BNP Paribas_E&P Primer

BNPP Knows E&P - A Primer

Primer: Exploration and ProductionQThe basics of the businessQWhat you need to know to follow the stocksQTerms and de! nitions

Equity Strategy, AmericasJanuary 12, 2011

Anne Cameron: (212) [email protected]

Anne Cameron (212) 841 2794 Equity Strategy, Americas

January 12, 2011

TABLE OF CONTENTS INTRODUCTION. 3

Oil natural gas, and liquids. 4

Price benchmarks... 5

Futures... 6

BASICS OF THE BUSINESS. 7

Conventional versus unconventional reservoirs.... 7

Exploration vs development vs exploitation.. 8

Identifying prospects... 9

Drilling.. 10

Leasing and well ownership..12

Going horizontal. 13

Fracture stimulation 14

Acreage math16

Decline curves.17

Going offshore..18

Volumetric calculations..19

FOLLOWING THE STOCKS....22

Reserves...................................................22

Reserve life....................23

PV 10.......23

Finding costs. 24

A few things about oil and gas accounting..25

Costs on the income statement..25

Successful efforts versus full cost methods..25

Taxes.26

A few problems with earnings...... 26

Valuation methodologies 28

FOR MORE INFORMATION.. 31

INDEX 32


January 12, 2011

INTRODUCTION The purpose of this primer is to take you through the basic concepts and terms you need to know to follow E&P companies. It focuses solely on the upstream business, or the first step in the journey of hydrocarbons from the ground to the end user.

Upstream activities include both:

Exploration: the geological study of the structure and processes of the earth, the leasing of land from a private owner or government, and the drilling of wells to determine whether commercially viable quantities of oil and gas are present.

and

Production: the production of oil and gas from the ground and sale at market prices.

Midstream companies include gathering, pipeline and marketing firms that transport and sell oil and gas to wholesale customers (utilities and refiners). Downstream firms includes refining businesses that turn crude oil into usable products as well as the gas stations and other retail outlets that sell products to end users. Some firms do exploration and production in conjunction with these other businesses, and these firms are known as integrateds. You will often hear exploration and production firms referred to as independents, as they are independent of the other midstream and downstream businesses

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Oil, natural gas, and liquids Oil and gas are hydrocarbons, or chemical compounds of carbon and hydrogen formed from decayed organic matter deposited in layers of rock under the

round. g A common misconception is that drilling for oil and for gas are two different businesses. This is not the case, and most reservoirs naturally produce at least small amounts of both. Today, most domestic independent firms are largely gas-producing. The word gas refers to natural gas, not gasoline, which is a product made from crude oil.

Gas gasoline

Crude is mostly used for transportation

Oil is the same thing as crude oil, which is synonymous with petroleum. Crude is a raw product, a raw mixture of hydrocarbons that can be refined into products such as jet fuel, gasoline, naptha, heating oil, asphalt, and chemical feedstocks. Crude is not a standard product, so think of it like beer. It comes in an almost unlimited set of varieties, some more valuable than others: sweet, sour, heavy, light, waxy, acidic, and so on. Crude is determined to be sweet or sour depending on its hydrogen sulphide and carbon dioxide content. Its API (American Petroleum Institute) gravity is a measure of how heavy or light the oil is compared to water. The lighter the oil, the easier it is to produce and sell. Crude is predominantly used as a transportation fuel.

Gas is used for

electricity, cooking, steam

Natural gas is an odorless and colorless gas. The main ingredient in natural gas is methane, a compound comprised of one carbon and four hydrogen atoms. Methane is often accompanied in natural gas by liquids referred to as natural gas liquids or NGLs. NGLs are separated from methane in processing plants and include ethane, propane, butane, and natural gasoline (often referred to as condensate). Gas with liquids is referred to as wet gas or rich gas. If liquids are not present, the gas is considered dry gas. In the US, natural gas is used for power generation, heating, cooking, steam, and for feedstock in chemical manufacturing. Dont confuse natural gas with liquefied natural gas (LNG): natural gas that has been cooled and condensed into liquid form in a liquefaction plant. Liquefaction condenses gas to 1/600th of its volume and enables its transport from areas of the world where it is plentiful (e.g. Australia, the Middle East) to end users (e.g. Japan, Korea, Europe). Once in liquid form, LNG is transported on tankers and transformed back into natural gas by a process called regassification. While LNG enables the transport of natural gas across distances that would prove uneconomic by pipeline, both liquefaction and regassification require massive upfront investments in infrastructure.

LNG NGL

Oil is most often measured in barrels (bo or bbl), while gas is most often measured in thousand cubic feet (Mcf). However, you can use either metric to measure either fuel.

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On an energy equivalent basis:

Oil Gas

1 bo (barrel) = 6 Mcf (thousand cubic feet) 1 Mbo (thousand barrels) = 6 MMcf (million cubic feet) 1 MMbo (million barrels) = 6 Bcfe (billion cubic feet)

1 Bbo (billion barrels) = 6 Tcfe (trillion cubic feet) Natural gas is sometimes measured in British thermal units (Btu), which refers to heating value rather than volume. If youre talking about dry gas (e.g. no liquids):

1 MMBtu (1 million Btus) 1 Mcf (1,000 cubic feet) of natural gas.

You can convert a combined liquids and natural gas stream into either barrel oil-equivalent (boe) or thousand feet-equivalent (Mcfe) units. Firms typically choose one metric or another to talk about their reserves and production.

Price benchmarks The E&Ps are generally price-takers; they accept market prices unless they have locked in long-term supply contracts or have hedged production on the forward curve.

Natural gas benchmarks The Henry Hub price is the U.S. benchmark price for natural gas. Henry Hub is an intersection of natural gas pipelines located in Louisiana where NYMEX contracts physically settle. Gas is most often measured in $/Mcf (volume) but also can be measured in $/MMbtu, which refers to energy content. Dry gas has an energy content of 1,000 btu/Mcf, so dry gas at Henry Hub should sell at the index. Wet gas (rich gas) contains a higher energy content than dry gas and sells at a premium to the index. Gas at Henry Hub with 1,200 MMbtu content should sell at 1.2x the Henry Hub price.

Wet or rich gas sells above the benchmark

The term, bid-week price refers to average prices over the last five trading days of each month, when most physical gas contracts are sold for delivery the following month. Since producers sell most of their gas at bid-week prices, analysts typically use bid-week prices in their models. Natural gas markets are regional, and the U.S. natural gas market is largely driven by its own supply and demand dynamics. The growing market for LNG is slowly transforming natural gas into a more global commodity, but in for the most part, natural gas price tends to be priced on its proximity to market and its heating value (or energy content).

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Within the U.S., local gas can sell at a premium or discount to Henry Hub depending on location. Traders swap natural gas contracts at "hubs" across the country, and each hub has its own supply/demand dynamics and premium or discount to Henry Hub. Other major natural gas hubs include CIG and Opal in the Rockies, AECO in Canada, and Houston Ship Channel (on the Gulf Coast). Natural Gas Pipeline Network

Basis differentials (or just basis or differentials) are the premium or discount of the price of gas to Henry Hub thats due to location. Basis is a spread that fluctuates based on regional supply and demand dynamics as well as pipeline space. Basis risk is defined as the risk that basis differentials (the spreads) widen or narrow relative to Henry Hub contracts. Producers can hedge their basis risk by swapping their local hub price to Henry Hub. When basis widens dramatically at a hub, you will see a basis blowout. Basis blowouts have plagued gas in the Rockies, where there is significantly more gas produced than consumed. Gas leaving the Rockies can either pay a ticket east in the form of firm transportation (contracted space on a pipeline) to receive the local price at the other end, or take its chances on local prices. In period of higher supply than demand, local gas will bid down the free space in the pipes to arrive at lower prices. The past several years have seen the expansion of pipelines out of the region, and Rockies basis has narrowed considerably. Crude benchmarks Unlike natural gas, crude prices are set globally. The benchmark prices for crude include:

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x WTI: WTI stands for West Texas Intermediate, which is a light, sweet, high-quality crude oil. Most NYMEX contracts for crude are based on WTI, and the physical contracts settle in Cushing Oklahoma.

x Brent: a particular kind of crude from the North Sea that is traded on

the International Petroleum Exchange in London. Slightly heavier than WTI, Brent crude typically trades at a $1-$2 of a discount to WTI.

Crude can sell at varying discounts to the WTI and Brent benchmarks owing to its particular composition. These differentials widen and contract based on the supply (i.e. production) and demand (e.g. refining capacity) for each particular kind of crude. Futures Contracts based on benchmark prices for oil and gas are actively traded in the forward market. The strip price refers to market expectation of average benchmark prices over a certain period of time. The strip price is the average of all monthly futures prices for the specified period. The 12-month strip is simply the average of each of the next twelve months futures prices. The 24-month strip is the average of each of the next twenty four months futures prices.

Strip prices = average of futures prices

The strip can more generally refer to the forward curve. You will hear an E&P executive say that he based his capital expenditures budget on the strip, which just means they budgeted based on their expectations of cash flows calculated with futures pricing. Likewise, an analyst might tell you that she ran her model at strip, which means she used NYMEX futures to calculate the expected future cash flows. The terms, backwardation and contango both describe the shape of the futures curve. A curve in contango is upward shaping, which means the futures prices are higher than the spot price. Contango curves indicate that the market expects rising prices. A backwardated curve is the opposite: downward sloping, with the market expecting lower prices.

$76

$78

$80

$82

$84

$86

$88

$90

$92

$94

$96

Source: BNP Paribas

Backwardation

Contango

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BASICS OF THE BUSINESS Conventional versus unconventional reservoirs In the U.S., the largest and most accessible reservoirs have likely been depleted and the search for oil and gas is moving towards smaller and/or more complicated reservoirs. Todays exploration is largely driven by the technologies that identify reservoirs and the drilling techniques that improve the chance of success. The early, low-hanging fruit of domestic oil and gas exploration were large conventional reservoirs at shallow depths. A reservoir is a continuous deposit of oil and/or gas in the pores of a rock underground - think of a large sponge full of water. Most of the low-

hanging fruit is already gone

The first oil and gas exploration targeted whats known as conventional reservoirs. For the existence of a conventional reservoir, three conditions must be met:

x A source rock that is rich in organic matter and can generate hydrocarbons

x A reservoir rock, or rock that has pores for the oil and gas. The

most common types of reservoir rock are sandstone or carbonates.

x A trap, or means by which hydrocarbons are contained on each

side by non-permeable rock, salt, or water.

Operators can exploit conventional reservoirs by drilling a well and using the pressure differential to extract oil and gas a process much like drinking through a straw.

Operators have increasingly targeted unconventional reservoirs for oil and gas deposits. Unconventional reservoirs were the rocks passed over in earlier oil and gas exploration, because they were believed too difficult to exploit. Unconventional reservoirs are continuous rock layers underground. These reservoirs include low-permeability rocks such as shale and tight sands as well as heavy oil, oil sands, and coalbed methane.

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A good way to think about our hydrocarbon resource is a concept called the resource triangle, developed by Dr. Stephen Holditch at Texas A&M. The resource triangle depicts oil and natural gas sources from the easiest to find and exploit down to the more difficult. The approach holds that conventional reserves represent a relatively small portion of our total recoverable resource, but accessing the far greater, unconventional resource will require higher prices and more sophisticated technology.

Source: IADC.org

Exploration versus development versus exploitation Exploration The search for new oil and gas deposits: Leasing

acreage, conducting seismic tests, procuring drilling permits and rigs, and drilling wells.

Development Drilling on less-risky or more-known reservoirs.

Exploitation The extraction of oil and gas from more mature fields Exploitation involves the extraction of greater quantities of hydrocarbons from existing, producing wells. Exploitation includes enhanced oil recovery efforts or EOR (flooding old reservoirs with carbon dioxide, water, or steam); stimulating previously fractured zones (refracs), and cleaning out old wellbores (workovers).

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Identifying prospects The first step in exploration starts with geologists, who study of layers of the earth to identify where oil and gas deposits might exist. Operators try to identify new plays, new formations or areas where hydrocarbons might be found.

Within an overall play, geologists attempt to identify individual reservoirs or well sites, known as prospects. For a highly speculative prospect a reservoir, in a new formation or new area an operator would typically shoot seismic to map underground geological structures. Seismic is the shooting of sound waves to map out geological structures and locate hydrocarbons. Seismic can be done on a 2-dimensional or 3-dimensional basis. Seismic Log Data

Source: McMoran Exploration Dont be intimidated, the interpretation of seismic data is usually very difficult for most financial analysts to comprehend, but operators like to pull it out sometimes to explain an exploration concept. Once an operator has determined the best place to place a well, the firm will apply for a drilling permit with the appropriate regulatory agency, contract a rig, and then finally spud (or break ground with) an exploration well, sometimes referred to as a wildcat well.

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Following an exploration result and with a greater degree of whats known as well control (e.g. data about the reservoir), an appraisal well, step-out well, or delineation well might be drilled nearby. Appraisal wells are drilled to determine the extent of a field and de-risk a project. If no hydrocarbons are found in an exploration well, the well would be referred to as a dry hole. The cost of a dry hole might be very small (several hundred thousand dollars for a shallow onshore test), or very large (up to $100MM for some deep wells offshore). Drilling E&Ps operate drilling activities, but they typically dont own the rigs themselves. Most upstream firms choose to contract rigs from independent companies focusing on drilling and drilling equipment, known as oilfield service companies. Types of rigs vary from relatively simple and inexpensive rigs for shallow onshore wells to semisubmersible, floating rigs in the deepwater that require hundreds in staff. Service companies typically charge E&Ps for their rigs by the day on long-term contracts. Employees of both the drilling company and the E&P would be man the rig, and drilling rigs typically operate 24 hours a day. Diagram of Onshore Rig

Source: Howstuffworks.com

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What enables hydrocarbons to flow are pressure differentials between the fluids in the reservoir rock and the pressure in the wellbore (the vertical column created by the drill bit as it moves down). Rig crews are not always able to control the pressure differentials in a wellbore, and an explosion of underground reservoir pressure, or a blowout, can cause oil or gas to shoot up out of the reservoir. Typically, a mechanism called a blowout preventer or BOP stack is installed on the rig or the ocean floor to contain these situations. No matter how skilled an operator, it is very difficult to drill through rock in a precise path, for rock types of varying densities can cause the drill bit to divert from its intended path. Faced with mechanical problems or new information about a reservoir, an operator might direct the drilling crew to sidetrack a well. Sidetracking involves drilling straight down through the existing hole and then directionally off to one side to avoid obstruction.

Sidetracking is not usually a good sign, but it doesnt mean the well

is unsuccessful

Most well bores are lined with a layer of steel casing in parts or the entire drilling hole. Along with a layer of cement, casing separates reservoir rock from the wellbore and is designed to enhance the structural integrity of the hole. Casing is set in strings, or sections as the drill bit moves down. Reaching the bottom of the well is called reaching TD, or total depth. Operators will conduct certain tests while drilling.

Cuttings analysis: Analyzing the bits of rock kicked up by the drilling fluids or mud while the well is drilling.

Logging: Using seismic and radiation technologies downhole to

determine rock formation type and porosity. Sometimes operators have to stop drilling activity to stop to carry out logging, but sensors can also be attached to downhole equipment and give real-time feedback, a process called logging-while- drilling.

Core sampling: Taking a cylinder of rock drilled from the well up to the

surface. Flow testing: Attaching a meter, to the top of the wellbore to perform a

test to see how fast oil and gas can flow. Flow tests are typically conduced after the well is completed. However, drill stem tests (DSTs) are carried out in the well while drilling is taking place. DSTs are used to obtain samples of fluids and to measure downhole pressure and potential flow rate.

Knowing the kinds of drilling tests will help

you interpret news flow

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Leasing and well ownership Firms spend a considerable amount of their capital budgets leasing mineral rights in new areas. In the US, mineral rights are often owned separately from land surface rights. To explore onshore, firms will approach individual landowners or the government. Most lease terms, onshore and off, are usually structured where an operator will offer the landowner an upfront bonus payment and a retained royalty on future production.

Lease bonus payments for federal

Deepwater leases range from several

thousand dollars up to ~ $100MM

To explore in the federal waters of the Gulf of Mexico, Operators bid on leases from the federal government. The BOEM or the Bureau of Ocean Energy Management (formerly the Mineral Management Service) holds lease auctions twice a year,

A royalty is defined as a certain percentage of gross production from a well or a lease. Royalties are non-operated interests, and domestically they typically range from 10-20%. Companies that operate on federal lands or waters owe royalty payments to the US government, and companies that operate overseas typically owe royalty to the foreign government. Lease agreements usually require an operator to drill and produce from a well on the lease within a specified time period (the lease term) or relinquish the lease.

Firms report proved reserves net of

royalties and their working interest

Firms refer to their ownership in a particular well or lease as their working interest. The ownership of an exploration project might be split between several parties (50% for one firm, and 50% for another firm), and working interest partners split well costs and future revenues pro-rata with their ownership stake. A firms working interest is gross of its royalty, and a firms net of its royalty is referred to as its net revenue interest, or NRI. Mathematically,

NRI = working interest x (1- royalty).

For example, a partner that owns a 50% working interest of a lease with a 20% royalty would have an NRI of 40%. A firms ownership in a project can be operated or non-operated. An operator of a lease is in charge of all activities and decisions on that lease: securing a rig or rigs, staffing operations, making on-site decisions, and making decisions about the pace of drilling.

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A non-operated partner signs off on well design (overall drilling plans) and shares in all economic ownership having to do with the lease or well, regardless of whether the well is successful or unsuccessful. Non-operated owners receive all drilling data and production updates from producing wells. Typically, the operator of the well pays all bills upfront and sends invoices to its non-operated partners. Ownership terms of a lease are typically spelled out in a wells joint operating agreement, or JOA.

An example of disharmony among joint

operating partners can be found among the

owners of the BP Macondo Well. Non-

operated partners Anadarko and Mitsui,

dispute BPs assertion that they own a

proportional share of liabilities.

Aside from seeking out leases from landowners, firms can obtain ownership in others leases by a process known as a farm in. Farming into a well mean obtaining an interest in a lease by agreeing to assume some (or all) of the costs involved in future exploration and development. Operators can sell portions of their ownership in a well or a lease by whats known as a volumetric production payment, or VPP. A VPP is the sale of a certain amount of oil and gas production volumes in return for up-front proceeds (the net present value of those future revenues). Most of the time, reserves sold in a VPP are removed from the sellers reported reserves and production. Firms can monetize land positions through joint venture agreements with other operators. The industry has seen a large number of these deals in recent years, where independents have monetized large portions of their assets by bringing in other independents or larger, integrated firms to help fund exploration. Since larger firms typically have a lower cost of capital, these deals have a natural place. Value can be created by the moving development assets into the hands of larger players while smaller independents use their cash flow to find new reserves. Joint venture agreements are often structured with a drilling carry, where the buyer pays for the acreage by assuming a disproportionate share of the sellers future drilling costs. The carry allows the seller to avoid some of the gains on sale for tax accounting purposes. Going horizontal Currently, most domestic onshore activity targets unconventional reservoirs and employs the relatively recent innovations in horizontal drilling and fracture stimulation. The lowest-cost source of new natural gas is currently found in shale, a highly impermeable sedimentary rock. Shale was formed by the deposition of organic matter on the bottom of oceans or other bodies of water and exists in relatively thin but widespread layers under the earths surface. Rich in organic matter, shale is often the source rock for conventional reservoirs. Until the commercialization of horizontal production from the Barnett Shale near Fort Worth, Texas in ~2003, production from shale rock itself was believed uneconomic.

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US Shale Gas Basins

Fracture stimulation Horizontal drilling involves drilling down to the target formation, turning the drill bit sideways, and continuing laterally through reservoir rock. Horizontal drilling is often accompanies by the process of fracture stimulation. Operators use fracture stimulation to increase the flow rate and ultimate recovery from a well. The first kind of fracturing was done with explosives. Firms now use hydraulic fracturing, which involves the injection of water and frac fluids under very high pressure into the reservoir rock. Fracture stimulation is done to generate fractures or cracks in the reservoir and enable gas to flow more freely. The injection of these fluids uses pressure pumping equipment.

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Diagram of Horizontal Wellbore

Source: Geology.com Fracture fluids involve mostly water mixed with sand, or other proppants. Proppants are small spheres intended to hold open the fractures in rocks after the initial pumping is over. Frac fluids can also include chemicals to reduce friction in the frac and increase its effectiveness. Fracs that include a friction reducer are called slick fracs. Fracture fluids usually involve a chemical, most often biocide, that sterilizes the rock and prevent bacteria growth in the reservoir. Many of the environmental complaints about fracture stimulation involve concerns about the effects of biocide.

Multi-stage fracs are done in stages or sections along the horizontal part of the wellbore. Operators typically experiment to determine the optimal fracture technique, lateral length, and number of stages. It is important to note that fracture stimulation technology and horizontal drilling are not always hand-in-hand. A firm can fracture stimulate vertical wells (for example, the Wattenburg field in Colorado or the Spraberry formation in Texas) or drill horizontal wells without fracking them (in naturally fractured reservoirs). Fracture stimulation can be used to exploit older fields. Wells may be fractured more than once in a lifetime; an operator might refrac a well after a certain number of years in order to boost production.

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Acreage math Aside high initial production rates from the effect of fracture stimulation; its the repeatability of shale drilling that can make shale drilling economically attractive. Unlike conventional reservoirs (anomalous structures that require the existence of a source rock, reservoir rock, and trap), layers of shale exist in fairly consistent, contiguous, and expansive sections. The success rate on shale drilling is typically higher than for conventional drilling, and operators can de-risk a large portion of their acreage on comparatively few results. Once a firm is comfortable with the rock properties on its acreage, estimating total resource requires an assumption about the optimal spacing of wells. Spacing wells too close to each other causes them to compete; spacing them too far apart leaves money on the table. Typically an operator will begin drilling in a new play by spacing wells relatively far apart from each other. Over time and with several years of production data, operators will decide to downspace, or plan new well penetrations closer together.

Well spacing is important, because it will help you estimate

future, eventual reserves from a play.

You will hear operators refer to the spacing of their wells by how many acres are drained by one penetration. A square mile contains 640 acres.

Drilling 640s = one well per square mile

Drilling 160s = four wells per square mile

Drilling 80s = eight wells per square mile

Spacing Assumptions for Vertical Wells in the Wattenburg Field

Source: Noble Energy

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Decline Curves All wells, convention and unconventional, produce at a rate that more or less declines over time. The simple explanation is that reservoir pressure drops as hydrocarbons exit a reservoir, and the pressure differential between the reservoir rock and the wellbore decreases. When you aggregate all the producing wells in the U.S., the production decline from existing wells has been about ~30% per year. The projection of decline curves is one of the most widely-used methods in the industry for projecting reserves.

Firms will often press release IP rates from

new plays, or new parts of a play

The initial decline for shale gas wells tends to be relatively steep compared to naturally fractured or conventional reservoirs. Firm will calculate an initial production rate, or an IP rate, which is the average flow rate for the first 24 hours or certain number of days of a well. The market views initial production rates from new plays as important data in that they can indicate an eventual EUR. The EUR of a well is its estimated ultimate recovery, or total produced reserves. EUR EUROPE

The graph of production versus time is called a type curve. Type curves vary in shape depending on reservoir type. The shape of the decline curve is very significant, in that an EUR can be very sensitive to small changes in decline.

Sample Decline Curve

Investors use initial production rates to

compare wells to each other and

possibly infer a EUR

Source: PDC Energy

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Many shale wells exhibit hyperbolic declines. A hyperbolic decline describes a production rate that falls at a decreasing rate over time, i.e. decline drops off, and production flattens out. Some wells decline at a constant rate, and those decline curves are described as exponential declines. The shape of the decline curve for hyperbolic wells is described by whats called a B-factor. The B factor is simply the rate at which the decline rate is decreasing. The higher the B factor, the faster the decline rate is dropping. For exponential wells, the B-factor is zero. Theoretically, a hyperbolic decline would imply a well should produce for infinity. As a practical matter, operators will produce wells as long as the revenue generated by declining production exceeds the wells cash operating costs. Going offshore Domestically, the majority of capital spent on conventional exploration takes place in the Gulf of Mexico. The earliest activity in the Gulf of Mexico targeted relatively shallow reservoirs in shallow waters. As the low-hanging fruit of the Gulf has been slowly depleted, operators have moved off the Shelf into deeper waters and greater distances beneath the sea floor.

Operators have defined several plays

within the Gulf of Mexico: some on the

Shelf, some in the Deepwater, some

more oily, some more gassy

Deepwater exploration is a very different business from onshore, unconventional exploration. Operators target reservoirs up to 40,000 feet beneath the sea floor and hundreds of miles from existing activity or infrastructure. Compared to most unconventional onshore activity, exploration in the Gulf involves higher geological risk, longer cycle-times, and larger upfront capital commitments. The fields being targeted, however, are very large and high quality. To drill in the Deepwater, operators contract rigs from an offshore service company. Rig slots are signed up months to years in advance, and the day rate for a vessel could be $300-500K per day. A single well could take several months to drill and cost as much as $250MM to drill and complete an especially deep target. Historical success rates are hard to measure, but most operators say that they predict a 25-33% average chance of geological success.

The scale of deepwater projects is

massive

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Deepwater Floating Rig (Noble Clyde Boudreaux)

Source: Noble Corp A successful exploration well in the Deepwater will be often years away from first production. A firms first move following a successful well will be to analyze its the new data, map out where next to drill on the structure, and think about options re infrastructure. Large fields will often involve a dozen or more wells across the structure to drain. The big-ticket and long-lead time item for large Deepwater developments is often the infrastructure. New fields can be hundreds of miles from existing pipelines or platforms, and firms can spend several years building floating or standing facilities to process oil and gas. In addition to platforms, firms have to construct or contract out the construction of subsea connections to move oil and gas back to shore. High, fixed, upfront capital costs mean that Gulf of Mexico developments are often driven by an economy of scale. A frequently-used rule of thumb is that operators typically target fields over 100 MMboe to make their investment in an exploration well worthwhile. Fields that are discovered close to existing infrastructure, or close enough to be tied in to existing platforms by pipeline, can be more valuable.

Volumetric calculations Operators typically wont complete a successful offshore exploration well right away, due to infrastructure constraints. The operator will judge the wells initial success on the quantity and attributes of pay encountered.

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Pay simply refers to the vertical distance of a hydrocarbon-bearing rock that is discovered. Typically, hydrocarbon-bearing rock will be interrupted by layers of non-reservoir rock. Net pay refers solely to the reservoir rock intervals. Gross pay includes the non-reservoir rock. Beyond pay, operators will consider the aerial extent of the field (the length and width if it were a rectangle), often measured in acres.

Net pay x aerial extent (acres) = total reservoir volume (acrefeet) 1

A reservoir is a mixture of rock and hydrocarbons (think of the wet sponge example), and within that, the quantity of oil or gas is called oil in place (OIP) or gas in place (GIP). OIP and GIP depends on the rocks porosity, or the volume of rock that can be occupied by fluids. Firms use cuttings, cores, or logs to measure porosity. Porosity is governed by a rocks matrix, or the natural order or particles within the formation.

Porous Material

Source: Globalsecurity.org

High permeability and porosity indicate

good reservoir rock

Within the OIP and GIP, the percent of oil and gas that a reservoir will produce is called the recovery factor. The recovery factor depends on the reservoir rocks permeability, or the ease through which fluids can flow. Permeability measures how connected the pores in the rock are to each other, and operators can only determine permeability by taking a core sample. The recovery factor also depends on the oils viscosity. Permeability and porosity are positively related. Gas can flow from rocks with low porosity and permeability more easily than oil.

1 The engineering formula used to calculate reservoir formula is the same as the concepts outlined above. Stock tank barrels of oil = (V x 7758 x O x S x R)/ FVF. V = volume of oil-pay zone expressed in acrefeet. 7758 = barrels in an acrefoot. O = porosity, which is expressed in a decimal. S = oil saturation, expressed in a decimal. R = recovery factor. FVF = oil/gas ratio.

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A recovery factor will also adjust for the difference in volume between fluid in the reservoir and fluid as it exits the wellhead. The difference between these two volumes is usually the amount of gas that is dissolved in oil in the reservoir and is referred to as the formation volume factor. Estimated reservoir size = reservoir volume (acrefeet) x recovery factor

As an investor, you will rarely get all the

inputs to these calculations, but its

necessary to know the concepts

Investors rarely get enough data (or good estimates) to calculate reservoir size from a single discovery well. Firms often announce feet of pay discovered, but feet of pay alone will not indicate the size of the reservoir: large fields can have very large aerial extents and relatively thin pay, or very tall pay section and smaller aerial extents.

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FOLLOWING THE STOCKS Reserves The assets of an E&P company are its reserves, or the quantity of oil and gas it can produce from the ground. Calculating reserves requires a degree of estimation, because no reservoirs true recovery can be known until its abandoned. (Abandonment is a procedure required by law once an operator leaves a reservoir.) A firms proved reserves are its oil and gas deposits that reservoir engineers have determined have a 90% chance of being recoverable in that quantity or greater. Firms calculate their proved reserves at the end of each fiscal year and report reserves in their 10K, as required by the SEC. To calculate the quantity of reserves, a flat price deck is used that is determined by the average oil and gas prices on the first day of the month of each month of the year. Firms can report reserves that provide a 0% rate of return (cash breakeven) or greater. The particular price deck affects volume of reserves that are reported: firms will always have more recoverable reserves given higher oil and gas prices and far fewer reserves at lower oil and gas prices. The quantity of a firms proved reserves can be highly sensitive to the oil and gas prices used, and changes in prices from year to year will cause firms add or subtract reserves from their proved calculation, as deposits become economic or uneconomic depending on prices. The change in quantity of reserves from year to year based on prices is categorized as a price revision to reserves. Firms can also revise reserves based on well performance, a change in service costs (e.g. rig costs), or a change in basis differentials.

The number of barrels are firm reports can be

highly sensitive to prices, costs, and basis

Proved reserves come in three types: proved developed reserves (PD), proved undeveloped (PUD), and proved developed non-producing (PDNP). Proved Developed (PD) reserves are oil and gas deposits from already drilled and producing wells.

PD

+ PDNP

+ PUD

= Proved Reserves

Proved Developed Nonproducing (PDNP) reserves are wells that are drilled but not currently hooked up and flowing. Proved Undeveloped (PUD) reserves are oil and gas expected to be produced from wells not-yet-drilled, or from the recompletions (re-entry) of old wells. Companies can book PUDs near locations of an existing (PDP) wells in the same zones, as long as they plan to drill them in the next five years.

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January 12, 2011

The important economic distinction between PUD and PD reserves is that PUD reserves require a capital outlay to convert to PD or bring to production. All other factors being equal, a companys proved reserves with a higher percentage of PD/total reserves should be worth more than a companys reserves with a higher PUD ratio. Companies have a significant amount of discretion as to how many PUDs they wish to book, and PUD booking practices may vary widely between firms. Beyond proved reserves, firms often talk about probable or possible reserves. Probable reserves are a firms oil and gas reserves that are not proven but are still likely to be produced. By definition, they have a chance greater than 50% but less than 90% of being economically and geologically feasible. Possible reserves are a category of reserves one step more speculative than probable reserves and have a probability of greater than 10% but less than 20% of being recoverable. Beyond possible reserves, a firm might also reference its contingent reserves, the most speculative category. The terms, 1P, 2P, and 3P reserves are often used. 2P Tupi

1P Reserves = proved reserves = > 90% chance recoverable 2P Reserves = proved + probable reserves = > 50% chance recoverable 3P Reserves = proved + probable + possible reserves = > 10% recoverable Reserve Life You might hear the phrase, reserve life, which refers to the theoretical amount of time it would take to deplete or produce a firms reserves at current production rates. Mathematically, reserve life equals R/P, which stands for reserves divided by production. A firms R/P can vary dramatically, and the measure indicates the nature of a firms assets. Wells in the Gulf of Mexico could produce for as little as five years (a low R/P), while a gas well in the Marcellus shale might produce for 40 years (a higher R/P). Equity investors typically discount the cash flows from firms with short R/Ps because of higher reinvestment risk. PV10

PV10 is the first step in building an NAV

(see page 28 in Valuation

methodologies)

Beyond the quantity of proved reserves that public firms are required to report to the SEC, they report the net present value of those reserves in a PV-10 Calculation or a Standardized Measure calculation. A PV10 estimates future net cash flows (revenues less capital and operating costs) from the companys proved reserves at a discount rate of 10%. In the PV-10 calculation, companies provide their own assumptions regarding future costs and well declines. Standard measure calculations are after-tax; PV10 calculations are pre-tax.

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January 12, 2011

For the PV10 calculation (as in the calculation of the quantity of proved reserves), firms use the SEC price deck and assume those prices are held constant. Investors typically use the undiscounted data from the PV10 calculation to model their own estimate of the value of a firms reserves. The PV10 itself is not a good estimate of the value of a firms reserves at any moment in time, given that it assumes a fairly arbitrary flat price deck and disregards some costs (e.g. overhead and infrastructure capital costs). Finding Costs Investors often use reserve data to calculate a capital efficiency metric called F&D. F&D refers to finding and development costs, which measure the capital spent in order to bring proved reserves on the books. F&D can be calculated in multiple ways, but a simple calculation for F&D is:

annual drilling, leasing, site preparation, completion, and well hook-ups costs

annual proved reserve adds Investors typically look at F&D on an annual basis, matching capital spent in a year with reserve adds in that same year. The metric is typically expressed per boe or per Mcfe and strips out proved reserves bought and sold as well as their associated costs. What complicates F&D is that proved reserves include both drilled (PD reserves) and undrilled wells (PUDs). Dividing capital by total reserve additions can mask the true cost of drilling, because, until they are converted to PD reserves, PUDs incur no significant capital investment to bring on the books. An increase in PUDs in any given year will understate the denominator of the F&D calculation.

PD F&D is the preferred metric for

among the many ways of calculating

F&D

Investors often adjust for PUDS in the F&D calculation to get PD F&D, which stands for Proved Developed finding and development costs. PDF&D adjusts for PUD reserves by stripping out the change in PUDs. F&D metric are driven by an operators efficiency and cost controls as well as the quality of a firms assets. Higher-cost plays (e.g., assets that require a higher breakeven commodity prices) will lead to higher F&D. Lower-cost plays, e.g. more economic assets, will lead to lower F&D. A companys F&D or PD F&D may be erratic from year to year, despite little change in the firms asset base. Part of the reason timing differences between when capital is spent (on acreage or science) and when proved developed reserves come on the books. Firms that explore for larger fields typically have longer project cycles, and therefore time lags between capital spending and reserve adds. For a company thats growing, this time lag can cause F&D or PD F&D to be overstated. F&D metrics run on an annual basis work best for companies with shorter cycle times, such as shale companies.

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January 12, 2011

A few things about oil and gas accounting Costs on the income statement COGS (cost of goods sold) is typically absent on an oil and gas companys income statement. Cash operating costs for an oil and gas firm are categorized as G&A (General and Administrative expense, which is overhead), severance taxes (state taxes on the production of oil and gas), and LOE (Lease Operating Expense). LOE includes all direct costs to keep wells hooked up and flowing: labor costs, repairs, materials, supplies, insurance costs, and fuels consumed. LOE is often reported in one line item combined with transportation expense. Transportation expense includes the midstream pipeline and processing costs involved in transporting oil and gas to market, removing NGLs from the gas stream, and compressing natural gas to meet pipeline pressure requirements. Investors often refer to a companys cash margin on a per-unit basis. The cash margin is simply

(revenue G&A LOE) production (Mcfe or boe). Successful efforts versus full cost methods You will occasionally see non-cash charges called reserve impairments, which are charges to earnings representing the difference between the book value of a company's reserves (as carried on the balance sheet) and the estimated discounted future net cash flows of those reserves based on current commodity prices. Impairments are done on a field-by-field basis for firms that use successful efforts accounting, the capitalizing of costs and expected revenues on a field-by-field basis. Reserve impairments are the accounting consequence of reserves that go off the books with a dip in oil and gas prices (or from poorer-than-anticipated well performance). Instead of successful efforts accounting, firms can elect to use the full cost method of accounting, which is the capitalization of all costs related to their oil and gas properties in one pool. Firms that use the full cost method of accounting record writedowns instead of field impairments. At the end of each quarter, full cost companies must conduct a 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. Writedowns are a one-way street: firms cannot write up their oil and gas assets on their balance sheet with an improvement in prices.

Ceiling tests, impairments, and

writedown = non-cash

Firms that follow the successful efforts method of accounting record an additional operating expense, called exploration expense: the capital costs of unsuccessful wells expensed each quarter. Because successful efforts firms record this expense and full cost firms dont, the industry convention is to measure EBITDA as EBITDAX, which simply means EBITDA before exploration expense.

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January 12, 2011

Taxes Smaller, faster-growing E&Ps seldom pay their cash taxes, because independent producers in the US benefit from a very favorable treatment of their capital costs on their tax returns. US producers can expense their intangible drilling costs (IDCs) or a large bulk of their capital expenditures on their tax books. IDCs are the portion of well costs that cannot be salvaged after the well has produced its reserves. IDCs include labor, the rigs costs, frac fluids, pressure pumping services: basically everything except the steel casing in the wellbore. A good rule of thumb is that intangible drilling costs typically comprise ~70% a total wells cost. The expensing of IDCs means that, under tax accounting, firms will likely have negative income as long as they are growing fast enough. The faster a firm is growing, the more it spends on capex relative to cash flow, and so the lower its taxable income. Theoretically, the depreciation of assets on an E&Ps GAAP income statement should catch up to the expensed capital costs on their tax returns, and their payments on taxes will come due. However, GAAP depreciation rates fall every time a company experiences a writedown or impairment, and so the total depreciable asset under GAAP books is typically far smaller than the expensed capex for tax purposes. Larger, slower growing firms typically pay a larger portion of their tax expense in cash, because their taxable income is higher. US producers that have refining businesses are not allowed to expense all of their intangible drilling costs on their tax books; they are allowed to expense only 25% of their intangible drilling costs. A few problems with earnings

Successful efforts versus full cost: The earnings of successful efforts

companies tend to be more erratic than those of full cost companies. Successful efforts firms expense dry holes, which lowers net income. Firms that use full cost accounting capitalize the costs of dry holes which get amortized through depreciation. Pay attention to cash

flow more than earnings

Oil and gas prices: The natural swings in commodity prices make

earnings erratic in general. E&Ps often have negative earnings during period of low oil and gas prices.

Taxes: A large portion of an E&Ps tax expense is often deferred.

Deferred taxes are deducted from net income but, because of swings in commodity prices, are sometimes never paid.

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January 12, 2011

In lieu of earnings, investors typically focus on cash flow or EBITDAX. The industry convention for measuring cash flow is discretionary cash flow or DCF, which is simply operating cash flow before the effect of changes in working capital.

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January 12, 2011

Valuation methodologies: NAV versus multiples Exploration and production companies seldom report free cash flow on the corporate level, because their assets are in a constant state of natural decline. Firms often spend their entire cash flow on growing or replacing reserves through exploration. Investors in the E&P space frequently follow two metrics: NAVs, or net asset value calculations, or forward multiples. x NAV: An NAV is the sum of multiple discounted cash flow models for

each of a firms known assets. An NAV does not assume a firm will remain a going concern beyond producing out its existing, known proved and unbooked reserves. It is, therefore, a theoretical value. A typical NAV will value proved reserves and add unbooked potential for each play where the company operates. An NAV, therefore, typically aims to value P3 assets and anything beyond. Analysts will adjust for debt, taxes, and overhead to calculate a residual equity value. The advantage of an NAV is that it paints a relatively full picture of a security. The disadvantages are that NAVs are time-consuming to contruct and require an enormous number of assumptions.

Many investors use both NAV and

multiples

x EV/EBITDA or P/CF: The advantage of using enterprise value/EBITDA or price/cash flow is that neither metric involves very many assumptions and you can have a relative degree of confidence about your EBITDA or cash flow forecast. The disadvantage of using a multiple is that the reserve life (or repeatability) of cash flow varies widely between firms.

What makes both NAVs and cash flow multiples problematic is that some stocks will trade at a discount or a premium to either metric for very long periods of time. For example, A stock could trade at a steep discount to its NAV because of investor

concern that management will destroy capital through inefficient operations.

A stock could trade at a premium to its NAV because of known new

exploration programs for which the market doesnt have enough data to value.

A stock could trade at a discount on a multiples basis because of

concerns about the repeatability of business (e.g. a potential lack of depth to an exploration inventory).

A stock could trade at a premium on a multiples basis because of a

change in asset base (e.g., an improving asset base several years out). One of the best arguments for using an NAV metric is that E&P stocks move considerably on exploration results that affect long-term cash flows but leave the next several years EBITDA or cash flow unchanged. An NAV model enables you to incorporate new discoveries on a discreet basis and revalue the security.

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January 12, 2011

The author of this primer is not aware of any one metric predictive of performance in the E&P space. Shares of an E&P are levered positions on crude and natural gas with imbedded real options. The shares of an E&P are a call option on the firms known assets as well as on any other assets the firm might discover. Understanding exploration news is therefore crucial to following the stocks. Sample NAV for Forest Oil

| January 10, 2011

EQUITY STRATEGY

Forest Oil Corporation (FST)

Commodity Price AssumptionsNYMEX Futures Custom Deck 1Oil Gas Oil Gas Oil Gas

2010 $79.28 $4.41 $50.95 $5.50 $79.28 $4.412011 $93.00 $4.34 $50.95 $5.50 $93.00 $4.342012 $92.84 $4.95 $50.95 $5.50 $92.84 $4.952013 $91.58 $5.29 $50.95 $5.50 $91.58 $5.29

Long-Term $91.86 $5.29 $50.95 $5.50 $91.86 $5.29

Shares OS 113Discount Rate 10%G&A /Mcfe $0.35Tax Rate 35%Cash Tax Rate 20%

Net Asset ValuationBcfe $MM $/Share $/Mcfe

U.S. Proved Reserves '09 1,746 $3,156 $27.83 $1.81Canadian Proved Reserves 322 $616 $5.44 $1.91Italian Proved Reserves 52 $74 $0.65 $1.43

Hedge $10 $0.09Net Debt ($1,617) ($14.26)Other Liabilities ($73) ($0.65)Other Assets $40 $0.36Net Working Capital ($168) ($1.48)

Taxes (allocated to P1) ($125) ($1.10)G&A (allocated to P1) ($173) ($1.52)

P1 Value $1,741 $15.36

Unbooked ReservesNarraway/Ojay 1,851 $661 $5.83 $0.36Evi and other light oil 130 $443 $3.91 $3.40Utica Shale 1,305 $253 $2.23 $0.19Granite Wash - Central Fairway 1,511 $1,090 $9.61 $0.72Granite Wash - South Fairway 850 $1,097 $9.67 $1.29Granite Wash - North Fairway 348 $254 $2.24 $0.73Core Haynesville 363 $142 $1.25 $0.39Southern Mid Bossier 646 $170 $1.50 $0.26East Texas Haynesville 582 $219 $1.93 $0.38Cotton Valley Horizontal 492 $132 $1.16 $0.27Eagle Ford Shale 575 $888 $7.83 $1.54

8,077

Taxes (allocated to unbooked reserves) ($475) ($4.19)G&A (allocated to unbooked reserves) ($658) ($5.80)

Net Asset Value 10,198 $5,956 $52.53

Anne Cameron, +1 212 841-2794, [email protected]

This Analysis is prepared by Marketing and/or Trading Desk personnel within the BNP Paribas group of companies (collectively BNPP) for distribution to Institutional Investors* only and you should not regard it as research or a research report. This Analysis is therefore not independent from the proprietary interests of BNPP, which may conflict with your interests. We are willing to discuss it with you on the assumption that you have sufficient knowledge, experience and professional advice to understand and make your own independent evaluation of the merits and risks of any transactions in the securities discussed herein. Additional information is available upon request.

Model

Corporate Assumptions

NYMEX STRIP

OTHER PRICE DECK

Source: BNP Paribas

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January 12, 2011

FOR MORE INFORMATION For general information and data on US production, reserves, and consumption of oil and natural gas, visit the EIA (U.S. Energy Information Administration) website. http://www.eia.doe.gov/

For global statistics on oil and natural gas, see the BP Statistical Review. The Review is a massive and very user-friendly document that BP prints annually. http://www.bp.com/multipleimagesection.do?categoryId=9023754&contentId=7044554 For publications on crude price outlook, see the IEA website. http://www.iea.org/ For information on the Gulf of Mexico, including production, well permits, leasing and regulations, see the Gulf of Mexico page on the Bureau of Ocean Energy Management website. http://www.gomr.boemre.gov/

30


January 12, 2011

INDEX

Page(s)

2P 233P 23abandonment 22aerial extent 20

3appraisal well 10barrels 21basis blowout 5basis differential 5, 22B-factor 18bid-week price 4bonus payment 12Brent 6British thermal units (Btu) 4casing 11, 26ceiling test 25condensate 3contingent reserves 23conventional reservoir 7, 13, 16, 17core sampling 11cuttings analysis 11, 20delineation well 10discretionary cash flow 27downstream 2dry gas 3, 4dry hole 10, 26enhanced oil recovery 8exploitation 8exploration 2, 7-9exploration expense 25exploration well 9-10, 19exponential decline 18F&D 24farm in 13firm transportation 5flow testing 11frac fluids 14, 15, 26fracture stimulation 13-16G&A 25gas in place 20gross pay 20Henry hub price 4hydraulic fracturing 14

API gravity

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January 12, 2011

hydrocarbons 2-3, 7-11, 17hyperbolic decline 18IDCs 26impairments 25integrateds 2IP rate 17joint operating agreement 13Joint venture 13lease term 12liquefaction plant 3liquefied natural gas 3LOE 25logging 11midstream 2, 25natural gas 13, 25, 31natural gas liquids 3NAV 28net pay 20net revenue interest 12non-operated 12, 13oil in place 20oil water contract 18operator 7, 9, 11-16, 18pay 5, 19-21PD F&D 24permeability 7, 20porosity 11, 20possible reserves 23pressure pumping 26probable reserves 23production 2, 4, 6, 12proppants 15prospects 9proved developed nonproducing reserves 22proved developed reserves 22proved reserves 22-24PV10 23, 24R/P 23recovery factor 20, 21refrac 8, 15regassification 3reserve life 23, 28reservoir 3, 7revise 22rich gas 3, 4royalty 12

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January 12, 2011

seismic 8, 9, 11severance taxes 25shale 7, 13, 16sidetrack 11spud 9stages 15standard measure 23step-out well 10strings 11strip price 6successful efforts 25, 26TD or total depth 11thousand cubic feet (Mcfe) 4, 24transportation expense 25trap 7VPP 13well design 13wellbore 8, 11, 15wet gas 3, 4wildcat well 9working interest 12workover 8writedowns 25WTI 6

33

This Commentary is prepared by Marketing and/or Trading Desk personnel within the BNP Paribas group of companies (collectively BNPP) for distribution to institutional clients only and you should not regard it as research or a research report. This Commentary is not a product of a BNPP Research Department and the views expressed herein may differ from those of the BNPP Research Department. This Commentary should not be considered objective or unbiased. BNPP may engage in transactions in a manner inconsistent with the views expressed in this material. BNPP may trade as principal in the instruments (or related derivatives), may have proprietary positions in the instruments (or related derivatives), and may make markets in the instruments (or related derivatives) discussed herein. The author of this Commentary will know the nature of firm trading positions and strategies. Marketing and Trading personnel are indirectly compensated based on the size and volume of their transactions. This material is only intended to generate discussion regarding particular instruments and investments and is subject to change or may be discontinued. The information contained herein is provided to you by BNP Paribas on a strictly confidential basis. Any prices, values, or examples of possible transactions contained herein are set out for illustrative purposes only. Actual prices and/or values will depend on market conditions at the time the transaction is concluded. Any indicative price quotations, values, or analyses provided to you have been prepared on assumptions and parameters that reflect BNP Paribas good faith judgment or selection and, therefore, no guarantee is given as to the accuracy, completeness or reasonableness of any such quotations, disclosures or analyses. This material is based upon information that BNPP considers reliable as of the date hereof, but BNPP does not represent that it is accurate and complete and undertakes no responsibility to update such information. Certain transactions or securities mentioned herein, including derivative products, give rise to substantial risk, including currency and volatility risk, and are not suitable for all investors. BNPP transacts business with counterparties on an arms length basis and on the assumption that each counterparty is sophisticated and capable of independently evaluating the merits and risks of each transaction and that the counterparty is making an independent decision regarding any transaction. Unless governing law provides otherwise, all transactions should be executed through the BNPP entity in the investors home jurisdiction. The author(s) attest that the views expressed in the Commentary accurately reflect their personal views about any of the subject securities, issuers, or markets; and that no part of their compensation was/is/will be directly or indirectly related to the expressed views.

BNP Paribas (2010). All rights reserved.

BNP Paribas is incorporated in France with limited liability. Registered office is 16 boulevard des Italiens, 75009 Paris. BNP Paribas Securities Corp., a subsidiary of BNP Paribas, is a U.S. registered broker dealer and a member of the NYSE, FINRA and other principal exchanges. Clients should contact and execute transactions through a BNP Paribas entity in their home jurisdiction unless governing law permits otherwise.

www.bnpparibas.com

TABLE OF CONTENTS INTRODUCTION Oil, natural gas, and liquids Price benchmarks Natural gas benchmarks Natural Gas Pipeline Network Crude benchmarks Futures BASICS OF THE BUSINESS Conventional versus unconventional reservoirs Exploration versus development versus exploitation Identifying prospects Seismic Log Data Drilling

Diagram of Onshore Rig Leasing and well ownership Going horizontal

US Shale Gas Basins Fracture stimulation

Diagram of Horizontal Wellbore Acreage math

Spacing Assumptions for Vertical Wells in the Wattenburg Field Decline Curves

Sample Decline Curve Going offshore

Deepwater Floating Rig (Noble Clyde Boudreaux) Volumetric calculations

Porous Material FOLLOWING THE STOCKS Reserves

Reserve Life PV10 Finding Costs A few things about oil and gas accounting

Costs on the income statement Successful efforts versus full cost methods Taxes A few problems with earnings Valuation methodologies: NAV versus multiples

Sample NAV for Forest Oil FOR MORE INFORMATION INDEX

BNP Paribas_E&P Primer

Documents

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crude oil

production of oil

liquids oil

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