EPEX Edge Petroleum Corp (MM)

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.

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.

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(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 16 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.

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        Leases covering approximately 41,530 gross (25,404 net), 38,449 gross (15,606 net) and 34,740 gross (26,145 net) undeveloped acres are scheduled to expire in 2008, 2009 and 2010, 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 37,487 gross (35,833 net) undeveloped acres in Texas for which we have the option to acquire leases based upon a commitment of continuous drilling. We estimate that these options to acquire leased acreage will expire in 2008, based on our current well and 3-D seismic acquisition schedule.

Core Areas of Operation

        As of December 31, 2007, 85% of our proved reserves were in Texas, 6% in Mississippi, 5% in New Mexico, and 4% in south Louisiana, Michigan, Alabama and Arkansas. In south Texas, our

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exploration and production activities are concentrated in three primary plays: Vicksburg, Queen City and Deep Frio trends. Our principal properties are located in the following areas of the United States:

        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, 2007. Net wells are calculated based on our working or net revenue interest in each of the properties we own.

(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.

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        We conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in south Texas, Mississippi, Arkansas, Louisiana and southeast New Mexico. Our resources and assets are managed and our results reported as one operating segment. The following table sets out a brief comparative summary of certain key 2007 data for each area.

South & southeast Texas

        As of December 31, 2007, we owned an interest in 151,295 gross (59,483 net) acres in Texas. Our areas of focus in this region are predominantly in the Vicksburg, Queen City and Deep Frio producing trends. As of December 31, 2007, we operated approximately 263 wells, which along with our 258 non-operated wells accounted for about 87% of our total net production in 2007. We drilled 31 wells during 2007 in Texas, 94% of which were apparent successes. The majority of our 2007 drilling activity took place in the Vicksburg project area. We drilled 20 apparently successful wells in the Vicksburg project area, five in the Deep Frio project area and four in the Queen City project area. In 2008, we currently expect to drill 14 gross wells (6 net) in our core areas in Texas. The majority of these wells are planned in the Vicksburg project area.

South Louisiana

        As of December 31, 2007, we owned an interest in 2,011 gross (575 net) acres in south Louisiana primarily located in Acadia, Calcasieu, Lafayette, St. Landry and Vermilion Parishes. As of December 31, 2007, we had an interest in 6 wells, none of which we operate. We did not drill any wells in south Louisiana in 2007 and we have no current plans to drill additional wells in this area in 2008.

Mississippi Interior Salt Basin

        As of December 31, 2007, we owned an interest in 25,706 gross (13,563 net) acres in the Mississippi Interior Salt Basin area and 44,732 gross (38,340 net) 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

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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, 2007, we operated eleven wells in this area. Production from wells in the Mississippi Interior Salt Basin accounted for approximately 4% of our total net production in 2007. In 2007, we drilled one well (1.0 net) in this area. We have no plans to drill additional wells in Mississippi at this time.

Michigan

        As of December 31, 2007, 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 less than 1% of our total net production in 2007. We have no plans for additional activity in Michigan in 2008 at this time.

Southeast New Mexico

        As of December 31, 2007, we owned an interest in 100,712 gross (20,942 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 2007, we participated in the drilling of 11 gross (4.7 net) wells, of which 100% were apparent successes. Production from wells in the southeast New Mexico area represented approximately 7% of our total net production in 2007. During 2008, we anticipate drilling 6 wells (2 net) in southeast New Mexico.

Arkansas

        As of December 31, 2007, we owned an interest in 5,661 gross (4,692 net) undeveloped acres in the Fayetteville Shale play in south central Arkansas. In 2007, we drilled seven wells (3.8 net), six (3.2 net) of which were apparent successes. Five wells in Arkansas had operations temporarily suspended at year-end 2007 because fracture stimulation during the completion of our initial wells caused communication with an underlying water bearing zone. Many of the planned 2007 wells have been deferred and some of the reserves that we originally expected to be classified as proved were moved to the non-proved category. Production from wells in the Arkansas area represented less than 1% of our total net production in 2007. Due to the ongoing strategic assessment process, we do not anticipate additional drilling in this area during 2008.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS —LIQUIDITY AND CAPITAL RESOURCES— CREDIT FACILITY" and Note 10 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 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.

Delivery Commitments

        During 2007, we executed a gas gathering and compression services agreement with Frontier Midstream, LLC ("Frontier"). Following execution of such agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure gathering lines, dehydration, compression and the interconnect with Ozark, in order to accommodate our desire to be able to deliver natural gas as soon as our wells were completed. At the time of signing the contract, we had completed and tested two productive wells in the Moorefield shale in Arkansas. The Rose Bud system was installed, operational and ready to deliver our production in June 2007. The contract minimum commitment to Frontier is 2.7 Bcf over a three year period for the pipeline interconnect. This line carries a $0.29 per Mcf deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. We have delivered approximately $41,400 of this commitment through December 31, 2007. In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The remaining commitment on these laterals is $1,305,000, for a total potential liability of approximately $2.0 million to be paid by June 2010 if the minimum volumes are not delivered. We currently have not recorded a liability for these commitments as we expect to meet the minimum physical delivery based on estimated production.

        This contract is not considered a derivative, but has been designated as an annual sales contract under Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended).

Derivatives

        Due to the instability of oil and natural gas prices, we may enter into, from time to time, price risk management transactions (e.g., swaps, collars and floors) on our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure to price

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fluctuations. While the use of these arrangements may limit our ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce our potential exposure to adverse price movements. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— APPROACH TO THE BUSINESS" for a discussion of our current level of derivative contracts as it relates to expected production. Our price-risk management arrangements, to the extent we enter into any, are intended to apply to only a portion of our expected production, and thereby provide only partial price protection against declines in oil and natural gas prices while limiting our potential gains from future increases in prices. None of these instruments are, at the time of their execution, intended to be used for trading purposes, but may be deemed as such due to the expected decrease in our anticipated 2008 production. All such derivative transactions provide for financial rather than physical settlement. These derivative transactions are generally placed with major financial institutions that the Company believes are minimal credit risks. 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 monitors our price-risk management policies and trades on a monthly basis. 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 our price-risk management transactions are considered derivative instruments and are accounted for in accordance with SFAS No. 133. 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 instruments, other than those that meet the normal purchases and sales exception, 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.

        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. Prior to 2006, 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.

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        The table below shows derivative gains and losses included within total revenue for the years presented.

        The table below summarizes our outstanding derivative contracts reflected on the balance sheet at December 31, 2007 and 2006.

(1)

Our natural gas collars were entered into on a per MMBtu delivered price basis, using the NYMEX Natural Gas Index. Mark-to-market accounting treatment is applied to these contracts and the change in fair value is reflected in total revenue.

(2)

Our crude oil collars 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.

(3)

During January 2007, the two natural gas collars entered into in August 2006 covering a portion of our 2007 estimated production were terminated at no cost to us and replaced with two new collars, each covering 15,000 MMBtu per day. The new prices per unit were $7.02-$9.00 and $7.00-$9.00.

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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

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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 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

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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 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

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facilities subject to DOT regulation, established new safety rules for certain gathering lines in rural areas, revised the current regulations applicable to safety and inspection of gathering lines in nonrural areas, and adopted new compliance deadlines. We acquired several lines in the January 2007 Acquisition that are subject to annual inspection and maintenance and we have DOT permits on 10 lines with the Texas Railroad Commission. 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, 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

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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.

        In response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth's atmosphere, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a "cap and trade" scheme of regulation of greenhouse gas emissions—a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. A vote on this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved.

        Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated producers of oil and natural gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and natural gas we produce.

        Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Court's holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal

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or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the oil and natural gas we produce.

        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.

        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.

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