil Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum Engineering from Louisiana State University.  Mr. Tugwell is a registered Professional Engineer in the State of Texas.  Mr. Tugwell is 43 years old.

Significant Employees

C.W. MacLeod has served as the Senior Vice President Business Development and Planning for the Company since April 2004 and Vice President Business Development and Planning for the Company since January 2002. From November 1999 to December 2001, he was Vice President - Investment Banking with Raymond James and Associates, Inc.  From February 1990 to October 1999, Mr. MacLeod was a principal with Kirkpatrick Energy Associates, Inc., whose principal business was merger and acquisition services, capital arrangement and analytical services for the oil and gas producing industry.  Mr. MacLeod was responsible for originating corporate finance and research products for energy clients.  His previous experience includes positions as an independent petroleum geologist, a manager of exploration and production for an independent oil and gas producer and geologic positions with Ladd Petroleum Corporation and Resource Sciences Corporation.  Mr. MacLeod graduated from Eastern Michigan University with a B.S. in Geology and earned his M.B.A. from the University of Tulsa.  Mr. MacLeod is a registered professional geologist in the State of Wyoming.  He is 56 years old.

Howard Creasey has served as the Senior Vice President of Exploration since October 2006 and prior to that as the Vice President of Exploration since October 2005.  Before October 2005, Mr. Creasey was Chief Geologist for the Company since October 2003.  From April of 1999 until October 2003 he served as a Senior Staff Geologist for Devon Energy and its predecessor Ocean Energy.  Prior to April 1999 for 14 years Mr. Creasey served as President and Exploration Geologist for Moss Rose Energy, Inc., a company he started in 1986.  Mr. Creasey holds a B.S. in Geology from Stephen F. Austin State University, has been a member of the AAPG for over 25 years and is a Certified Geoscientist in the State of Texas.   Mr. Creasey is 51 years old.

Kirsten A. Hink has served as Vice President and Controller of the Company since October 1, 2003 and as Controller of the Company since December 31, 2000.  Prior to that time she served as Assistant Controller from June 2000 to December 2000.  Before joining Edge, she served as Controller of Benz Energy Inc., an oil and gas exploration company, from June 1998 to June 2000.  Mrs. Hink received a B.S. in Accounting from Trinity University.  Mrs. Hink is a Certified Public Accountant in the State of Texas.  She is 40 years old.

Kurt P. Primeaux has served as Vice President of Production since October 2006, Manager of Production Operations from April 2004 to October 2006, and before that, as Senior Petroleum Engineer from August 2003 to April 2004.  Prior to joining the Company, he held similar positions with Union Oil of California from June 1998 to

32




August 2003, most recently that of Resource Manager.  Mr. Primeaux began his career with Texaco USA in 1988 and has over 18 years experience in reservoir, drilling, production and operations engineering.  He holds a B.S. degree in Petroleum Engineering from Louisiana State University and an M.S. degree in Environmental Engineering from Tulane University.  He is 43 years old.

R. Keith Turner has served as Vice President of Land for the Company since September 2006.  Before moving to the Land Department, Mr. Turner was a Staff Attorney in the Legal Department since 2003.  Prior to joining the Company in 2003, Mr. Turner served in various capacities with Newfield Exploration Company, Fina Oil and Chemical Company and Torch Energy Advisors, Inc.  He received a B.S. in Science from Stephen F. Austin State University and a J.D. degree from South Texas College of Law.  Mr. Turner is 52 years old.

Robert C. Thomas has served as Senior Vice President, General Counsel and Corporate Secretary since October 2006 and prior to that as Vice President, General Counsel and Corporate Secretary since March 1997.  From February 1991 to March 1997, he served in similar capacities for the Company’s corporate predecessor.  From 1988 to January 1991, he was associate and acting general counsel for Mesa Limited Partnership in Amarillo, Texas.  Mr. Thomas holds a B.S. degree in Finance and a J.D. degree in Law from the University of Texas at Austin.  He is 53 years old.

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Price of and Dividends on Common Equity and Related Stockholder Matters.

As of March 8, 2007, we estimate there were approximately 236 record holders of our common stock.  Our common stock is listed on the NASDAQ Global Select Market (“NASDAQ”) and traded under the symbol “EPEX”.  As of March 8, 2007, we had 28,383,455 shares outstanding and our closing price on NASDAQ was $11.97 per share.  The following table sets forth, for the periods indicated, the high and low closing sales prices for our common stock as listed on NASDAQ.

 

Common Stock Prices

 

 

 

High
($)

 

Low
($)

 

Calendar 2006

 

 

 

 

 

First Quarter

 

34.65

 

22.89

 

Second Quarter

 

26.85

 

16.60

 

Third Quarter

 

21.58

 

15.28

 

Fourth Quarter

 

20.26

 

15.00

 

 

 

 

 

 

 

Calendar 2005

 

 

 

 

 

First Quarter

 

18.24

 

13.40

 

Second Quarter

 

16.86

 

12.46

 

Third Quarter

 

27.94

 

15.47

 

Fourth Quarter

 

28.49

 

20.05

 

 

We have never paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future.  In addition, under our current credit facility, we are restricted from paying cash dividends on our common stock.  The payment of future dividends, if any, will be determined by our Board of Directors in light of conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing agreements, business conditions and other factors.  See ITEMS 1A. “RISK FACTORS We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.”

There were no repurchases of securities during the fourth quarter of 2006.

Performance Graph

The following performance graph compares the cumulative total stockholder return on the common stock to the cumulative total return of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and an index composed of all publicly traded oil and gas companies identifying themselves by primary Standard Industrial Classification (“SIC”) Code 1311 (Crude Petroleum and Natural Gas) for the period beginning December 31, 2001 and ending December 31, 2006.

34




COMPARE 5-YEAR CUMULATIVE TOTAL RETURN

AMONG EDGE PETROLEUM CORPORATION, S&P 500 INDEX

AND SIC CODE 1311 INDEX

The graph assumes that $100 was invested on December 31, 2001 in each of Edge common stock, the S&P 500 Index and the SIC Code 1311 companies and assumes that all dividends were reinvested:

 

Edge Petroleum

 

S&P 500 Index

 

SIC Code Index

 

December 31, 2001

 

$

100.00

 

$

100.00

 

$

100.00

 

December 31, 2002

 

$

70.75

 

$

77.90

 

$

106.61

 

December 31, 2003

 

$

190.94

 

$

100.25

 

$

171.22

 

December 31, 2004

 

$

275.09

 

$

111.15

 

$

217.51

 

December 31, 2005

 

$

470.00

 

$

116.61

 

$

312.49

 

December 31, 2006

 

$

344.15

 

$

135.03

 

$

406.32

 

 

35




ITEM 6.  SELECTED FINANCIAL DATA

The following table sets forth selected financial data regarding the Company as of and for each of the periods indicated.  The following data should be read in conjunction with ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS” and ITEM 8. “FINANCIALS STATEMENTS AND SUPPLEMENTARY DATA”:

 

 

Year Ended December 31,

 

 

 

2006 (1) (2)

 

2005 (3)

 

2004 (4)

 

2003 (5)

 

2002

 

 

 

(in thousands, except per share amounts)

 

Statement of operations:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue

 

$

129,744

 

$

121,183

 

$

64,505

 

$

33,926

 

$

20,911

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas operating expenses including production and ad valorem taxes

 

18,257

 

17,068

 

9,309

 

5,116

 

3,831

 

Depletion, depreciation, amortization and accretion (5)

 

61,080

 

40,218

 

21,928

 

13,577

 

10,427

 

Impairment of oil and natural gas properties (6)

 

96,942

 

 

 

 

 

General and administrative expenses and bad debt expense

 

13,788

 

12,436

 

9,447

 

7,132

 

5,229

 

Total operating expenses

 

190,067

 

69,722

 

40,684

 

25,825

 

19,487

 

Operating income (loss)

 

(60,323

)

51,461

 

23,821

 

8,101

 

1,424

 

Interest expense and amortization of deferred loan costs, net of amounts capitalized

 

(2,665

)

(153

)

(473

)

(679

)

(228

)

Interest income

 

152

 

128

 

36

 

17

 

27

 

Income (loss) before income taxes and cumulative effect of accounting change

 

(62,836

)

51,436

 

23,384

 

7,439

 

1,223

 

Income tax (expense) benefit

 

21,575

 

(18,078

)

(8,255

)

(2,731

)

(473

)

Income (loss) before cumulative effect of accounting change

 

(41,261

)

33,358

 

15,129

 

4,708

 

750

 

Cumulative effect of accounting change (5)

 

 

 

 

(358

)

 

Net income (loss)

 

$

(41,261

)

$

33,358

 

$

15,129

 

$

4,350

 

$

750

 

Basic earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before cumulative effect of accounting change

 

$

(2.38

)

$

1.95

 

$

1.16

 

$

0.48

 

$

0.08

 

Cumulative effect of accounting change

 

 

 

 

(0.03

)

 

Basic earnings (loss) per share

 

$

(2.38

)

$

1.95

 

$

1.16

 

$

0.45

 

$

0.08

 

Diluted earnings (loss) per share :

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before cumulative effect of accounting change

 

$

(2.38

)

$

1.87

 

$

1.11

 

$

0.47

 

$

0.08

 

Cumulative effect of accounting change (5)

 

 

 

 

(0.03

)

 

Diluted earnings (loss) per share

 

$

(2.38

)

$

1.87

 

$

1.11

 

$

0.44

 

$

0.08

 

Basic weighted average number of shares outstanding (7)

 

17,368

 

17,122

 

13,029

 

9,726

 

9,384

 

Diluted weighted average number of shares outstanding (7)

 

17,368

 

17,815

 

13,648

 

9,988

 

9,606

 

EBITDA Reconciliation (8):

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(41,261

)

$

33,358

 

$

15,129

 

$

4,350

 

$

750

 

Cumulative effect of accounting change (5)

 

 

 

 

358

 

 

Income tax expense (benefit)

 

(21,575

)

18,078

 

8,255

 

2,731

 

473

 

Interest expense and amortization of deferred loan costs, net of amounts capitalized

 

2,665

 

153

 

473

 

679

 

228

 

Interest income

 

(152

)

(128

)

(36

)

(17

)

(27

)

Depletion, depreciation, amortization and accretion (5)

 

61,080

 

40,218

 

21,928

 

13,577

 

10,427

 

EBITDA

 

$

757

 

$

91,679

 

$

45,749

 

$

21,678

 

$

11,851

 

 

36




 

 

 

As of December 31,

 

 

 

2006 (1) (2)

 

2005 (3)

 

2004 (4)

 

2003 (5)

 

2002

 

 

 

(in thousands)

 

Selected Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

97,409

 

$

93,111

 

$

42,270

 

$

23,898

 

$

10,408

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash used in investing activities

 

$

(140,412

)

$

(167,280

)

$

(89,410

)

$

(28,070

)

$

(19,255

)

Net cash provided by financing activities

 

$

44,418

 

$

72,568

 

$

48,080

 

$

2,931

 

$

10,623

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Working capital (9)

 

$

10,162

 

$

10,537

 

$

8,957

 

$

948

 

$

3,310

 

Property and equipment, net

 

289,457

 

306,456

 

165,840

 

97,981

 

75,682

 

Total assets

 

321,657

 

343,380

 

190,990

 

118,012

 

85,576

 

Long-term debt, including current maturities

 

129,000

 

85,000

 

20,000

 

21,000

 

20,500

 

Stockholders’ equity (7)

 

156,052

 

191,755

 

150,467

 

82,011

 

58,533

 

 


(1)                  As discussed in Note 6 to our consolidated financial statements, we completed one significant property acquisition in December 2006 and various other working interest acquisitions throughout the year, which could affect the comparability of our results in 2006 to prior periods.

(2)                  As discussed in Note 9 to our consolidated financial statements, in 2006 we discontinued the use of cash flow hedge accounting on our natural gas contracts.  During 2006, mark-to-market accounting treatment was applied to these contracts, which affects the comparability of our results in 2006 to prior periods.

(3)                  As discussed in Note 6 to our consolidated financial statements, we completed one property acquisition and one corporate acquisition in the fourth quarter of 2005, which affects the comparability of our results in 2005, and subsequent periods, to prior periods.

(4)                  As discussed in Note 6 to our consolidated financial statements, we completed the merger with Miller in December 2003, which affects the comparability of our results in 2004, and subsequent periods, to prior periods.

(5)                  As discussed in Note 7 to our consolidated financial statements, effective January 1, 2003, we changed our method of accounting for asset retirement obligations, which affects the comparability of our results in 2003, and subsequent periods, to prior periods.

(6)                  As discussed in Note 2 to our consolidated financial statements, in the third quarter of 2006 we recorded an impairment of oil and natural gas properties in the amount of $96.9 million ($63.0 million, net of tax) as a result of our full-cost ceiling test.  The impairment of oil and natural gas properties was primarily the result of a decline in natural gas prices at September 30, 2006, the date of impairment measurement for the full-cost ceiling test.  No such impairment was necessary in the years 2002 through 2005.

(7)                  As discussed in Note 11 to our consolidated financial statements, we completed a public offering of our common stock on December 21, 2004 and a significant property acquisition on December 29, 2004, therefore certain of our results in 2004 and subsequent periods are not directly comparable to periods prior to 2004.

(8)                  EBITDA is defined as net income (loss) before cumulative effect of accounting change, interest expense and amortization of deferred loan costs (net of interest income and amounts capitalized), income tax expense, depletion, depreciation and amortization and accretion expense. EBITDA is not adjusted for the full-cost ceiling test impairment recorded in 2006.  EBITDA is a financial measure commonly used in the oil and natural gas industry, but is not defined under accounting principles generally accepted in the United States of America (“GAAP”). EBITDA should not be considered in isolation or as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP or as a measure of a company’s profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income, this measure may vary among companies. The EBITDA data presented above may not be comparable to a similarly titled measure of other companies. Our management believes that EBITDA is a meaningful measure to investors and provides additional information about our ability to meet our future liquidity requirements for debt service, capital expenditures and working capital. In addition, management believes that EBITDA is a useful comparative measure of operating performance and liquidity.  For example, debt levels, credit ratings and, therefore, the impact of interest expense on earnings vary significantly between companies. Similarly, the tax positions of individual companies can vary because of their differing abilities to take advantage of tax benefits, with the result that their effective tax rates and tax expense can vary considerably. Finally, companies differ in the age and method of acquisition of productive assets, and thus the relative costs of those assets, as well as in the depreciation or depletion (straight-line, accelerated, units of production) method, which can result in considerable variability in depletion, depreciation and amortization expense between companies. Thus, for comparison purposes, management believes that EBITDA can be useful as an objective and comparable measure of operating profitability and the contribution of operations to liquidity because it excludes these elements.

(9)                  Working Capital is defined as current assets less current liabilities.

We do not pay cash dividends on our common stock and have not in the periods presented above; therefore, they are not presented in the selected financial data.  We expect to pay dividends on our 5.75% Series A cumulative convertible perpetual preferred stock issued in our January 2007 offering.

37




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

The following is a review of our financial position and results of operations for the periods indicated.  Our Consolidated Financial Statements and Supplementary Information and the related notes thereto contain detailed information that should be referred to in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”).

GENERAL OVERVIEW

Edge Petroleum Corporation (“Edge”, “we” or the “Company”) is a Houston-based independent energy company that focuses its exploration, development, production, acquisition and marketing activities in selected onshore basins of the United States. In late 1998, we undertook a top-level management change and began a shift in strategy from pure exploration, which focused more on prospect generation, to our current strategy which focuses on a balanced program of exploration, exploitation and development and acquisition of oil and gas properties. We generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We make significant capital expenditures in our exploration, development, and production activities that allow us to continue generating revenue, income and cash flows.  We have also spent considerable efforts on acquisitions, including both corporate and asset acquisitions, which have contributed to our growth in recent years.

This overview provides our perspective on the individual sections of MD&A.  Our MD&A includes the following sections:

·                  Industry and Economic Factors – a general description of value drivers of our business as well as opportunities, challenges and risks related to the oil and gas industry.

·                  Approach to the Business – additional information regarding our approach and strategy.

·                  Acquisitions and Divestitures – information about significant changes in our business structure.

·                  Outlook – additional discussion relating to management’s outlook to the future of our business.

·                  Critical Accounting Policies and Estimates – a discussion of certain accounting policies that require critical judgments and estimates.

·                  Results of Operations – an analysis of our consolidated results for the periods presented in our financial statements.

·                  Liquidity and Capital Resources an analysis of cash flows, sources and uses of cash, and contractual obligations.

·                  Risk Management Activities Derivatives & Hedging supplementary information regarding our price-risk management activities.

·                  Tax Matters – supplementary discussion of income tax matters.

·                  Recently Issued Accounting Pronouncements – a discussion of certain recently issued accounting pronouncements that may impact our future results.

INDUSTRY AND ECONOMIC FACTORS

In managing our business, we must deal with many factors inherent in our industry.  First and foremost is the fluctuation of oil and gas prices.  Historically, oil and gas markets have been cyclical and volatile, which makes future price movements difficult to predict.  While our revenues are a function of both production and prices, wide

38




swings in commodity prices have most often had the greatest impact on our results of operations. We have little ability to predict those prices or to control them without losing some advantage of the upside potential. During 2006, natural gas prices steadily declined from their record highs at the end of 2005.  Crude oil prices spiked to an all-time high in the summer of 2006, but subsequently declined to a price similar to the price at the end of 2005. Despite these changes in 2006, oil and gas prices remain at historically high levels.

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, we may still 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 reserves being discovered.  Moreover, costs associated with operating within our industry are substantial. The high commodity price environment in 2005 led to increased costs in our industry, and in 2006, we saw commodity prices decline while operating costs continued to increase.  These factors, together with increased demand for rigs, equipment, supplies and services, have made it difficult at times for us to further our growth, and made timely execution of our planned activities difficult.

Our business, as with other extractive businesses, is a depleting one in which each gas equivalent produced must be replaced or our asset base and capacity to generate revenues in the future will shrink.

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 exploration, production, marketing and acquisition activities.  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 operational and 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 business will largely depend upon our ability to successfully find and develop new proved reserves of oil and natural gas in a cost-effective manner.  In order to achieve an overall acceptable rate of growth, we seek to maintain a prudent blend of low-, moderate- and higher-risk exploration and development projects.  We have chosen to seek geologic and geographic diversification by operating in multiple basins in order to mitigate risk in our operations. We also attempt to make selected acquisitions of oil and gas properties to augment our growth and provide future drilling opportunities.

We periodically hedge our exposure to volatile oil and gas prices on a portion of our production to reduce price risk. In 2006, we had 53% and 42% of our natural gas and crude oil production, respectively, hedged.  As of March 9, 2007, we have derivative contracts in place covering approximately 60% and 72% of our anticipated 2007 natural gas and crude oil production, respectively, including the effect of the Smith acquisition which closed in January 2007, but before any other acquisitions that may occur.

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.  Our Board recently approved a 2007 capital budget of approximately $140 million. Based on current expectations for production volumes and commodity prices, we expect to fund those capital expenditures from internally generated cash from operating activities. We do not typically include acquisitions in our budgeted capital expenditures, but expect to fund those with either borrowings under our credit facility, proceeds from offerings of common stock or other securities under our shelf registration statement or other sources.

For 2006, we reported a 5% increase in annual production volumes over the 2005 period. We also replaced 97% of our total 2006 production (see ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – OIL AND NATURAL GAS RESERVE REPLACEMENT”).  At December 31, 2006, our net proved reserves were 102.1 Bcfe, of which approximately 77% were developed.  In addition, in January 2007, we acquired certain oil and gas properties from Smith Production Inc., as discussed below in “ACQUISITIONS AND DIVESTITURES - Acquisitions.”  Following the completion of our two recent public offerings that resulted in net proceeds of approximately $276.7 million, we believe we are in a strong financial position.  We have unused borrowing capacity of $85.0 million as of March 9,

39




2007.  Operationally and financially, we believe we are well positioned to continue the execution of our business strategy during 2007.

ACQUISITIONS AND DIVESTITURES

Acquisitions - We have become increasingly active in acquisitions in recent years. We have looked to acquisitions to enable us to achieve our growth objectives and we expect acquisitions will continue to play a significant role in our future plans for growth. Acquisitions add meaningful incremental increases in reserves and production and may range in size from acquiring a working interest in non-operated producing property to an entire field or company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated.  Specific timing and size of acquisitions cannot be predicted. Although we consider a wide variety of acquisitions, a significant part of our growth strategy is expected to be focused toward producing property acquisitions, which we believe have exploitable potential. Because of our financial flexibility, we are positioned to take advantage of opportunities to acquire producing properties as they may arise. In today’s high-price environment, where production is providing greater cash flow and earnings to most companies in our industry, identifying quality opportunities is difficult. We believe through hard work, technical ability and creative thinking, we will continue to grow through both acquisitions and drilling. Any such acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities.

On January 31, 2007, we completed the purchase. of certain oil and natural gas properties located in 13 counties in south and southeast Texas and other assets from Smith Production Inc.  We paid approximately $389.8 million for these assets.  In total, the Smith assets include approximately 150 gross producing wells (74 net) and an ownership interest in approximately 17,000 gross (12,250 net) developed acres and 56,000 gross (16,000 net) undeveloped acres of leasehold, all as of December 31, 2006.  In addition to the properties and related acreage, we acquired from Smith certain gathering facilities and ownership of approximately 13 miles of natural gas gathering pipelines and related infrastructure serving certain producing assets in southeast Texas. The pipeline system transports our natural gas as well as third-party natural gas.  We also acquired 25% of Smith’s option and leasehold rights in an approximate 95 square mile 3-D exploration area with approximately 30,000 gross acres of leases and options located in the Mission project area in Hidalgo County in south Texas, with a primary focus on the Vicksburg formation.  We acquired a 12.5% working interest in an approximate 160 square mile 3-D exploration area with approximately 55,000 gross acres of leases and options located in the Yates Ranch/Hostetter project area in McMullen and Duval Counties in south Texas. The 160 mile 3-D area increases our exposure to the Middle and Deep Wilcox trend. Furthermore, this venture allows us to participate in a proposed additional 3-D shoot covering approximately 120 square miles near the Yates Ranch within the Wilcox trend. We also acquired 25% of Smith’s option and leasehold rights in an approximate 105 square mile 3-D exploration area with approximately 60,000 gross acres of leases and options in Newton County in southeast Texas and Beauregard Parish in Louisiana with a focus on prospects in the Frio, Yegua and Wilcox formations at depths ranging between 4,000 and 10,000 feet.  We financed the Smith acquisition through concurrent public offerings of 10.925 million shares of our common stock and 2.875 million shares of our Series A preferred stock, along with borrowings under a new revolving credit facility.

On December 28, 2006, we completed an acquisition of certain working interests in the Chapman Ranch Field in Nueces County, Texas from Kerr-McGee, a wholly-owned subsidiary of Anadarko Petroleum Corporation.  In late 2005, we acquired non-operated working interests ranging from 44% to 50% in several producing wells in this field, as discussed below.  In the Kerr-McGee acquisition, we acquired an additional 44% to 50% working interest in the same wells in the field and acquired two additional wells, bringing our working interests in those Chapman Ranch properties, including a total of nine producing wells, to 88% to 100%.  The base purchase price of the acquisition was $26.0 million.  The purchase price was preliminarily adjusted at closing to approximately $25 million (including a previously paid deposit of $2.6 million) as a result of adjustments to the purchase price for the results of operations between the December 1, 2006 effective date and the December 28, 2006 closing date, and other purchase price adjustments.  There may be post-closing adjustments to the purchase price for results of operations between the effective date and closing date as further information becomes available.  We financed the purchase price of the Kerr-McGee acquisition through $24.0 million in borrowings under our credit facility, the borrowing base of which was increased in connection with this transaction (see Note 10 to our consolidated financial statements).

On September 21, 2005, we acquired (i) the stock of a private company, Cinco Energy Corporation (“Cinco”), whose primary asset is ownership of working interests in oil and natural gas properties located on the Chapman Ranch Field in south Texas and (ii) additional working interests in the same field owned by two other private

40




companies for an aggregate cash purchase price of approximately $74.9 million (of which $46.9 million was attributable to the stock purchase and $28.0 million was attributable to the working interest asset purchase). We allocated approximately $17.5 million of the total purchase price to the unproved property category. The properties acquired from these entities are located in Nueces County, Texas and consisted of six producing wells, one well undergoing completion operations, and one well shut in for evaluation, as well as an ownership interest in approximately 1,300 net acres of developed and undeveloped leasehold.  We financed the acquisitions through borrowings under our then-existing credit facility, the borrowing base of which was increased in connection with the acquisitions and other activities after the last redetermination.

On October 13, 2005, we consummated the Chapman Ranch Field asset acquisition for a final purchase price of $28.0 million. On November 30, 2005, we consummated the Cinco stock purchase for a final purchase price of $46.9 million.

On December 29, 2004, we acquired oil and natural gas properties located in south Texas from Contango Oil & Gas Company (“Contango”) for a final purchase price of $40.1 million.  We financed the acquisition with proceeds from a public offering of our common stock under our shelf registration (see Note 11 to our consolidated financial statements). The properties acquired consisted of 39 non-operated producing wells with working interests ranging from approximately 41% to 75% and net revenue interests ranging from 29% to 56%. These properties, located primarily in Jim Hogg County, Texas and producing primarily from the Queen City formation, are in a geographic area that has been one of our most active and successful areas of focus in recent years. In addition to estimated proved reserves, our technical team also identified a substantial number of additional drilling locations on undeveloped acreage for which we realized much of the exploitable potential in 2005 and 2006.  We believe this area to be a continued target of exploitable potential for us in future years.

Divestitures - We regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While we generally do not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the first half of 2006, we sold our Buckeye properties in Live Oak County, Texas for $627,645.  During 2005, we had no divestitures. During 2004, our net proceeds from asset divestitures of $60,000 were primarily derived from the sale of certain oil and gas properties and equipment in Texas, Mississippi and Louisiana.

OUTLOOK

·                  We successfully completed one significant acquisition during 2006, as well as a large, transforming acquisition in the first quarter of 2007, both of which added valuable reserves in our core areas in Texas. We also completed smaller working interest acquisitions in 2006.  We expect to continue to spend considerable effort in 2007 on acquisitions, as we seek to further our growth.

·                  We expect to drill between 80 and 90 wells (37 and 42 net, respectively) in 2007 and we estimate capital spending for the year to be approximately $140 million. Our ability to materially increase the number of wells to be drilled is heavily dependent upon the timely access to oilfield services, particularly drilling rigs.  The shortage of available rigs in 2006 delayed the drilling of several wells, slowing growth in our production for the year.

·                  Drilling activities in the Fayetteville Shale play were initiated during the second quarter of 2006 and we expect that activity to continue into 2007.

·                  In order to manage our realized growth in 2006 and our anticipated growth for the next several years, we increased our headcount from 62 employees as of December 31, 2005 to 68 employees as of December 31, 2006, resulting in increased G&A costs for 2006. We have added and expect to continue to add to our staff levels again in 2007 both as a result of recent growth and anticipated future growth.

·                  To help protect against the possibility of downward commodity price movements and lost revenue, we have several derivatives in place to hedge a portion of our expected natural gas and crude oil production streams for 2007 and 2008. While there was no cash impact from our oil derivatives contracts, our gas derivatives contracts contributed $4.7 million to our cash flows in 2006. We discontinued cash flow hedge accounting treatment on our natural gas collars, and thus all of our derivative transactions are now accounted for using mark-to-market accounting treatment (see Note 9 to our consolidated financial statements).

·                  We recorded a $96.9 million ($63.0 million, net of tax) non-cash impairment relating to our oil and natural gas properties during the third quarter of 2006 resulting from our full-cost ceiling test. Natural gas prices

41




fell below $5.00 per MMBtu at September 30, 2006, but subsequently rose above $6.00 per MMBtu after the third quarter end, which we believe would have allowed us to avoid the impairment if, as would have been allowed under applicable accounting guidelines, we had elected to use such subsequent prices in determining the calculation of our ceiling test at September 30, 2006. However, oil and natural gas prices are expected to continue to be volatile in the future.  The benefit of the write-down is that it is expected to decrease future depletion expense and we believe that it will more appropriately state our capitalized costs.

Our outlook and the expected results described above are both subject to change based upon factors that include, but are not limited to, drilling results, commodity prices, access to capital, the acquisitions market and factors referred to in “FORWARD LOOKING INFORMATION.”

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying financial statements.  Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

·                  it requires assumptions to be made that were uncertain at the time the estimate was made, and

·                  changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate.

Nature of Critical Estimate Item: Oil and Natural Gas Reserves - Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.  For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results.  In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change.  Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements.

Assumptions/Approach Used: Units-of-production method to amortize our oil and natural gas properties - The quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate.

 “Ceiling” Test - The full-cost method of accounting for oil and gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling test. The ceiling is the discounted present value of our estimated total proved reserves adjusted for taxes and the impact of qualifying hedges on pricing, using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and gas properties is not reversible at a later date even if oil and gas prices increase. A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. During the year ended December 31, 2006, we recorded a ceiling test impairment of $96.9 million ($63.0 million, net of tax).  No such impairment was required in the years ended December 31, 2005 and 2004. The ceiling test calculation dictates that prices and costs in effect as of the last day of the period are to be used in calculating the discounted present value of our estimated total proved reserves.  Oil and natural gas prices used in the reserve valuation at December 31, 2006 were $61.06 per barrel and $5.62 per MMbtu.

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Effect if different assumptions used: Units-of-production method to amortize our oil and natural gas properties - A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the year by approximately 10%.

“Ceiling” Test - The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in prices at a measurement date could trigger a full-cost ceiling impairment. Such a reduction from June 30, 2006 to September 30, 2006 was primarily responsible for our impairment in the third quarter of 2006.  Subsequent to September 30, 2006, quoted market prices for natural gas increased such that we believe we would have avoided a write down if, as would have been allowed under applicable accounting guidelines, we had elected to use such subsequent prices in calculating our ceiling test at September 30, 2006.  We had a cushion (i.e. the excess of the ceiling over our capitalized costs) of $31.9 million, net of tax, at December 31, 2006.  A 10% increase or decrease in prices used would have increased or decreased, respectively, our cushion by approximately 78%. Our hedging program would serve to mitigate some of the economic impact of any price decline. However, since we no longer apply cash flow hedge accounting to our derivative contracts, our hedging program does not impact the ceiling test. Had we applied cash flow hedge accounting to our outstanding derivative contracts, the cushion at December 31, 2006 would have increased by approximately $11.1 million. Another likely factor to contribute to a ceiling test impairment is a revised estimate of reserve volume. A 10% increase or decrease in reserve volume would have increased or decreased, respectively, our cushion at December 31, 2006 by approximately 53%, net of tax.  As noted above, we used pricing and costs as of the last day of the period to determine our ceiling test.  Should commodity prices decrease significantly in 2007, the possibility of a ceiling test impairment at a future date exists.  Also, the effects of the Smith acquisition in 2007 could increase the possibility that we will be required to record a ceiling test impairment, particularly if commodity prices decline below the effective levels paid for in the Smith acquisition.

Nature of Critical Estimate Item: Unproved Property Impairment - We have elected to use the full-cost method to account for our oil and gas activities. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs.  Unproved properties are evaluated quarterly for impairment on a property-by-property basis.  If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized.

Assumptions/Approach Used: At December 31, 2006, we had $57.6 million allocated to unproved property. This allocation is based on our estimation of whether the property has potential attributable reserves. Therefore, our assessment of the potential reserves will determine whether costs are moved from the unproved category to the full-cost pool for depletion or whether an impairment is taken.

Effect if different assumptions used: A 10% increase or decrease in the unproved property balance (i.e. transfer to full-cost pool) would have decreased or increased, respectively, our depletion expense by approximately 2% for the year ended December 31, 2006.

Nature of Critical Estimate Item: Asset Retirement Obligations - We have certain obligations to remove tangible equipment and restore land at the end of oil and gas production operations.  Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Prior to the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, the costs associated with this activity were capitalized to the full-cost pool and charged to income through depletion. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”).  Primarily, SFAS No. 143 requires us to estimate asset retirement costs for all of our assets, adjust those costs for inflation to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset, and record an ARO liability in that amount with a corresponding addition to our asset value. When new obligations are incurred, i.e. new well drilled or acquired, we add a layer to the ARO liability. We accrete the liability layers quarterly using the applicable period-end effective credit-adjusted-risk-free rates for each layer. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation

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