E&P Primer JPM

North America Equity Research 18 November 2005

E&P 101: A Primer

Oil and Gas Exploration & Production

Exploration & Production

Shannon Nome (1-713) 216-1918 [email protected]

Phillips Johnston, CFA (1-212) 622-6491 [email protected]

Scott Arndt, CFA (1-713) 216-6218 [email protected]

Rodney C Clayton (1-212) 622-2873 [email protected]

J.P. Morgan Securities Inc.

See page 46 for analyst certification and important disclosures, including investment banking relationships. JPMorgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

Everything You Wanted to Know About E&P, But Were Afraid to Ask:

• Glossary of energy terms

• The oil & gas value chain

• Conversion factors

• Basic industry statistics and key facts

• E&P stocks as investments

• Interpretation of hypothetical E&P press releases

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Table of Contents The Basics: Term & Definitions...............................................3 Oil and Gas ..................................................................................................................3 Prices............................................................................................................................5 Reserve Terms .............................................................................................................7 Production Terms.......................................................................................................13 Oil & Gas Value Chain: Think of a River...............................14 Upstream Segment .....................................................................................................14 Midstream Segment ...................................................................................................15 Downstream Segment ................................................................................................15 Conversions and Statistics ...................................................15 Conversion Exercise ..................................................................................................16 Putting Statistics into Perspective........................................16 Crude Oil Market: A Global Market..........................................................................16 Natural Gas Market: Primarily a Regional Market, but LNG Is Changing This........18 E&P Stocks as Investments ..................................................23 Types of E&P Companies..........................................................................................24 What Matters to Investors..........................................................................................25 Asset Intensity: The “Holy Grail” of the E&P Business? .........................................29 Macro Data to Watch .................................................................................................31 Valuation....................................................................................................................32 Why Earnings Are Less of a Concern to E&P Investors ...........................................34 A Word on Hurricanes............................................................34 Liquefied Natural Gas: A Brief Primer ..................................35 Appendix: Hypothetical E&P Press Releases.....................38 Exploration Discoveries.............................................................................................38 Successful Appraisal Well .........................................................................................40 Unsuccessful Appraisal Well .....................................................................................41 Reserve Write-down ..................................................................................................41 Farm-in Agreement....................................................................................................42 Downspacing Approval .............................................................................................43 New Unconventional Play .........................................................................................43 Onshore Acquisition ..................................................................................................45

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The Basics: Term & Definitions Oil and Gas Hydrocarbons: a compound of carbon and hydrogen. Includes crude oil, natural gas, natural gas liquids (NGLs), coal, and others.

Oil = Petroleum = Crude Oil: unrefined liquid mixture of hydrocarbons that can be refined to yield oil products such as gasoline, naphthas, jet fuel, diesel fuel, heating oil, fuel oil, asphalt, etc. Oil is also used as feedstocks (inputs) for chemical manufacturers in the production of commodity chemicals, plastics, etc. If crude is high in sulfur content, it is a sour crude; otherwise it is a sweet crude. Crude oil may also be referred to as heavy or light according to its API gravity, which is the American Petroleum Institute's measurement of the specific gravity of crude oil (ranging from 9° to 55°), the lighter oils having the higher gravities (closer to 55°).

Table 1: The Oil Barrel Products Uses

Liquefied Petroleum Gas (LPGs) Ethane, Propane Heating, cooking 10% Butane Chemical feedstocks, Motor gasoline blending

Light Ends Naphthas Petrochemical feedstocks Gasolines Reforming into gasoline, Automotive fuel

35%

Middle Distillates Jet Kerosene Aviation fuel Diesel Automotive fuel Heating/Gasoil Domestic heating fuel Vacuum Gasoil Distilled to lighter product

35%

Heavy Distillates Cracked Fuel Oil Power generation, Ship fuel Straight-Run Fuel Oil Lighter products, Fuel oil Asphalt Road surfacing, Roofing Bitumens, Coke Manufacturing of steel

20% Sulfur Chemical industry

Source: Bloomberg. Note: Percentages are approximate and vary by crude and refinery type.

Natural Gas: a clean burning, odorless, colorless, highly compressible mixture of hydrocarbons occurring naturally in gaseous form. Primarily comprised of methane, but can also include ethane, propane, butane, and natural gasoline. If these latter components (called NGLs) are high in content, the gas is considered wet, and the NGLs may be separated from the methane in a processing plant to be sold separately. Producers will often vary the amount of NGL extraction depending on the current market pricing, as NGL pricing is benchmarked off of crude. Uses for natural gas (inputs) include space heating, water heating, cooking, etc (residential and

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commercial); steam generation, melting, and use as feedstocks for chemical manufacturing (industrial) and use as fuel for electricity generation (electric utility and independent power producers). See Figure 8, pg. 20 for a breakdown of U.S. supply and demand.

Table 2: The Natural Gas Mcf Products Uses

Dry gas Methane (aka pipeline-quality gas) Space heating, water heating, cooking Steam generation, melting Petrochemical feedstocks Power generation 95%

Wet gas (Natural Gas Liquids) Ethane, propane, butane, Space heating, water heating, cooking iso-butane, and natural gasoline Petrochemical feedstocks, Refining feedstocks, 5% Motor gasoline blending

Source: JPMorgan estimates. Note: Percentages vary by region and basin.

Natural Gas Liquids (NGLs): hydrocarbons that are originally in gaseous form underground, but turn into liquid form when either brought to the surface or processed in gas processing plants. NGLs include ethane, propane, butane, and natural gasoline. Many refer to crude oil and NGLs interchangeably (often as liquids), and most companies group NGL production and reserves together with oil production and reserves. NGLs should not to be confused with LNG (see below).

Liquefied Natural Gas (LNG): natural gas that has been cooled to very low temperatures (-259 degrees) and turned into liquid form for transportation (usually by ship or vehicle). The LNG is turned back into gas form before it reaches the end-user. The ramp of LNG imports is expected to have a significant effect on the North American natural gas industry (see "Liquefied Natural Gas: A Brief Primer," pg. 38).

Gas-To-Liquids: process of converting "stranded gas" (gas without a readily available market) to liquids products to facilitate transportation to markets. Examples: diesel, naphtha, waxes.

Liquefied Petroleum Gas (LPG): propane gas or butane gas that has been compressed into a liquid. LPG is used in rural areas for home heating and cooking and has industrial, agricultural, and commercial applications. Principal source is natural gas, from which the liquefied petroleum gases are separated by fractionation.

Liquids: general term that refers to crude oil and/or natural gas liquids (NGLs).

Deep Gas: natural gas located 15,000 feet or more below the earth's surface.

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Unconventional Resources = Resource Plays: hydrocarbons contained in low-permeability reservoirs that often require fracturing or other advanced completion techniques to extract.

Tight Gas: natural gas located in rock with low permeability (ability for fluids to flow through pore spaces of a reservoir). Enhanced recovery techniques like fracture stimulation must be performed to efficiently produce tight gas reserves. Tight gas includes both shale gas and basin-centered gas, and is often found the mid-continent, Rocky Mountain, and Appalachian regions.

Coal Bed Methane (CBM): natural gas located in coal deposits. CBM is formed during coalification, the natural process of turning organic matter into coal under high pressure and heat. It usually consists of methane—the purest, driest, and most environmentally friendly form of natural gas. CBM wells tend to produce at negligible rates at first as the coal seam dewaters, followed by a ramp in production once the water cut begins to decline.

Oil Sands: sandstones that contain oil (bitumen) that is too heavy to transport under normal temperatures. In order to be captured in commercial quantities, the oil is mined using heat or solvents. Once extracted, lighter oil must be injected into the bitumen in order for it to flow through pipelines. North American oil sands are concentrated in Canada, primarily in Alberta.

Prices Henry Hub Price: the benchmark natural gas price measured in $/MMbtu or $/Mcf (these two are essentially interchangeable). Natural gas futures contracts that trade on the NYMEX physically settle at Henry Hub, a vast intersection of natural gas pipelines located in Louisiana. Henry Hub prices can refer to spot or futures prices.

Bid-Week Price: the period of time, up to five days, at the end of the month when prices are set for gas deliveries the following month. Pricing corresponds to the futures contract, which is used to price next month's deliveries. Bid-week pricing can remove some of the volatility embedded in the futures market for producers. Most producers sell some gas at bid-week pricing, and thus, realized prices can often differ significantly from the average daily NYMEX price over a period of time.

Basis Differentials: a premium or discount to Henry-Hub pricing. Natural gas is physically traded at market "hubs" across the U.S. Hub prices are not consistent across the country as each hub has its own supply/demand and transportation constraints. The most famous "hub" is Henry Hub in Louisiana, where NYMEX futures contracts are settled for physical delivery. Other hubs, such as CIG, Opal, AECO, and Houston Ship Channel will trade at a premium or discount to Henry Hub. This premium or discount is known as the basis differential, and can represent transportation costs and local supply/demand dynamics. Thus, while producers can hedge away commodity price risk, they can still face basis risk, defined as the risk that

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basis differentials widen relative to Henry Hub (representing NYMEX contracts). Producers can enter into derivative contracts settled at NYMEX +/- the appropriate basis differential to hedge this risk. Figure 1 below illustrates how the expansion of the Kern River pipeline narrowed Rockies gas differentials. The expansion created greater access to market for the gas and effectively increased demand.

Figure 1: Kern River Pipeline Expansion and Rockies Differentials

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($2.50)

($2.00)

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$0.00

$0.50

Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04

$/MMbtu Opal/Henry Hub Differential

Kern River Pipeline Expansion

Source: JPMorgan estimates, Bloomberg

WTI Price: the benchmark crude oil price in the U.S. measured in $/barrel. WTI stands for West Texas Intermediate, which refers to a type of high quality, light in gravity crude oil. Curiously, WTI crude oil futures contracts that trade on the NYMEX physically settle at a storage facility in Cushing, Oklahoma, rather than in Texas. WTI prices have historically traded at a $1-2/barrel premium to Brent prices.

Brent Price: the benchmark crude oil price in Europe, as traded on the International Petroleum Exchange in London. Brent crude refers to a particular grade of crude found in the Brent field located in the North Sea. Brent crude is slightly heavier than WTI crude (lighter oil is generally more desirable than heavier oil because it is easier and less costly to refine).

Strip Price: the market's expectation of average prices over a certain amount of time in the future. The strip price is calculated by taking the average of all monthly futures prices for the specific time period. For instance, the 12-month strip price calculated in November 2005 is an average of 12 futures prices (beginning with the near-month contract that settles in December 2005 and ending with the contract that settles in November 2006).

Contango vs. Backwardated: refers to the shape of the commodity futures curve at a point in time. Just as the shape of the interest rate curve can offer insight to the economy and investors' expectations of the future, the shape of energy futures curves can offer insight to the state of the market and expectations for future changes in fundamentals. Contango refers to a price

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strip in which the prompt or near-month contract is higher than the spot price, or futures prices at the more distant end of the curve are higher than nearby futures prices. A price curve in contango would indicate that investors expect increasing prices, and would provide an incentive for inventory builds. Consumers can buy on the spot market while selling a futures contract. They commodity is then stored and delivered to satisfy the futures contract at a higher price. If the price discrepancy is larger than the storage costs, an arbitrage opportunity exists. In contrast, a price strip in which the cash price is higher than the prompt month or nearby futures contracts are higher than more distant contracts is backwardated. A backwardated price curve would indicate the investors expect declining commodity prices, and would encourage inventory withdrawals. Figure 2 below shows that the current gas curve is backwardated, while the current crude curve is in contango.

Figure 2: Natural Gas and Crude Oil 12-Month Futures Curve

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9.50

10.00

10.50

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13.00

Dec Jan FebMar Apr

May Jun Jul Aug Sep OctNov

$/MM

btu

57.00

57.50

58.00

58.50

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59.50

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61.00

$/Bbl

Oil curve is in contango

Natural gas curve is backw ardated

Source: Reuters.

Reserve Terms Reservoir: a single continuous deposit of oil and/or gas in the pores of a rock layer. Most reservoirs contain gas, oil, and water. A reservoir has a single pressure system and does not mix with other reservoirs. Major reservoir characteristics include thickness, porosity (a measure of the reservoir rock's storage capacity for fluids), permeability (a measure of the ease in which fluid flows through the reservoir), and saturation (the volume percentage of different fluids like water, oil and gas in the pore spaces of the reservoir).

Proved/Proven Reserves: quantities of oil or natural gas that are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves are highly certain, with a 90% chance that actual reserves will be larger and a 10% chance that they will ultimately prove to be smaller. It usually takes a discovery well to book proved reserves, and the SEC allows only reserves economic at year-end commodity prices to be

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booked as proved. The year end pricing convention can lead companies to impair reserves previously booked under higher prices. Note: proved reserves are the only type of reserves that a company can report in SEC filings.

Proved Developed Reserves: proved reserves that are expected to be produced from existing wells. These can be classified into two categories: proved developed producing (PDP), or proved developed non-producing (PDNP).

Proved Undeveloped Reserves (PUDs): proved reserves that are expected to be produced from new wells drilled or recompletions of old wells. PUDs are often booked as offset locations to a producing (PDP) well (see Figure 3). Note: conversion of PUDs or PDNPs to PDP will usually require a capital outlay.

Probable Reserves: quantities of oil or natural gas not proven by geological information, but likely present due to the proximity of proven reserves and can be produced if located. Probable reserves are less accurate than proven reserves. Note: companies cannot report probable reserves in SEC filings.

Possible Reserves: quantities of oil or natural gas that is inferred to be present by speculative geological information and can be produced if located. Possible reserves are less accurate than proven reserves and probable reserves. Note: companies cannot report possible reserves in SEC filings.

2P Reserves: the sum of proved and probable reserves.

3P Reserves: the sum of proved, probable and possible reserves.

Figure 3: Producing Well with Offset Locations

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PROB PROB PROB PROB PROB

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PDP

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PDP

EUR: “estimated ultimate recovery,” projected total reserves.

OOIP/OGIP: “original oil in place / original gas in place." Due to tight rock properties, not all of the oil or gas originally present may be recoverable. OOIP * recovery factor = EUR.

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Reserve Life: reserve to production ratio (R/P ratio). The theoretical amount of time in years it would take to fully produce or deplete oil and gas reserves at current production rates.

Reserve Impairment: non-cash charge to earnings representing the difference between the book value of a company's reserves on the balance sheet and the estimated discounted future net cash flows of those reserves, based on currently prevailing commodity prices.

Companies that utilize the full cost method of accounting must capitalize all costs related to their oil and gas properties (both productive and non-productive properties). These capitalized costs are amortized on an aggregate basis via DD&A expense over the estimated lives of the properties using the units-of-production method. At the end of each quarter, full cost companies must conduct a "full cost ceiling test" which limits the book value of these capitalized costs to the present value of future net revenues attributable to these reserves discounted at 10% (using prevailing oil and gas prices at that date), plus the lower of cost or market value of unproved properties. If the book value of the capitalized costs exceeds the ceiling test, the company must write-down its capitalized costs that are in excess of the present value calculation. Restoration of a quarterly write-down following an improvement in oil and gas prices is not allowed.

Under the successful methods method of accounting, a ceiling test is not formally required, primarily because FASB did not expect capitalized costs to normally exceed the underlying value of the reserves since successful efforts companies can only capitalize costs related to discovered reserves.

Reserve Audits: the term “audit” is commonly misused in oil and gas circles, as it carries the connotation of an independent verification of a company’s oil and gas reserves (as a financial statement audit would imply). There are several different levels of third-party involvement in company preparation of oil and gas reserve estimates, among which audits and procedural audits are included. Unlike financial audits, there is no requirement that a firm engage a third-party engineering review for any level of reserve audit.

The most rigorous level of external reserve evaluation is the independent reserve evaluation—or “determination”—which involves extensive client visits, collection of any and all required geologic, geophysical, engineering and economic data, and a complete external preparation of reserve estimates. In the case of a determination, the third party engineer’s estimates are used in the public company’s year-end financial disclosures.

An “audit” also involves company visits, data collection, and independent calculations of estimated reserve estimates, but unlike the case of a full determination, it is the producer’s own estimates that are disclosed in year-end financial statements. In addition, and audit often only examines a percentage of the reserves.

See pg. 34 for more on successful efforts vs. full cost accounting.

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A “procedural audit” is an overview of the internal processes only. The consultant sits in on the producer’s internal meetings, learns about the methodologies and processes used to ascertain and book proved reserves, and may review selected data. This type of audit does not involve generating an independent, third-party estimate of reserve quantities. As such, it is considered a notch below the straight “audit.”

Finally, “review letters" examine a field or specific asset area only. Limited in scope, these assignments are not considered an aggregate endorsement of a company’s proved reserves or overall methodologies.

PV-10 Calculation = SEC-PV10 = Standardized Measure of Discounted Future Net Cash Flows: discounted cash flow calculation that the SEC requires every publicly-traded company with significant oil and gas producing activities to disclose in annual financial statements. The calculation measures the present value of estimated future cash flows (revenues less development costs, production costs, and taxes) from the companies proved reserves, discounted at 10%. The PV-10 calculation is somewhat subjective in that companies provide their own assumptions regarding future development costs, future production costs, how fast the production base is declining, etc. Furthermore, companies must take whatever the prevailing commodity prices and costs were at the end of a reporting period and assume these levels are held constant throughout the life of the reserves. This leads to significant volatility in the PV-10 calculation from one year to another simply because of fluctuating commodity prices. The PV-10 value is often referred to as the “liquidation value.” Note: The PV-10 calculation excludes the effects of hedges.

Exploration Terms Exploration: all of the activities associated with finding new reserves of hydrocarbons (oil and gas). Includes acquiring acreage, shooting 2-D or 3-D seismic surveys, studying the geology and geophysics of a particular area, obtaining drilling rigs, and drilling exploration wells.

Prospect = Exploration Prospect: a potential drilling location.

Log: curve or set of curves that records physical, electrical, and radioactive properties of rocks and fluids in rocks in a wellbore in order to determine the presence of hydrocarbons in the wellbore.

Exploration Well = Wildcat Well: a well drilled to find a new reservoir, formation, or deposit of hydrocarbons. If successful, the well may be referred to as a discovery well.

Appraisal Well = Step-Out Well = Delineation Well: a well drilled after a discovery well to gain more information about the reservoir. Most are drilled to help determine the size or extent of the reservoir or field.

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Flowtest = Drillstream Test: an initial production test conducted under various pressures and chokes used to determine optimal production conditions and estimate initial ranges of production.

Sidetrack: to directionally drill around broken drill pipe, junk, or casing that has become permanently lodged at the bottom of an in-progress well.

Dry Hole: an unsuccessful exploration or development well. Well costs can range from tens of thousands of dollars all the way up to $100 million. Successful efforts companies expense dry hole costs while full cost companies capitalize dry hole costs.

Seismic: an exploration method used to map subsurface geological structures in order to locate potential hydrocarbon-bearing reservoirs (e.g., 2-D and 3-D seismic data).

Acreage: land held under lease for the purposes of exploration and production of oil and gas. Can also be used to refer to a concession, typically in international settings.

Authority for Expenditure (AFE): an estimate of all the related costs associated with drilling a well under two scenarios: a producer and a dryhole.

Concession: a legal agreement between a government and an oil company whereby the company is granted a permit for the right to explore, drill and produce oil and gas in a certain area for a fixed period of time. If proved reserves are discovered, the permit is usually held through the productive life of the area. Today, most concession agreements are structured so that the government receives a bonus and royalty payments. The government does not usually participate in operations or marketing.

Production Sharing Contract (PSC): an arrangement that is similar to a concession agreement, except the company is required to spend a specified amount of money each year for a specified time period. Furthermore, discovered reserves are owned by the government rather than the company with the company receiving a specified share of production, usually 15-20%.

Royalty: the fractional share of the gross (free of costs, except taxes) production revenues from a well or lease that is retained by the owner of the mineral rights. In the U.S., the landowner generally receives a royalty on

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onshore leases, and the Federal government receives a royalty on offshore leases and some onshore leases (most notably in the Rocky Mountains). In most foreign countries, royalties are paid only to the government. Note: mineral rights may be owned separately from the surface rights or together with the surface rights.

Royalty Interest (RI): an economic interest retained by the mineral interest owner when that owner leases the property to another party. The RI receives a specified fractional share of the gross (free of costs, except taxes) production revenues from a well or lease. A royalty takes preference over all other payments from lease revenue. A typical royalty interest would be 12.5% of gross production revenues, but can run significantly higher in “hot” exploration areas. The RI is a nonoperating or nonworking interest, meaning that it is passive.

Working Interest (WI): the economic interest remaining after deducting all nonworking interests, including the royalty interest. The working interest must pay all of the costs of exploring for, developing and producing oil and gas. The working interest may be divided among several parties (for example Party 1 may have a 75% working interest and Party 2 may have the other 25% working interest).

Farm In: the process of obtaining an interest in a lease by agreeing to assume some or all of the costs of exploring for, developing and producing oil and gas. Often times, major oil and gas companies will "farm out" acreage to smaller independents in order to keep from losing the lease for a lack of drilling. If the major is able to farm out all of the costs, but still retain an interest in the revenue from production, the major is said to be “carried.”

Net Revenue Interest (NRI): the share of production revenue after all royalties and other nonworking interests have been paid. For example, a company owning a 100% working interest on a lease will have a lower net revenue interest (87.5% would be typical, assuming a 12.5% royalty) after royalty payments are paid to the owner of the royalty interest.

Reversionary Interest: a share of production revenue that becomes effective after a third-party receives a predetermined amount of production. Reversionary interests are often used by capital constrained producers to finance the development of a large project. Typically, the producer will forego production volumes for a period of time to allow a third-party E&P or service company to receive the producer's share of production as reimbursement or compensation for development of the project. Once the third-party has received a pre-determined amount of production volumes, the producer begins to receive its share of production. A “back-in” is a related concept.

Volumetric Production Payment (VPP): represents the sale of a fixed-term of oil or gas production volumes to a buyer in exchange for a certain amount of up-front proceeds. The proceeds are determined by the net present

When one refers to costs “to the 8/8ths,” it means total gross costs to all the interest holders in a project.

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value of future revenues from those production volumes over the VPP term, and since the price risk is typically "removed" via hedging those volumes at NYMEX prices, it enables a producer to effectively capture future strip prices today. In instances when E&P stocks do not discount current strip prices, this apparent market inefficiency affords an interesting arbitrage opportunity.

Reserves sold in a VPP transaction must be removed from the seller’s books, although all reserves remaining after the term of the VPP revert back to the producer.

APO/BPO = “After Payout / Before Payout”: the conditions associated with an interest in a well or project. Often times a producer’s interest in a well will change upon payout of drilling costs. For example, a producer may cite a 25% BPO, falling to a 15% APO.

Production Terms Development: the process of producing oil and/or gas from an area that contains proved reserves. This area may or may not be already under production, but typically connotes drilling new wellbores.

Exploitation: basically another word for development but also connotes activity in a more mature area and may not involve drilling new wells. May involve enhanced oil recovery techniques including secondary recovery and tertiary recovery. These include stimulating production levels through techniques like water flooding, steam injection, or fracturing the sands or rock in the reservoir in order to produce the reserves faster and/or more efficiently. Exploitation can also include refracs (fracturing or stimulating a previously fractured zone), recompletions (completing a well in a new zone or formation), and workovers (cleaning out a wellbore in order to increase production).

Development Well: a well drilled in an area where proved reserves already exist in order to bring on new production.

Horizontal Well: a well that is initially drilled vertically, then by directional drilling, it curves at an angle and is drilled horizontally, or at another non-vertical angle. Horizontal wells have recently been shown to increase recovery in shale plays such as the Barnett Shale.

Infill Drilling = Downspacing: drilling wells between producing wells to increase production and possibly the ultimate recovery from the reservoir.

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Completion: the process of bringing a new well onto production. Includes adding steel casing (pipe) to the well (often using cement), perforating the casing, adding flow control equipment, etc.

Fracture Stimulation = Fracture Treating = Frac Job: a well-stimulation process in which fluids and proppants are pumped into the reservoir at high pressure to artificially fracture it and increase permeability and production.

Finding Cost = Finding & Development (F&D) Cost: capital spent in order to add new reserves or to initiate new production from an area containing proved reserves either through exploration or development activities. These expenditures are capitalized on the balance sheet as plant, property and equipment (PP&E) and eventually flow through the income statement in the DD&A expense line item.

All-in Finding Cost = Finding, Development and Acquisition (FD&A) Cost: same as above but includes capital spent on acquisitions of proved reserves from other parties.

Operating Costs = Lease Operating Costs (LOE) = Production Costs = Lifting Costs: the direct cash costs incurred to operate and maintain wells and related equipment and facilities. Included are labor costs; gathering and transportation costs, repairs and maintenance; materials, supplies and fuel consumed and services utilized in operating the wells and related equipment; property taxes and insurance premiums; and finally severance and ad valorem taxes (a.k.a. production taxes), which are state and local taxes on the volume or value of oil or gas produced and sold.

Oil & Gas Value Chain: Think of a River Upstream Segment Involves all operations associated with finding and extracting oil and gas from the subsurface.

Exploration & Production Sector The first step of exploration often involves leasing land from a private owner or government and studying it (geology, geophysics, 2-D and/or 3-D seismic). This will help boost chances of exploration success. Next step is to drill an attractive prospect(s). Most E&P companies contract out the actual drilling activities to oilfield services companies. If the well is successful and new reserves are encountered, next step is to produce the reserves (a.k.a. develop the reserves) out of the ground and sell them to a third party. The timing of both the development process and achieving first oil or gas production following a successful discovery varies significantly and can take days, up to several years, depending on the complexity of the required engineering and the availability of infrastructure. E&P company fortunes are tied directly to oil and natural gas prices. As producers of commodities,

F&D costs = costs incurred for exploration and development divided by the sum of drillbit extensions & additions and revisions, stated on a $/boe or $/mcfe basis.

Production/severance taxes vary directly with prevailing oil & gas prices. There are no production taxes in Gulf of Mexico federal waters.

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E&P companies are price takers, unless the company has locked in prices via hedging contracts or long-term supply contracts.

Oilfield Services Sector Includes rig construction, rig leasing, drilling, seismic, well logging, cementing, stimulation, etc. (e.g. Schlumberger). Oilfield services company fortunes are tied directly to capital spending in the E&P sector.

Midstream Segment Involves all operations associated with transporting oil and gas from the wellhead to refineries, processing plants, and/or end-users (e.g. Kinder-Morgan). Oil can be transported by pipelines, trucks, and oil tankers. Natural gas midstream operations include gas pipelines and storage facilities. Operators usually carry little commodity price risk, and instead typically charge a transportation fee or tariff. Midstream sector fortunes are tied to demand from end markets and supply from commodity source.

Downstream Segment Includes refining crude oil into crude oil products (gasoline, jet fuel, heating oil, diesel, fuel oil, asphalt, etc), marketing the crude oil products (retail gasoline stations and convenience stores), and/or chemicals divisions. An example of a pure-play downstream company is independent refiner Valero Energy. Downstream natural gas operations mostly involve local distribution companies (LDCs), a.k.a. natural gas utilities (e.g., KeySpan, Sempra). Fortunes of the downstream sector are tied to refining margins, chemicals businesses, and consumer demand.

Conversions and Statistics 1 barrel (bbl) of oil = 42 gallons 1 Mcf of natural gas = 1,000 cubic feet 1 MMcf = 1 million cubic feet 1 Bcf = 1 billion cubic feet 1 Tcf = 1 trillion cubic feet 1 Btu (British Thermal Unit) refers to heating value, rather than volume, but as a rule of thumb, 1 MMBtu (1 million Btus) = 1 Mcf (1,000 cubic feet) of natural gas. Btu content can be slightly higher if the gas is “wet,” or contains NGLs.

Oil and gas can be statistically converted into one another based on heating values, or Btus

Approximate Conversions

1 barrel (bbl) of oil = 6 Mcf of natural gas 1,000 bbls of oil = 6 MMcf of natural gas 1 MMbbls of oil = 6 Bcf of natural gas

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1 billion bbls of oil = 6 Tcf of natural gas

• Converting all of a company's reserves or production into crude oil gives you barrel oil-equivalent (boe) units

• Converting all of a company's reserves or production into natural gas gives you thousand cubic feet-equivalent (Mcfe) units

Conversion Exercise Company XYZ has 1,200 MMcf of natural gas reserves and 200,000 barrels of crude oil reserves. How many boe's does it have? How many Mcfe's does it have?

Oil-equivalent answer: 1,200 MMcf = 1,200,000 Mcf 1,200,000 Mcf / 6 = 200,000 boe 200,000 boe + 200,000 bbls = 400,000 boe (can also be written as 400 Mboe) Natural gas-equivalent answer: 200,000 bbls x 6 = 1,200,000 Mcfe 1,200,000 Mcfe + 1,200,000 Mcf = 2,400,000 Mcfe 2,400,000 Mcfe = 2,400 MMcfe (can also be written as 2.4 Bcfe)

Putting Statistics into Perspective Crude Oil Market: A Global Market

• World produces and consumes roughly 80 MMbbl/d (million barrels per day).

• OPEC produces about 33 MMbbl/d (million barrels per day), or 41% of world supply.

• United States produces about 7 MMbbl/d (million barrels per day), or only 9% of world supply.

• United States consumes over 20 MMbbl/d (million barrels per day), or 25% of world supply.

• All global oil transactions occur in US dollars. Crude oil is a not consumed directly, but is refined into other products such as gasoline, heating oil, lubricants, plastics, and jet fuel. There are many grades of crude oil with different qualities and pricing characteristics. Light sweet crude has a high API gravity and a low sulphur content, while heavy or sour crudes tend to be just the opposite. Light/sweet crudes typically trade at a premium to heavy/sour crude, as refiners can generally produce a higher yield of high quality refined products, such as gasoline, by running light/sweet crudes. The U.S. has far more refining capital for light/sweet crudes.

17



While crude oil is a global commodity and is produced all over the world, the vast majority of the world's oil reserves are located in the Middle East. Figure 4 below shows a breakdown of the world’s consumption and oil reserves as of 2004. The top consumers of oil largely consist of developed nations. As nations’ economies grow, so does their thirst for oil. The last couple of years have included a boom in oil consumption from India and China that largely tested the world's oil capacity, sending prices to largely unprecedented levels. Figure 4: World Reserves and Consumption

Source: 2005 BP Statistical Review of World Energy While crude prices are determined through global supply and demand interaction, OPEC's policies have a large influence on prices. OPEC does not set prices, but does set production quotas, thereby influencing the supply-side of the equation. Currently, 10 of OPEC's 11 cartel members are subject to group quotas, with Iraq being exempt. Saudi Arabia is by far the largest and most influential member of OPEC. Contrary to popular belief, it is not to OPEC's advantage to target as high an oil price as possible. The cartel wants to maximize revenues, but needs consumers as much as consumers need OPEC oil. At very high prices, OPEC runs the risk of hampering economic development (demand) or encouraging non-OPEC producers to increase oil producing investments (supply), both of which can have a negative impact on OPEC’s ultimate revenues. While E&Ps tend to have a higher exposure to gas prices, investors should be aware of the oil markets as gas prices tend to be closely related to oil prices are there is some degree of substitution between the two fuels.

YE2004 Proved Reserves

Kuwait11% Iraq

13%

Iran15%

Saudi Arabia30%

USA3%

UAE11%

Venezuela9%

Russia8%

2004 Consumption

Japan 7%

Total Middle East7%

China8%

USA25%

Other 43%

FSR5%

S. Korea3%

Canada3%

18



Figure 5: World Crude Production

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Thou

sand

Bar

rels

Daily

N. America S. Central America Europe & Eurasia Middle East Total Africa Asia Pacific

Source: 2005 BP Statistical Review of World Energy Table 3: A Perspective Of World Oil Reserves

Proved oil reserves

% of totalworld reserves

World oil reserves (YE2004) 1,189 billion bbls 100%World oil reserve life (YE2004) 40.5 years -

By Producer Group OPEC oil reserves (YE2004) 890 billion bbls 75%OPEC oil reserve life (YE2004) 74 years -

Former Soviet Union oil reserves (YE2004) 121 billion bbls 10%FSU oil reserve life (YE2004) 29 years -

OECD oil reserves (YE2004) 83 billion bbls 7%OECD oil reserve life (YE2004) 11 years -

Other world oil reserves (YE2004) 95 billion bbls 8%

By Country (examples) Saudi Arabia oil reserves (YE2004) 263 billion bbls 22%Saudi Arabia oil reserve life (YE2004) 68 years -Iran oil reserves (YE2004) 133 billion bbls 11%Iraq oil reserves (YE2004) 115 billion bbls 10%Kuwait oil reserves (YE2004) 99 billion bbls 8%UAE oil reserves (YE2004) 98 billion bbls 8%Venezuela oil reserves (YE2004) 77 billion bbls 7%Russian Federation oil reserves (YE2004) 72 billion bbls 6%US oil reserves (YE2004) 29 billion bbls 3%US oil reserve life (YE20042) 11 years -Source: 2005 BP Statistical Review of World Energy. Note: Figures have been rounded.

Natural Gas Market: Primarily a Regional Market, but LNG Is Changing This

• North America produces about 73 Bcf/d of natural gas, or about 26.5 Tcf per year

• United States produces about 54 Bcf/d of natural gas, or about 19 Tcf per year.

19



• Canada is a net exporter of natural gas to the U.S., as U.S. consumption is over 60 Bcf/d.

• Liquefied natural gas (LNG) has made major strides in recent years in bringing stranded natural gas to developed markets. We expect the gas market will move to a more global market as a result of advances in LNG. Please see “Liquefied Natural Gas: A Brief Primer,” page 35.

Demand for North American natural gas has increased at a compounded average annual growth rate of about 1% since 1995. Figure 6 below illustrates increasing demand coupled with higher prices. Figure 6: Total Gas Consumption vs. Annual Wellhead Price

1.552.17 2.32

1.96 2.19

3.68 4.00

2.95

4.885.49

7.15

20,000

20,500

21,000

21,500

22,000

22,50023,000

23,500

24,000

24,500

25,000

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005E

Bcf

$-

$1

$2

$3

$4

$5

$6

$7

$8

Wellhead price ($/M

cf)

Total Consumption Gas Price

R2 =0.56

Source: EIA, Bloomberg, JPMorgan estimates Natural gas has emerged as the fuel of choice for new power plants and is also used as a preferred fuel for home heating. Demand is very much dependent on the weather as LDCs tend to inject natural gas into storage in periods of low demand (generally April through October) in order to withdraw gas to meet home heating needs when demand peaks in the winter. Storage levels are watched closely by investors as an indication of both supply and demand; however, there is some evidence that the relationship between storage and natural gas prices breaks down in periods of unusually high crude prices as natural gas serves as substitute fuel in some cases. Figure 7 illustrates historical storage fluctuations over time.

20



Figure 7: Historical Seasonal Storage Levels

200

700

1200

1700

2200

2700

3200

3700

1/014/01

7/0110/0

11/02

4/027/02

10/02

1/034/03

7/0310/0

31/04

4/047/04

10/04

1/054/05

bcf

5 Yr Range 5-Yr Avg Actual

Source: EIA Demand for North American gas can be categorized as electrical generation, residential and commercial, industrial, and other. Industrial demand is considered the swing demand as it tends to fall in periods of high prices, only to return when prices moderate. Figure 8 below illustrates the changing demand mix as higher prices have eroded industrial demand.

Figure 8: Industrial Demand Destruction

Industrial Gas Consumption vs. Annual Wellhead Gas PriceShare of 2005E Total Demand

Residential & Commercial:

41%

Industrial:34%

Electric Generation:

21%

Othe

r: 3%

1.552.17 2.32

1.96 2.19

3.684.00

2.95

4.885.49

7.15

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005E

Bcf

$-

$1

$2

$3

$4

$5

$6

$7

$8

Wellhead price ($/Mcf)

Industrial Gas Demand Gas Price

R2 =0.68

Source: EIA, Bloomberg, JPMorgan estimates

North American natural gas supply has declined over the last few years, despite increased drilling. This is due in large part an industry shift from more prolific offshore Gulf of Mexico wells to unconventional onshore resources that tend to produce less gas per well, but have a much flatter decline rate. As the traditional Gulf of Mexico producing basins have

21



matured, the industry has been forced to look for unconventional resources in areas such as the mid-continent, the Rocky Mountains, and Appalachia. Figure 10 below illustrates the industry's struggle to grow or even maintain production. North American production has declined year over year since 2001 and is expected to dip significantly in 2005 as an unusually active hurricane season caused significant damage to the Gulf of Mexico producing basins. A continuation of rising demand and flat to falling production is expected to put the burden on LNG to fill the gap.

Figure 9: Total U.S Gas Supply

Net Imports13%

LNG3%

US Production84%

Source: EIA

Figure 10: Total U.S Gas Production

16,000

16,500

17,000

17,500

18,000

18,500

19,000

19,500

20,000

20,500

21,000

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005E

Bcf

Source: EIA

22



Table 4: A Perspective Of World Natural Gas Reserves Proved % of total gas reserves world reserves

World gas reserves (YE2004) 6,337 Tcfe 100%World gas reserve life (YE2004) 67 years -

By Country or Producer Group (examples) Former Soviet Union gas reserves (YE2004) 2,065 Tcfe 33%FSU gas reserve life (YE2004) 79 years -Russian Federation gas reserves (YE2004) 1,694 Tcfe 27%Iran gas reserves (YE2004) 971 Tcfe 15%Qatar gas reserves (YE2004) 910 Tcfe 14%Saudi Arabia gas reserves (YE2004) 238 Tcfe 4%UAE gas reserves (YE2004) 214 Tcfe 3%US gas reserves (YE2004) 187 Tcfe 3%US gas reserve life (YE2004) 10 years -Nigeria gas reserves (YE2004) 176 Tcfe 3%Algeria gas reserves (YE2004) 160 Tcfe 3%Canada gas reserves (YE2004) 57 Tcfe 1%Canada gas reserve life (YE2004) 9 years -Source: 2005 BP Statistical Review of World Energy. Note: Figures have been rounded.

Table 5: A Perspective Of Reserves By Company, Field and Well Proved reserves Proved reserves

Comment (oil-equivalent) (gas-equivalent)By Company (Examples) Exxon Mobil - YE2004 Largest Supermajor 21,711 MMboe 130,266 Bcfe EnCana Corp. – YE2004 Largest-cap E&P 2,245 MMboe 13,470 Bcfe Apache Corp. – YE2004 Large-cap E&P 1,937 MMboe 11,622 BcfeChesapeake Energy - YE2004 Large-cap E&P 817 MMboe 4,902 Bcfe Noble Energy – YE2004 Mid-cap E&P 524 MMboe 1,578 Bcfe Forest Oil – YE2004 Small-cap E&P 222 MMboe 1,332 Bcfe McMoRan Exploration – YE2004 Micro-cap E&P 8 MMboe 48 Bcfe

By Field or Well (Examples) Prudhoe Bay Largest oilfield in N. America 39 billion boe 234 Tcfe Thunder Horse Largest oilfield in GOM 1-3 billion boe 6-18 TcfeStandalone successful Deepwater GOM field (range) 75 MMboe - 3,000 MMboe 450 Bcfe - 18,000 BcfeStandalone successful Deepwater GOM field (average) 100-150 MMboe 600-900 BcfeSuccessful Deep Shelf GOM target (range) 3-33 MMboe 20-500 BcfeSuccessful Deep Shelf GOM target (average) 3 MMboe 20 BcfeSuccessful Conventional GOM Shelf well (range) 0.5-3.3 MMboe 3-20 BcfeUS onshore conventional well (range) 125 Mboe-17.0 MMboe 750 MMcfe-100 BcfeCoal Bed Methane well (range) 50 Mboe-0.2 MMboe 250 MMcfe-1 BcfeSource: Company reports, MMS, Netherland, Sewell & Associates, Alaska Department of Natural Resources, and JPMorgan estimates.

23



Table 6: A Perspective Of Production By Company, Field and Well Production Production

Comment (oil-equivalent) (gas-equivalent)By Company (Examples) Exxon Mobil - YE2004 Largest Supermajor 1,591 MMboe 9,546 Bcfe EnCana Corp. – YE2004 Large-cap E&P 279 MMboe 1,674 Bcfe Chesapeake Energy - YE2004 Large-cap E&P 60 MMboe 360 Bcfe Apache Corp. – YE2004 Large-cap E&P 164 MMboe 984 BcfeNoble Energy – YE2004 Mid-cap E&P 39 MMboe 234 Bcfe Forest Oil – YE2004 Small-cap E&P 29 MMboe 174 Bcfe McMoRan Exploration – YE2004 Micro-cap E&P 0.4 MMboe 2.4 Bcfe

By Field or Well (Examples) Initial Production Initial ProductionDeepwater GOM field (range) 25-250 Mboe/d 150-1,500 MMcfe/dDeepwater GOM field (average) 50 Mboe/d 300 MMcfe/dDeep Shelf GOM target (range) 3-58 Mboe/d 10-350 MMcfe/dDeep Shelf GOM target (average) 2-7 Mboe/d 10-40 MMcfe/dConventional GOM Shelf well (average) 1 Mboe/d 5 MMcfe/dUS onshore conventional well (range) 0.4 Mboe/d 2.5 MMcfe/dCoal Bed Methane well (range) 8-833 boe/d 50 Mcfe/d-5MMcfe/dSource: Company reports, MMS, Netherland, Sewell & Associates, and JPMorgan estimates.

E&P Stocks as Investments E&P stocks represent a "pure play" investment on oil and gas prices. Most investors prefer to invest in E&P stocks rather than oil and gas futures as many institutional investors are prohibited from futures trading, futures have margin requirements, and futures contract sizes are large.

Figure 11: Correlation Between Commodity Prices and E&P Stocks

-

2.00

4.00

6.00

8.00

10.00

12.00

Dec-94

Dec-95

Dec-96

Dec-97

Dec-98

Dec-99

Dec-00

Dec-01

Dec-02

Dec-03

Dec-04

0

50

100

150

200

250

300

350

400

Blend 12-Month Strip S&P 500 E&P Index

50% Gas, 50% Oil80% R-Squared

Source: Bloomberg; Factset

24



Exposure to oil versus natural gas varies widely among E&P companies. In general, the average E&P company is more exposed to gas than oil. As a result, most E&P investors focus more on natural gas prices and fundamentals than oil prices and OPEC, but the latter is obviously still quite important.

Types of E&P Companies • Pure Exploration Companies: Rely solely on the drillbit (i.e.,

drilling exploration wells) for growth in reserves and production. Requires highly skilled exploration technical staff. May command a premium because not beholden to M&A market for growth. Example: Bill Barrett Corp.

• Acquire and Develop Companies (a.k.a. Acquire and Exploit Companies): For the most part, these companies take the "E" out of E&P, as exploration activity is either not very significant or non-existent. Instead, the strategies of these companies involve acquiring mature properties and reserves from other companies and developing or exploiting the reserves. In the past 10-20 years, the majors in general have been slowly shedding lower return, mature assets in the U.S. in search of higher returns abroad. Many E&Ps have found a niche in acquiring such properties (both from majors, integrateds, and even larger E&Ps), and paying closer attention to the properties in order to add value. This may involve enhanced oil recovery techniques including secondary recovery and tertiary recovery. These include stimulating production levels through techniques like water flooding, steam injection, or fracturing the sands or rock in the reservoir in order to produce the reserves faster and/or more efficiently. The major drawback for these types of companies is the fact that they are beholden to M&A market as a source of growth. The M&A market is highly competitive and can be quite efficient, so it is often hard to truly add value. Example: Encore Acquisition Company, XTO Energy

• Combination of Both: Most E&P companies employ a combination of both strategies discussed above. This approach is a little more flexible. Companies often like to concentrate on exploration and development drilling when commodity prices are high and acquiring reserves when commodity prices (and therefore asset prices) are low. Example: Most E&P companies

• Unconventional Producers: Unconventional or resource plays have come into their own as an important source for future of U.S. energy supply, as production from conventional supply basins such as the Gulf of Mexico shelf has stalled and entered a relatively pronounced decline phase. Given USGS estimates that low-permeability, deep gas reservoirs in the U.S. may contain upwards of 135 Tcf of technically recoverable gas, these plays are logically viewed as the

25



"last growth frontier" in what is otherwise a relatively mature U.S. producing basin. When compared to conventional resources, unconventional resource plays tend to offer long-life, low-decline reserves, reliable production growth and lower costs over time. Example: EnCana Corp., EOG Resources, Quicksilver Resources, Ultra Petroleum, Southwestern Energy

Virtually every top-performing E&P stock over the past three years could be characterized as resource play producer. We think the underlying reasons that longer life assets have gained so much favor are North American basin maturity, rising commodity prices, and to a lesser extent, falling interest rates. Among these factors, we think the significant lift in long-dated energy futures prices has been the single most important. Much in the way falling interest rates push up the value of long-duration bonds, rising commodity prices and lower discount rates have driven up the value of long-lived unconventional assets.

What Matters to Investors • Cash Flow Growth: Although more emphasis is being placed these

days on returns and profitability metrics like ROCE, the typical E&P investor is more focused with the rate companies grow their cash flow (a.k.a. discretionary cash flow or cash flow from operations before changes in working capital). Over the long run, companies cannot grow cash flow without growing production, so there is a huge emphasis on production growth. On that note, companies can't sustain production growth without finding or acquiring new reserves, so reserve growth is also highly important.

• Production & Reserves Growth: Growing production and reserves is easier said than done, as natural decline rates can be difficult to offset. In order to grow organically, a company really needs to add new assets that are yielding initial production at a rate faster than its base is declining. This is easy enough to do in a given year, except that adding faster-decline production has the effect of "turning up the treadmill" over time. As the new, rapid-decline assets become a bigger part of the base, it becomes tougher and tougher to find new projects to offset the accelerated decline rate. We think this is why significantly above-average organic growth has, without exception, proven to be unsustainable in this industry.

• Cost Control: Keeping costs in check is challenging in an environment where costs are creeping up across the industry (see Figure 12). Finding, development and acquisition costs (FD&A costs) include capital spent in order to add new reserves either through exploration and development activities, or through acquisitions of new properties or companies. These expenditures are capitalized on the balance sheet as plant, property, and equipment

26



(PP&E) and eventually flow through the income statement in the DD&A expense line item. FD&A costs are especially important because they usually represent the greatest portion of a company's cost structure. Production costs (a.k.a. lifting costs, operating costs, lease operating expense, or LOE) are also important. We note that the characteristics of particular fields or basins (geology, infrastructure, oil field service costs, politics, etc) can vary significantly, which can meaningfully affect FD&A and operating costs. G&A and interest expenses are usually a smaller portion of the cost equation.

Figure 12: Cost Creep Average all in costs, $/Mcfe

$1.84$2.04

$1.82 $1.72 $1.81

$2.15$2.43

$2.20$2.41

$2.89

$2.53

$3.16

$3.69

$4.25

-

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005E

Source: Company reports and JPMorgan estimates. Note: We define all-in costs as FD&A, LOE (including production/severance taxes and transportation costs, net interest (including preferred dividends), and G&A expenses.

• Return and Profitability Metrics: More emphasis is being placed on return and profitability metrics like return on capital employed (ROCE) and profit margins. Although commodity prices have generally been strong in the past few years, bolstering the top line, the phenomenon of "cost creep" has hampered returns on capital employed (see Figure 13).

27



Figure 13: Generating Mid-Cycle ROCEs Requires Much Higher Prices Today

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

95 96 97 98 99 00 01 02 03 04 05E 06E1.50

2.50

3.50

4.50

5.50

6.50

7.50

8.50

9.50

ROCE Commodity Px Index ($/Mcfe)

10-yr average: 9% on av'g px of $3.80/Mcfe

Source: Company reports, JPMorgan estimates. Note: ROCE is defined as recurring earnings plus tax-effected interest (~NOPAT) divided by stockholders' equity plus debt. Commodity price index is a 50/50 oil/gas weighted index, stated in Mcf-equivalents converting at 6:1.

• Catalysts: Investors often look for catalysts that can move a stock.

Positive catalysts would include successful results of a key exploration well, first production from a key development project; successful results from a downspacing pilot which could lead to reserve additions, an accretive acquisition at an attractive price, a boost in production guidance, a well-executed divestiture, a share repurchase program, or any macro factors that positively affect oil and gas prices.

Negative catalysts would include a dry hole announcement at a key exploration well, delays at a key development project, disappointing reservoir performance or characteristics of a development field or project versus original expectations, a dilutive merger or acquisition, a reduction of production guidance, an asset impairment charge (a.k.a. reserve writedown), or the announcement of an equity offering.

• Hedging: Strategies among management teams vary, and investors have varying opinions as to whether or not companies should hedge. Some investors want full and complete exposure to commodity prices (remember the pure-play concept), while others prefer some degree of hedging, which can be used by management to protect its balance sheet, protect a capex program (thus helping ensure production growth), or lock-in the economics of a particular acquisition or a large development project coming online. As the last couple of years have brought a period of dramatic increases in

We estimate that it now requires $6.50-$7.00/Mcfe pricing for the average producer to cover a 9-10% WACC.

28



commodity prices, many producers are stuck with large writeoffs associated with underwater hedges. Thus, producers seem to be hedging less, but this could change if commodity prices fall into a prolonged slump. Producers with large hedge positions must also be cautious of potential supply disruptions that could leave them "overhedged" on their production and required them to effectively buy production in the open market to satisfy hedges. Note: JPMorgan publishes a Quarterly Hedging Survey which includes summary hedge positions for each producer under coverage. The following Figure 14 is taken from our Q3-05 Hedging Update.

Figure 14: Summary E&P Hedge Positions, 2006E

32.26

54.10

25.92

46.3044.94

39.40

32.75

57.32

49.36

38.8240.51

47.74

35.16

39.43

67.94

50.40

38.28

30.62

20.74

37.07

46.68

38.93

30.39

44.2641.63

33.7535.16

39.43

43.55

25.62

29.43

76.40

75.37

28.92

39.89

55.00

31.36

32.28

42.46

37.27

38.56

45.00

-

100

200

300

400

500

600

700

800

900

1,000

ECA DVN APA BR APC EOGKMG XTO CHK NBL PXD NFX PPP FST VPI PXP THX RRC SGY UPL SM COG WTI WGRKWK SFY EAC SKE MMR

Aver

age 2

006E

Pro

duct

ion

(Mbo

e/d)

$-

$10

$20

$30

$40

$50

$60

$70

$80

Weighted Average Hedged Price ($/boe)

Hedged Volumes Unhedged Volumes Avg. Floor and Ceiling Prices

Average hedge protection: 26% of 2006E Production

67%

25%

1%72%0%

1%4%6%

0%

7%51%65%1%26%

30%17%

17%

23%28%

0%0%40%0%36%37%0%12%7%27%

Source: Company reports and JPMorgan estimates. Note: Data Current as of August 2005.

• Balance Sheet: Financial flexibility is crucial in the E&P sector, especially considering most E&P companies rely on acquisitions for meaningful growth. When commodity prices fall from peak to trough levels, stocks with higher financial leverage tend to underperform the group. The average net debt to capital ratio in our coverage universe stood at 33% at the end of Q3/05. The average net debt to EBITDAX ratio in our coverage universe stood at 0.8 at the end of Q3/05. As a result of record cash flows over last couple of years, many producers are finding themselves with the attractive

29



“problem” of swelling cash balances. As acquisitions are currently both expensive and difficult to come by, many producers are using cash to repurchase shares. As the E&P business tends to be cyclical, producers generally prefer repurchase plans over the relative permanence of increased dividends.

Asset Intensity: The “Holy Grail” of the E&P Business? The business of oil and gas exploration and production is a challenging one. Producers face a daily and perpetual decline in their base assets, and must constantly redeploy cash flow in order to offset natural depletion. Growth becomes doubly challenging in a rising cost environment within a mature basin, as more cash flow is eaten up by efficiency losses and rising expenses. In the end, it would seem that those companies having more cash flow available after base declines are offset should be able to deliver higher and more sustainable growth over time.

Our work suggests that a producer's finding efficiency and asset characteristics can be combined into a single metric that captures a producer’s ability to “pedal uphill.” We originally introduced this concept back in May 2003, calling this metric “asset intensity,” and this has been the dominant consideration in our stock-picking efforts since that time. We define asset intensity as the proportion of discretionary cash flow required in order to maintain flat production in a given period. There are two main components to our "asset intensity" metric: maintenance capital spending, or that investment required to keep production flat on an annual basis; and projected discretionary cash flow (operating cash flow before working capital changes).

Figure 15: Definition of Asset Intensity Lower is Better

Asset Intensity =

Maintenance Capex*

Discretionary Cash Flow

* Note: Maintenance capex is defined as [ (Production Volumes * 3-yr Avg. FD&A) + non-E&P segment maintenance capex ] Source: JPMorgan.

Maintenance capex is a function of the decline profile of a producer’s asset base and that producer’s finding efficiency. Discretionary cash flow, on the other hand, is a function of revenues generated relative to cash costs. We think because these broad measures encompass so many "moving parts" that are critical to the E&P value proposition, they do a reasonable job of capturing differences in competitive advantage, and combined they yield a metric that appears to be a strong indicator of sustainable growth potential.

We originally approximated maintenance capex by multiplying projected production volumes by a company’s projected unit cost to find and develop.

30



The F&D cost assumption was guided mostly by each company's three-year average historical unit drillbit finding costs, normalized for unusual revisions or other items. As time went on, we refined this methodology to also accommodate differing intrinsic decline rates among the various companies, so our maintenance capex estimates are now hopefully more precise than what a more simplistic “production times F&D” approach might generate. As before, we add in estimated "maintenance capex" for non-E&P businesses (such as chemicals, midstream, or R&M) where appropriate.

Additionally, for companies who use property acquisitions as a recurring and essential component of their strategy (companies like XTO and CHK, for example), we incorporate more of an all-in (FD&A) cost component. Even if their sizeable prospect inventories in place don’t require acquisitions, those particular companies have stated they will, nonetheless, continue to purchase new properties in order to help stabilize what would otherwise be accelerating natural declines. We reason that either one has to use F&D (drillbit-only) costs, and assume accelerating natural declines, or else hold intrinsic decline rates stable but assume (typically higher) all-in FD&A costs.

Once we have a reasonable approximation for maintenance capex, we divide that amount by estimated discretionary cash flow for the period in question to generate an asset intensity percentage. In Figure 16 below, we have ranked the companies according to their 2006 estimated ratios, as of our November 2005 estimates.

Figure 16: Lower Asset Intensity Indicates Greater Growth Potential

88%70%

64%59%

55%50%50%

48%46%46%46%

43%43%

41%40%39%

38%36%36%36%36%36%

35%28%

26%26%

25%19%

8%

27%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

WTIVPI

SKEKMGSGYPPPDVNNFXECASFYTHXPXDFSTCHK

SMAPAAPCBBGEACCOG

BREOGNBLXTORRCKWKSWNPXP

WGRUPL

Less

Attr

activ

e

Mor

e Attr

activ

e

39%

Source: Company reports and JPMorgan estimates.

31



Macro Data to Watch

• Weekly Natural Gas Storage Levels (see Figure 17): Weekly storage reports are published every Thursday at 10:30 Eastern by the Energy Information Administration (EIA), a division of the US Department of Energy (DOE). Because a large proportion of natural gas demand is weather-driven (used for heating), production in the spring, summer and fall exceeds demand, so there are net gas injections into storage facilities. Storage levels typically peak on or around October 31. From early November to late March, demand significantly exceeds production, so there are net gas withdrawals from storage. Storage levels typically trough on or around March 31. Investors watch storage levels closely because natural gas prices are highly correlated with the tightness of storage levels. Prices tend to drop as storage levels move above average, and prices tend to rise when storage levels fall below average.

• Weekly Crude Oil Reports: Weekly crude oil reports are published every Wednesday at 10:30 am ET by the EIA. The report details U.S. oil and oil product statistics including inventories, imports, demand, refining utilization, etc. E&P investors watch this report for much the same reason that they watch the weekly natural gas storage report. Crude oil prices are in part driven by the tightness of inventory levels. Prices tend to drop as inventories move above average, and prices tend to rise when inventories fall below average.

• Weekly Rig Counts: Baker Hughes publishes weekly rig counts every Friday. When rig counts rise, drilling activity is picking up. This is bearish for E&P stocks for two reasons. First, it signals that new supply (production) may increase. Second, it indicates that demand for rigs is increasing, which may boost E&P drilling costs.

• Quarterly Gas Production Figures From North American Producers: The JPMorgan North American Natural Gas Supply Monitor is a bottom-up survey that attempts to estimate changes and trends in North American natural gas production by the industry, based on quarterly results from producers. Decline in supply is bullish for gas prices, and growth in supply is bearish for gas prices.

• Government Natural Gas Supply and Demand Data: Each month, the EIA releases gas supply and demand data, but these are of questionable value because the data lags significantly and is typically subject to later revisions.

• OPEC-Related News: OPEC represents roughly one third of worldwide oil supply, and thus has a major influence on prices.

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Figure 17: Henry Hub Spot Natural Gas Prices and Working Gas Storage Levels

0

2

4

6

8

10

12

14

Jan-93

Jan-94

Jan-95

Jan-96

Jan-97

Jan-98

Jan-99

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

$/M

MB

TU

200

700

1,200

1,700

2,200

2,700

3,200

3,700

J F M A M J J A S O N D

bcf

5 Yr Range 2004 2005 5-Yr Avg

Source: Natural Gas Week, EIA, Bloomberg.

Valuation Six Most Widely Used E&P Valuation Metrics:

• Price/Cash Flow (P/CF): Stock price divided by discretionary cash flow (cash flow from operations before changes in working capital). In times of low commodity prices, multiples expand and in times of strong commodity prices, multiples contract. This metric, while easily calculated, can be misleading in cases of above-average or below-average financial leverage.

• Enterprise Value/EBITDAX: A better metric than P/CF, in our opinion, because it adjusts for financial leverage (i.e., a highly-leveraged company may look cheap on a P/CF basis but more average or even rich on a EV/EBITDAX basis). The "X" in EBITDAX stands for the exploration expense for successful efforts companies (see discussion on page 34 entitled Why Earnings Are Less of a Concern to E&P Investors). In times of low commodity prices, multiples expand, and in times of strong commodity prices, multiples contract. The E&P sector has traded at 5.0 times forward EBITDAX on average during the past five years, with a high of 7.2 and a low of 3.2.

• EV/FCF: This multiple captures important differences in maintenance capex/finding efficiency among the companies, and thus should be a better indicator of sustainable growth potential. Free cash flow, as we define it, is unlevered cash flow (i.e. discretionary CF less cash taxes and interest expense) minus maintenance capex (expenditures required to keep production flat). The underlying concept with EV/FCF is to assess what an investor is paying for the sustainability of a given asset base’s growth profile, which we have

33



shown to be a direct function of its free cash flow. EV/FCF is closely related to our asset intensity concept described above.

• Enterprise Value/normalized EBITDAX: Same calculation as EV/EBITDAX, but the EBITDAX is based on a theoretical normalized value that is estimated assuming mid-cycle commodity prices defined as the level of oil and gas pricing would have enabled the sector on average to earn its cost of capital in a given year. Unlike the plain vanilla EV/EBITDAX multiple, this multiple contracts in times of low commodity prices and expands and in times of strong commodity prices. The E&P sector has traded at 5.0 times forward normalized EBITDAX on average during the past five years, with a high of 7.9 and a low of 3.6.

• Enterprise Value/normalized Asset Value: A discounted cash flow analysis that assumes mid-cycle commodity prices defined as the level of oil and gas pricing that would enable the sector on average to earn its cost of capital in a given year. The DCF analysis mimics the SEC present value calculation (PV-10) that is required to be disclosed in the reserve section of companies' 10-Ks. The SEC calculation requires the assumption of whatever the prevailing commodity prices were at the end of a reporting period. This leads to significant volatility in the PV-10 calculation from one year to another, simply because of fluctuating commodity prices. Unlike the SEC approach, our calculation assumes that the normalized or mid-cycle price prevailed in every given year. Stocks can trade at discounts or premiums to their normalized asset values, depending on the commodity price cycle. The E&P sector has traded at 93% of normalized asset value on average during the past five years, with a high of 135% and a low of 65%.

• Enterprise Value/Reserves: A simplistic valuation tool that requires no estimates or assumptions. In general, this metric should not be used as a primary valuation multiple, as not all reserves were created equal, but it can serve as a useful point of reference. This metric is often used to evaluate the valuation of property acquisitions, when little is known about the specific cash flow generating potential of the acquired reserves. Companies also sometimes prefer to repurchase stock if the shares are trading below the EV/ Reserve multiples of potential corporate or property acquisitions. In general, the longer the reserve life of a company or property, the lower the EV/Reserve multiple, all other things being equal. This is because reserves with a longer reserve life (reserves/production ratio, or R/P ratio) take longer to produce and are therefore worth less on a time-value-of-money basis. The proportion of proved undeveloped reserves (PUDs) in the reserve base also affects this multiple. In general, the greater the proportion of proven undeveloped reserves, the lower the EV/Reserve multiple, all other things being equal.

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Reserves that are less prolific will also trade at a discount, all other things being equal.

Why Earnings Are Less of a Concern to E&P Investors • Successful Efforts Versus Full Cost Accounting: Companies are

given a choice between two methods to account for dry holes (unsuccessful exploration wells). Companies that employ the successful efforts method of accounting must expense the cost of the well immediately through the income statement. By contrast, companies that use the full cost method of accounting must capitalize the cost of the dry hole onto the balance sheet, and eventually amortize it through DD&A expense. Therefore, earnings from successful efforts companies can be very erratic, compared to those of full cost companies. The two accounting methods produce apples and oranges when looking at relative P/E ratios within the sector.

• Negative Earnings Are Common in Years of Low Commodity Prices: The fortunes of E&P companies are largely tied to oil and gas prices, which are cyclical. In times of weak prices, many E&P companies have negative earnings, making P/E ratios not meaningful. The integrated oil companies and majors have other businesses that usually do well when oil and gas prices are weak (like refining, marketing, and chemicals businesses).

A Word on Hurricanes As the bulk of North America’s oil and gas infrastructure is still concentrated in or near the Gulf of Mexico, the energy industry is highly susceptible to storm-related disruptions. NOAA data suggests a steady pickup in Atlantic/GOM tropical storm activity over time, and most notably over the past ten years. Over the long haul (i.e., since 1944), the “average” tropical storm season involves 10 named storms, including 6 hurricanes, 3 of which prove to be “major” (i.e., Category 3, 4 or 5) hurricanes, though, the past ten years have been quite a bit more active than this. In fact, the high level of activity since the mid-1990s and various climatic indicators have led some forecasters to call for a 20-25 year cycle of increased tropical activity.

Hurricanes can have a two-fold effect on exploration and production companies. Depending on the size and severity of a hurricane, producers will be forced to shut-in their Gulf of Mexico production well ahead of the arrival of a storm, and often leave platforms abandoned for several days after the storm passes. This results in a deferral of production to subsequent periods. While producers are forced to forego or delay production, they often receive an offset to lost revenue in the form of higher commodity prices. The cumulative shut-ins across the industry can add up to a significant loss of

35



supply, forcing prices higher. E&P producers are then able to capture higher prices for production elsewhere.

While hurricane season really covers the second half of the year, some of the more servere storms of late have caused production shut-ins that have persisted for more than a year. In some cases, the shut-ins were due to damaged production infrastructure, while in other cases, shut-ins persisted due to damages to third-party pipeline systems. Some producers carry insurance to cover both damaged infrastructure and lost production, but terms and the extent of coverage vary widely. Figure 18 below summarizes the effects of three recent major hurricanes that traveled through the producing region of the Gulf of Mexico.

Figure 18: Gulf of Mexico Shut-ins from Recent Hurricanes

14%14% 12% 6%

40%45%

50%55%52%57%

66%75%

33%

66%

80%

34%40%

52%

73%

88%83%

6%10%17%14%

19%20%24%

30%36%42%53%

11%0%

10%20%30%40%50%60%70%80%90%

100%

Landfa

llDay

8Day

15Day

22Day

29Day

38Day

45Day

50Day

57Day

64Day

71

IVAN '04

KATRINA / RITA '05

Source: Minerals Management Service

Liquefied Natural Gas: A Brief Primer The declining outlook for domestic natural gas production has thrown LNG into the industry spotlight. According to the EIA, U.S. natural gas consumption is forecast to increase from 22.3 Tcf in 2004 to 25.4 Tcf in 2010 and to 30.6 Tcf by 2025. Domestic production of natural gas will likely not be sufficient to keep pace with consumption, with the production shortfall versus consumption rising from 3.3 Tcf in 2004 to an estimated 4.9 Tcf in 2010 and to 8.7 Tcf in 2025, according to EIA. Canadian natural gas imports are expected to steadily decline from 3.0 Tcf in 2005 as Canadian demand increases and gas fields mature. These developments raise the question of where the United States will find adequate supply to satisfy its growing demand.

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Natural gas has remained a relatively regional business because of the inherent difficulty in transporting it over long distances, but LNG is quickly changing the dynamics of natural gas into a global enterprise. The process of liquefying gas involves cooling it to 259 degrees below zero, at which point it becomes a liquid and its volume is reduced 600 times. It can then be stored and transported by tanker across long distances. Before the gas is consumed, however, it must be regasified. Existing LNG proposals differ, but this can be done on the tanker or, more commonly, at a regasification facility.

Many foreign nations have natural gas supplies that more than satisfy their levels of domestic demand and therefore can be readily commercialized and exported to the United States and other nations with demand in excess of supply. The top exporters of LNG to the United States include Trinidad and Tobago, Algeria, Australia, and Nigeria.

While awareness of LNG has been heightened in recent years, there are currently only four LNG importation facilities operating in the continental U.S., and a new facility has not opened in roughly two decades. The two primary deterrents to more development of domestic LNG importation capacity have been safety/regulatory concerns and economics. The latter issue appears to no longer be a factor with natural gas prices at historically high levels and a supply/demand picture, as illustrated above, which suggests that prices could stay somewhat elevated over the long term.

Most industry experts believe long-term gas prices of at least $3.50/Mcf are needed to keep a LNG project commercially viable. JPMorgan projections call for gas prices to stay well above that level through 2007.

Safety and regulatory concerns continue to be an issue for expanding domestic LNG capacity. The actual liquefied gas is believed by most to be non-toxic, non-flammable, and non-explosive. In fact, LNG technology has been around for over 40 years, with a strong safety record. There was a notable explosion, however, at an Algerian LNG liquefaction facility, and an indisputable cause of the incident has not been determined. As a result of this and other reported LNG accidents, it is common for the local public to demonstrate strong resistance upon the identification of an onshore site near a populated area for a potential LNG facility. Regulatory bodies continue to study the environmental impact of LNG but to date have made no substantial disclosures that raise serious concern. An energy-friendly Bush administration could lead to regulatory entities being pressed to approve LNG proposals more quickly going forward.

Today, there are proposals for nearly 40 new LNG regasification facilities in North America over the next several years, with the next U.S. terminal projected to open in the Gulf Coast in 2007.

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Table 8: Projections of U.S. Natural Gas Consumption and Production Growth figures in Tcf

2004 2010E 2025E Consumption 22.3 25.4 30.6 Production 19.0 20.5 21.9 Differential 3.3 4.9 8.7 Source: EIA.

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Appendix: Hypothetical E&P Press Releases All of the following scenarios are for fictitious companies.

Exploration Discoveries Example 1: Deepwater Gulf of Mexico Discovery Press Release: Orange Resources reported today that an exploratory well testing the Humphrey Bogart Prospect on Garden Banks Block 782 in the Gulf of Mexico encountered over 360 net feet of pay in four intervals. The Garden Banks Block 782 #1 exploratory well, located in 4,642 feet of water, was drilled to a true vertical depth of 15,717 feet. Each pay zone was encountered at the predicted depth and generally met or exceeded the anticipated thickness. The rig Ocean Victory will stay on location to conduct subsequent appraisal drilling at Humphrey Bogart that will target several additional shallow and deep objectives that could not be penetrated from the initial wellbore location. Orange owns a 20 percent working interest in the Humphrey Bogart Prospect on Garden Banks Block 782 as well as in adjacent blocks 826 and 827 and nearby block 785. Purple Exploration holds an 80 percent working interest in these same blocks and serves as operator.

Interpretation Unless unrisked (total potential) pre-drill reserve estimates were disclosed prior to drilling this well, it is difficult to estimate the size and value of this discovery. However, one can deduce a few takeaways:

First, Orange believes there is a chance the deepwater discovery is commercial, otherwise, it would not conduct appraisal drilling, and the well would likely be plugged and abandoned.

Second, it is unlikely that there is any nearby infrastructure with spare capacity that could be utilized to more efficiently and more cheaply develop the discovery, otherwise, the press release would have likely mentioned this. This means that in their ultimate evaluation of the potential economics of the discovery, Purple and Orange will likely need to assume that a new production facility will need to be built in order to develop the reserves.

Finally, because the well was drilled in very deep water (in the Gulf of Mexico, any depth greater than roughly 655 feet of water is considered deepwater) in an area with no nearby available infrastructure capacity, one can safely deduce that the target size of the reservoir was likely above 100 million boe. As a rule of thumb, undeveloped deepwater Gulf of Mexico discoveries have around $5/boe worth of net present value. Therefore, if this discovery is ultimately declared commercial, we would peg its NPV to be between around $500 million on a gross basis, or $100 million net to Orange.

QUESTIONS TO ASK MANAGEMENT:

• What were the predrill reserves estimates?

• Is there any nearby infrastructure with spare capacity?

• How many appraisal wells will be necessary to justify sanction?

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Investors should be aware that for cost reasons, flowtests are not commonly conducted on apparent discoveries in the deepwater. Instead, extensive logging and other reservoir tests are run to bracket in a range of recoverable reserve estimates, in order to justify project sanction. For this reason, new deepwater fields can occasionally encounter production problems in their first six months onstream, as a reservoir quality and/or the extent of compartmentalization comes to light.

Example 2: Deepwater Gulf of Mexico Discovery Press Release: Violet Energy today announced a natural gas discovery at its James Cagney prospect in the Eastern Gulf of Mexico. The discovery well is located in Atwater Valley 349, and was spudded in 8,800 feet of water, about 200 miles southeast of New Orleans. It encountered a total of 83 feet of net pay and was drilled to the target depth of 18,310 feet using the Deepwater Millennium drillship. Estimated field size is 40 million to 50 million barrels of oil equivalent. Violet holds a 100 percent interest in the James Cagney discovery and adjacent blocks. The company believes James Cagney could be commercially produced when hub facilities are established in the area. Toward that goal, Violet will soon begin drilling its high-potential Spencer Tracy prospect located at Lloyd Ridge Block 360 in 9,100 feet of water.

Interpretation: This is technically a discovery, but we would not necessarily call it a successful discovery, given its size (40-50 MMboe), water depth, and the lack of available infrastructure capacity. As a rule of thumb, companies drilling in deepwater in an area with no nearby available infrastructure capacity are targeting at least 100 million boe of gross reserves to justify a standalone commercial development project. These results therefore likely came in below the company's expectations. Furthermore, the company admits that the find is not commercial, unless other discoveries are found in the area that will augment economics. Until that occurs, the market will likely ascribe little-to-no value to James Cagney.

Example 3: Deep-Shelf Gulf of Mexico Discovery Press Release: Pink Exploration today announced its first shallow-water, deep-shelf gas discovery at its Jimmy Stewart prospect at High Island 115 in 44 feet of water. The #1 well was drilled to 19,800 feet and tested 20 million cubic feet of gas per day. The company anticipates first production in seven to eight months, pending construction of facilities. Pink Exploration has a 50 percent working interest in the project. The well is operated by Beige Oil and Gas as a part of the previously announced joint-venture agreement between both companies.


• What would be the minimum threshold size for a collection of fields here to justify a hub development?

• How many similar prospects does the company have in inventory here?

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Interpretation: Unless unrisked (total potential) pre-drill reserve estimates were disclosed prior to drilling this well, it is difficult to estimate the size and value of this discovery. However, one can use the production test rate data to back into an approximate gross reserve size. One could assume that, as a rule of thumb, a deep-shelf well will likely produce roughly half of its reserves in the first year, given the steep hyperbolic decline rates of shelf wells, and the other half over the next three or four years. Therefore, a well that initially produces 20 MMcf/d will likely produce around 7 Bcf of gas in year 1, implying total gross reserves of about 14 Bcf. Assuming these undeveloped gas reserves have a NPV of $1.00-1.25/Mcfe (worth more than deepwater undeveloped reserves because they can be brought onto production at much faster rates, sometimes through existing infrastructure), we would peg the NPV of the discovery between $14-17.5 million on a gross basis, or $7-8.8 million net to Pink.

Successful Appraisal Well Example 1: Successful Deepwater Appraisal Well Press Release: Grey Land & Exploration and its partners today announced another successful deepwater subsalt appraisal well on their Clark Gable discovery, located in the Gulf of Mexico on Green Canyon Block 562, about 180 miles south of New Orleans. "We're pleased to discover the potential field size of Clark Gable could be larger than Grey's previous estimates," said Grey's Chairman, President and CEO John Q Smith. "The Clark Gable No. 3 appraisal well was intended to confirm the northwestern edge of the field, but the field extends even deeper and farther beyond what we had predicted. In fact, the outermost limits of Clark Gable are still unknown." The Clark Gable No. 3 well was spudded by Black Gold Petroleum Co. in February 2005 in about 3,900 feet of water. The well reached a total depth of more than 27,000 feet and encountered a total of 208 feet of oil pay in two sands with no oil-water contact. The findings confirm the prior estimated gross reserves of about 100 million barrels of oil equivalent, and the lack of an oil-water contact suggests additional reserve potential. The well extended the limit of the proven oil column down dip an additional 800 feet on the Clark Gable structure. Grey holds a 52.5 percent working interest in the project; other partners include Black Gold (operator - 18.2 percent), Aqua Energy (16.8 percent) and Indigo Hydrocarbons (12.5 percent). The Clark Gable partner companies expect to make a decision on development plans as early as this summer. They are considering options including a separate structure or a tie-back to the nearby Gregory Peck facility, which will be installed late this year and operated by Grey. First production from Clark Gable could be late 2006 or early 2007.


• What are expected reserves?

• Do you have any “look-a-like” prospects nearby?

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Interpretation: From previous press releases, we know that Clark Gable was originally discovered in 2001, and an appraisal well was drilled in September 2004. The latest No. 3 well thus represents the second successful appraisal well drilled in the area. While the success of this well is obviously good news, the impact on Grey's stock price will be limited by the fact that the partners had already provided a 100 million boe estimate for the size of Clarke Gable. Most of the NPV of Clarke Gable was likely already discounted into the stock prior to the drilling of the No. 3 well. However, there may be a modest to moderate amount of upside in the stock, given the CEO's comments that Clarke Gable may be larger than previously estimated due to the lack of an oil-water contact.

Unsuccessful Appraisal Well Example 1: Unsuccessful Deepwater Appraisal Well Press Release: Ewing Bank Block 994 (Marlon Brando Discovery)—The initial exploratory well drilled at this location encountered 185 feet of pay. A delineation well failed to encounter hydrocarbons of sufficient commercial quantities to justify further development of this discovery. Brown Exploration & Production has a 40% working interest. The company’s proved reserves as of December 31, 2001, included 7.2 million barrels of oil and 13 billion cubic feet of natural gas attributable to Marlon Brando.

Interpretation: While this field was relatively small to begin with given the amount of reserves the company has booked, this is not good news and it will likely negatively impact Brown's stock, considering Brown is a small-cap E&P company. Brown had already booked reserves at Marlon Brando, so this will result in negative reserve revisions in the company's year-end financial statements. Furthermore, Brown's stock price likely accorded some value to the Marlon Brando reserves. Assuming the market valued these undeveloped reserves at $5/boe, around $47 million of NPV could be wiped out of the company's market capitalization. The downside could be even lower considering the negative effects on production growth estimates and financial leverage.

Reserve Write-down Example 1: Reserve Write-down Press Release: During the third quarter, Blue Offshore conducted an internal reserve review by a third party outside engineering firm to review several of its largest Gulf of Mexico fields. Based on this review, Blue estimates that its proved reserves as September 30, 2005 were approximately 670 billion cubic feet equivalent (Bcfe). A full reserve report by a third party engineering firm will be performed at year end.

The following is a reconciliation of Blue’s December 31, 2004 estimated proved reserves with its current estimated proved reserves:


• When will the next appraisal well be drilled?

• If the project is deemed sizable enough to justify a standalone platform, what will that mean to the initial onset date?


• How much capital was tied up in this project?

• Does this condemn any other exploratory prospects or developments nearby?

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Proved reserves as of December 31, 2004 1,100 Bcfe Revisions of previous estimates (210) Extensions, discoveries and other additions 50 Purchase of producing properties 10 Production (50) Estimate of proved reserves as of June 30, 2005 900 Bcfe

The revisions are not expected to have a material impact on Blue's near term production volumes. Approximately 50 Bcfe and 40 Bcfe of the downward revisions were attributable to Blue's Garden Banks 123 and High Island 123 fields, respectively. Blue expects the revisions to result in an increase in the depletion rate for future periods. The timing and amount of such increase has not yet been determined. No determination has been made as to the impact, if any, on prior periods.

Interpretation: This is a negative event for Blue and will likely lead to slide in the company’s stock price. The company is writing off 210 Bcfe from YE2004, a 19% reduction to proved reserves. The remaining line items in the reconciliation are normal recurring items that reconcile the 2004 total to the current total. A write-down of this magnitude could lead to a restatement of prior-periods.

Of the 210 Bcfe, less than half is attributable to two individual fields, indicating that the reason for the reserve revision is unlikely to be isolated or simply due to well performance in a couple of fields. The revision is more likely to be a widespread problem with company reporting and/or controls, perhaps indicating overly-aggressive reserve recognition procedures.

To gain a rough estimate of the loss of value, one could calculate the market value per Mcfe by dividing the company's enterprise value by the previous reserve estimate of 1,100 Bcfe. This multiple could then be applied to the 210 Bcfe being written off to arrive at an estimate of the value that the market was affording to the lost reserves.

Blue’s DD&A rate will go up in future periods because the costs of these reserves will remain in the cost pool (the numerator of the DD&A calculation), while the reserves will never be produced (the denominator of the DD&A calculation).

Farm-in Agreement Example 1: Press Release Announcing Farm-in Agreement to Develop Acreage: Black-Gold Resources announced today that it has executed an agreement with Major Oil Company to develop acreage in the Piceance Basin in northwest Colorado.

Under the terms of the deal, Black-Gold will farm-in approximately 100,000 gross acres of Major’s Prolific Gas Field in the Piceance Basin. Black-Gold


• How widespread were the reserve revisions at the other fields?

• What originally prompted a third-party reserve review during the middle of the fiscal year?

43



will operate and earn 50% working interest ownership in the entire leasehold position by drilling six wells beginning before year-end.

Interpretation: This is likely a positive development for both companies. Black-Gold is able to gain access to highly competitive acreage at an attractive price, while Major Oil Company is able to hold its leasing rights by commencing drilling on the land. The Piceance basin is a low-risk resource play characterized by thick gas accumulations in the Willams Fork formation. Press releases from other operators have indicated well economics of 1.1-1.3 Bcfe/well for about $1.2-$1.9MM/well. Assuming the midpoint of $1.6MM/well, we estimate Black-Gold's cost is attractive at less than $95/acre. Future expansion of the agreement is likely possible if Major Oil Company has a substantial acreage position in the Piceance.

Downspacing Approval Example 1: Press Release Announcing Approval to Downspace Existing Field: Orange Petroleum announced that the Wyoming Oil and Gas Conservation Commission today approved Orange’s request for five 10-acre pilot programs on Orange’s Wyoming acreage. These pilot programs consist of a total of 128 ten-acre wells.

“This decision enables Orange to proceed with gathering the data requested by the Commission in anticipation of final approval of field-wide 10-acre downspacing on our Wyoming acreage," stated Orange's CEO.

Interpretation: Downspacing approval can often be a significant positive catalyst for a producer’s stock. Operators wish to downspace fields when they discover that the current spacing of their development wells is not recovering the optimal amount of oil and gas in place. Typically the decision of whether to allow downspacing is rested in a government agency charged with balancing environmental concerns with realizing the full potential of the state's natural resources. Downspacing can increase the recovery of hydrocarbons, but comes at the expense of a larger "footprint" on the environment. The government typically conducts hearings in which the producers will present engineering evidence (typically well pressure data) that downspacing will indeed increase recovery without unnecessarily harming the environment. The committee must be satisfied that incremental wells would truly recover hydrocarbons that would not otherwise be recovered by existing wells. Successful downspacing will lead to additional locations and ultimately reserves.

New Unconventional Play Example 1: Press Release Announcing New Unconventional Play: Red Energy Co. today announced that it is currently testing a new shale gas play in southern Kansas. The company is drilling test wells targeting the


• What are well costs and anticipated average reserves per well?

• Any chance of expanding the arrangement in the future?


• What is the timing for this pilot and when will the field-wide downspace request go to the commission?

• What results have other operators experienced with similar pilots?

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Prolific Shale, an unconventional gas reservoir, ranging in depths from 1,500-8,500 ft. The Prolific Shale is a Mississippian-age shale that is the geologic equivalent of the Abundant Shale found on the Oklahoma side of the Arkoma Basin and the Fruitful Shale found in north Texas. The company has increased its acreage position in the area from 200,000 net undeveloped acres at December 31, 2003 to approximately 500,000 net undeveloped acres today. Of the 500,000 net undeveloped acres, 150,000 is held by conventional production. The undeveloped acreage was acquired at an average cost of approximately $40.00 per acre and the average primary lease term is over 10 years.

Red has recently drilled and completed four vertical wells in the Prolific Shale. The Prolific Shale was present as predicted and appears to be range in thickness from 75 to 400 feet. The four wells have responded to fracture stimulation treatments and have shown preliminary production rates in the range of 150-500 Mcf per day.

Interpretation: While it is still early in terms of production history, this is a positive development for Red Energy and the announcement will likely be met with a positive market reaction. Shale plays are characterized by long-life production, low-decline reserves, reliable production growth and low costs over time.

This release indicates that the shale is rather thick at 75-400 ft, indicating that there should be significant gas in place. To this point, Red has only drilled standard vertical wells to test for the presence of hydrocarbons. Red will likely drill more vertical wells to delineate the field, but will then begin to test horizontal wells and more advanced completion techniques to maximize recovery. The 150-500 Mcf production rates tell us that the shale is likely economic, but are not a good indicator of future IP rates. More technologically advanced horizontal wells will likely yield a significantly greater production rate.

Red is a first mover in the play having accumulated a very sizable position of 500,000 acres. As a first mover, Red was able to find acreage for roughly $40.00 an acre, an attractive price compared to current acreage prices in the Barnett running anywhere from $200-$1,500/acre. Moreover, a 10-year lease term is favorable when compared to the much shorter terms being offered in better-established shale plays (i.e. 2-5 years). The fact that Red is issuing this press release discussing the location of the play and production data indicates that Red is likely satisfied with the size of its position. An announcement of this nature will undoubtedly increase demand for acreage and drive up per acre lease rates. The 150,000 acres held by production is significant in that producers can be contractually forced to relinquish leasehold that is not producing after a certain period of time. Red can concentrate drilling in non-producing areas in order to keep as much acreage as possible held by production. This can be a significant issue for capital-constrained companies or in a particularly tight rig environment.


• How much gas-in-place per section (square mile) and what is the envisioned well spacing?

• When will the first horizontal tests take place?

• What other producers hold acreage nearby?

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Onshore Acquisition Example 1: Press Release Announcing the Purchase of Mid-Continent Producing Properties: Green Resources today announced that it has entered into an agreement to purchase oil and gas properties in the Anadarko Basin for $200MM. Green's internal engineers have estimated total proved reserves to be 12 MMboe, which are 95% oil and 70% proved developed producing. The properties are long-lived with current production of approximately 2,600 boe/d and a reserves to production ratio of 9 years. Lease operating costs are $14.00/boe. Green has identified 4.0 MMboe of proved undeveloped opportunities on the properties with total capital requirements of $25MM. Brown has entered into swaps for approximately 50% of the acquired proved developed producing volumes with the following fixed prices: $63.00 for 2006, $60.00 for 2007, and $58.00 for 2008.

Interpretation: Green is paying $16.67/boe for the proved reserves, or $2.78/Mcfe. Because only 70% of the proved reserves are developed, additional capital of $25MM will be needed to develop the PUDs, bringing the total or "fully developed" purchase price to $225MM, or a more expensive $18.70/boe. The properties have a developed reserve life of nearly nine years, calculated by dividing the proved developed reserves of 8.4 MMboe by the estimated annual production of 949,000 boe.

The LOE of $14.00/boe represents the costs associated with producing the reserves. LOE of $14.00/boe is rather high, but is consistent with more oil weighted properties as oil tends to be more expensive to produce. Depending on the Green’s current rate, the acquisition may result in higher company-wide LOE. Green is able to hedge production in 2006-2008 at attractive prices; however, the declining swap rate indicates that the futures curve is backwardated. By hedging a portion of the production, Green is locking in a the economics of the deal by guaranteeing a realized priced that will result in a positive cash margin when LOE, production taxes, and finding costs are subtracted.


• What are probable and possible reserve estimates for the purchased assets?

• Is there significant potential to reduce costs?

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Analyst Certification The research analyst who is primarily responsible for this research and whose name is listed first on the front cover certifies (or in a case where multiple research analysts are primarily responsible for this research, the research analyst named first in each group on the front cover or named within the document individually certifies, with respect to each security or issuer that the research analyst covered in this research) that: (1) all of the views expressed in this research accurately reflect his or her personal views about any and all of the subject securities or issuers; and (2) no part of any of the research analyst's compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed by the research analyst in this research.

Important Disclosures:

Price Charts for Compendium Reports: Price charts are available for all companies under coverage for at least one year through the search function on JPMorgan's website https://mm.jpmorgan.com/disclosures/company or by calling this toll free number (1-800-477-0406).

Explanation of Ratings and Analyst(s) Coverage Universe: JPMorgan uses the following rating system: Overweight [Over the next six to twelve months, we expect this stock will outperform the average total return of the stocks in the analyst’s (or the analyst’s team’s) coverage universe.] Neutral [Over the next six to twelve months, we expect this stock will perform in line with the average total return of the stocks in the analyst’s (or the analyst’s team’s) coverage universe.] Underweight [Over the next six to twelve months, we expect this stock will underperform the average total return of the stocks in the analyst’s (or the analyst’s team’s) coverage universe.] The analyst or analyst’s team’s coverage universe is the sector and/or country shown on the cover of each publication. See below for the specific stocks in the certifying analyst(s) coverage universe.

Coverage Universe: Shannon Nome: Anadarko Petroleum (APC), Apache (APA), Bill Barrett Corporation (BBG), Burlington Resources (BR), Chesapeake Energy (CHK), Devon Energy (DVN), EOG Resources, Inc. (EOG), EnCana Corp (ECA), Forest Oil Corporation (FST), Kerr-McGee (KMG), Newfield Exploration Company (NFX), Noble Energy (NBL), Pioneer Natural Resources (PXD), Pogo Producing Company (PPP), Southwestern Energy Company (SWN), Spinnaker Exploration Company (SKE), Swift Energy Company (SFY), W&T Offshore Inc (WTI), XTO Energy (XTO)

Phillips Johnston, CFA: Cabot Oil & Gas (COG), Cheniere Energy (LNG), Encore Acquisition Company (EAC), Houston Exploration (THX), McMoRan Exploration Company (MMR), Plains Exploration & Production (PXP), Quicksilver Resources Inc (KWK), Range Resources Corp (RRC), St. Mary Land & Exploration (SM), Stone Energy (SGY), Ultra Petroleum Corp (UPL), Vintage Petroleum (VPI), Western Gas Resources (WGR)

JPMorgan Equity Research Ratings Distribution, as of September 30, 2005 Overweight

(buy) Neutral(hold)

Underweight(sell)

JPM Global Equity Research Coverage 40% 42% 18% IB clients* 46% 45% 39% JPMSI Equity Research Coverage 34% 49% 17% IB clients* 65% 55% 45% *Percentage of investment banking clients in each rating category. For purposes only of NASD/NYSE ratings distribution rules, our Overweight rating falls into a buy rating category, our Neutral rating falls into a hold rating category, and our Underweight rating falls into a sell rating category.

Valuation and Risks: Company notes and reports include a discussion of valuation methods used, including methods used to determine a price target (if any), and a discussion of risks to the price target.

Analysts’ Compensation: The equity research analysts responsible for the preparation of this report receive compensation based upon various factors, including the quality and accuracy of research, client feedback, competitive factors, and overall firm revenues, which include revenues from, among other business units, Institutional Equities and Investment Banking.

https://mm.jpmorgan.com/disclosures/company

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Other Disclosures:

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General: Information has been obtained from sources believed to be reliable but JPMorgan Chase & Co. or its affiliates and/or subsidiaries (collectively JPMorgan) do not warrant its completeness or accuracy except with respect to any disclosures relative to JPMSI and/or its affiliates and the analyst’s involvement with the issuer. Opinions and estimates constitute our judgement as of the date of this material and are subject to change without notice. Past performance is not indicative of future results. This material is not intended as an offer or solicitation for the purchase or sale of any financial instrument. Securities, financial instruments or strategies mentioned herein may not be suitable for all investors. The opinions and recommendations herein do not take into account individual client circumstances, objectives, or needs and are not intended as recommendations of particular securities, financial instruments or strategies to particular clients. The recipient of this report must make its own independent decisions regarding any securities or financial instruments mentioned herein. JPMSI distributes in the U.S. research published by non-U.S. affiliates and accepts responsibility for its contents. Clients should contact analysts and execute transactions through a JPMorgan subsidiary or affiliate in their home jurisdiction unless governing law permits otherwise.

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Revised September 30, 2005.

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