UPSTREAM OIL & GAS ECONOMICS & FISCAL INTELLIGENCE · p UPSTREAM OIL & GAS ECONOMICS & FISCAL INTELLIGENCE Part I: Service Description, Analysis Methodology, Definitions, Key Assumptions

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UPSTREAM OIL & GAS ECONOMICS & FISCAL INTELLIGENCE

Part I: Service Description, Analysis Methodology, Definitions, Key Assumptions

North America Oil & Gas Economics & Fiscal Intelligence Service – Part I: Description, Methodology, & Definitions 2014

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North America Upstream Economics & Fiscal Intelligence Service

Description, Methodology, Definitions, & Key Assumptions

1. Description of the Service

Oil and gas producers understand very well the costs of developing and producing oil

and gas deposits. This is certainly true for activities that are associated with costs such

as drilling and completing wells, constructing related well site facilities, building

pipelines, etc. Producers are well acquainted with the prices charged by drilling rig

companies, seismic acquisition and processing firms, and all of the myriad of other

goods and services required to produce oil & gas and deliver it to market. There is

however one important category of costs that is less understood. This is the fiscal cost

of doing business – the cost to producers from taxes and other fiscal levies applied by

governments.

The fiscal costs of doing business is important, and while producers are certainly well

aware of these costs, these levies are often less understood than the other costs. This is

interesting because fiscal costs tend to be particularly worrisome for producers.

Similarly, resource owners, particularly governments, have limited means to gain a full

understanding of oil and gas costs and thus of production economics. Resource owners

are typically not involved and the day-to-day working of the oil and gas business. This

often translates into a reduced ability to fully understand the full range of economic

impacts that can be caused by the fiscal terms, which in turn, results in terms that are

either too tough, too lax, or just poorly designed. The situation for governments is also

complicated by the need for policy trade-offs that seek to balance revenue benefits

from fiscal sources such as taxes and royalties with benefits from industry activity and

jobs creation.

Experience with fiscal systems around the World shows that some systems work better

than others in balancing a variety of legitimate policy goals. It is a misconception that

more for the resource owner necessarily means less for the investor. Improved fiscal


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system design can reduce risk and other costs, offering the opportunity for increased

net economic benefits overall – a win-win outcome for the benefit of both producers

and resource owners.

The share of net revenue (sales revenues after costs) from oil and gas wells in North

America broadly ranges from 65/35 in favor of the producer to 25/75 in favor of the

resource owner. The World average share is in the range of 60%, with the share closer

to 50% for importer jurisdictions and to 75% - 85% for exporter nations.

The resource owner’s share is determined by the jurisdiction’s fiscal system.1

Representing a share of net revenue in the range of 35% - 75%, the fiscal system is one

of the key determinants of project economic viability.

Despite its importance as a key economic driver for the upstream oil & gas sector very

little comparable information is available in the public domain and across jurisdictions.

The North American Fiscal Intelligence Service is intended to help bridge this gap.

The North America Fiscal Intelligence Service (NAEFIS) provides an overview of the

economic attractiveness of new oil and gas wells in North America and assesses the

associated fiscal system impacts. The service provides a source of consistent and

comparable analysis for both investors and governments. Analysis assumptions with

respect to costs, recoverable reserves, and production profiles are based on publically

available company reports and presentations, with adjustments to ensure data

consistency and the incorporation of full cycle costs and risks.2

1 The fiscal system refers to the total of all fiscal levies that apply – any fiscal cost applied by the resource owner,

including that for land acquisition, corporate income tax, property tax, import duties, royalties, etc.… 2 Full cycle costs refers to the incorporation of all costs related to a given project, including land acquisition, up-

front geophysics, and exploration dry holes. Risk is handled through expected value analysis.


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The service (or NAEFIS) consists five report parts covering four broad research areas:

1. Part I – Service Description, Methodology, Definitions, & Key Assumptions;

2. Part II – Fiscal Thumbnail Descriptions & Economics Summaries;

3. Part III – Fiscal Systems Comparison;

4. Part IV – Fiscal Systems Subcomponent Analysis; and,

5. Part V – Play Economics Reports.

Part II - Fiscal Thumbnail Descriptions & Economics Summaries: The fiscal thumbnails

component of this service provides one-page descriptions of the essential fiscal

instruments applicable in each jurisdiction; plus, the associated economics results across

a range of seven oil type-wells and seven gas type-wells. These thumbnails offer a quick

reference into the fiscal costs and structure of each jurisdiction and a glimpse into the

economic strength of potential oil and gas investment opportunities. The type-wells are

based on North American data and provide a representative range of possible costs and

well sizes in terms of EUR (estimated ultimate resource recovery. Table I.1 provides a

list of the fiscal systems currently covered in this service.

Part III - Fiscal Systems Comparison: The fiscal systems comparison report highlights

selected fiscal systems for inter-jurisdiction comparison. In addition to illustrating the

structure and behavior of each fiscal system these comparisons provide a window on

the fiscal costs of doing business in each jurisdiction and on the associated government

and resource owner shares.

Part IV - Fiscal Systems Subcomponent Analysis: Some fiscal systems are particularly

complex, incorporating a combination of formulas and parameters that are not

transparent in terms of the behavior of the government share or the impact on investor

economics over a range of economic conditions. Often a variety of special rates and

conditions apply. The fiscal components analysis selects the more complex systems to

illustrate the relative contribution of each system sub-component.


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Part V - Play Economics Reports: The play economics component provides separate

reports on each resource play. The plays currently included are identified in Table I.2.

Figure I.1 provides a sense of location within the North American context.

Figure I.1


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The seven oil type wells and seven gas type-wells for each play are based on

representative parameters for these plays. Each play-report identifies the key land

holders, and describes the play in terms of (i) location and resource characteristics, (ii)

representative recoverable reserves, costs, and prices, and (iii) economic attractiveness.

The full range of economic decision-making and fiscal health parameters are reported

for each play.

Table I.2


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2. Methodology

The North America Economics & Fiscal Intelligence Service (NAEFIS) is based on publically

available information. Where appropriate, this information is augmented from internal and

otherwise unpublished sources in order to facilitate the full range of economics and fiscal

system tests. For example, published company information typically reports only well

drilling and completion costs, and then often for only the best prospects. While this

represents the largest cost share for onshore operations, full cycle and risk analysis require

the addition of costs for other activities, including geological & geophysical evaluations as

well as well tie-in and other facilities.

Capital Costs: Publically available cost information tends to be obscure at best, and

particularly for operating costs. This of course is understandable, given the associated

commercial sensitivities and competitiveness issues involved. Considering publically

reported capital costs (CapEx) for oil and gas wells therefore requires caution, particularly

on whether the costs are half-cycle or full-cycle.

Half cycle typically includes just the costs for well drilling and completion. Full-cycle costs

would include more, and are typically associated with an entire play. Such additional costs

would include: land acquisition, seismic acquisition and processing, and well tie-in. Full

cycle costs can also include a category for facilities which would include roads, bridges, field

offices, warehouses, central treating facilities and testing facilities. The cost of central

treating and testing facilities can be huge. It basically includes all the cost for building

batteries, plants and sales facilities. For economic purposes this is often taken into account

on a project basis, but it can be divided up and included on a per well basis. There are also

group gathering pipelines and sales pipelines – these would be treated like central facilities.

Processing and treating costs can either be capitalized of leased as an operating expense.

This report incorporates processing into operating costs.

It is also necessary to account for exploration wells. In conventional developments this

reflects dry wells and their associated risks. In unconventional resource developments the

risk of a dry well is much less however these developments rely on fine tuning the drilling


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and fracking technologies to the specific play. This translates into early development costs

that are typically much higher than those for half-cycle development where resource

knowledge and economies of scale translate into improved efficiencies and correspondingly

reduced costs.

Notwithstanding the differences between conventional and unconventional resource

developments, and for simplicity in determining the thumbnail results, the EMV and

corresponding Risk Performance Index calculations are based on the traditional

success/failure model, incorporating a 50:50 chance of oil or gas and a 20% probability of

failure. The individual plays would of course fine tune these parameters; for example,

considering only oil or only gas.

Operating Costs: There are no universal or standard operating cost (OpEx) categories. Each

company employs up its own. Some companies will have many categories, because they

want to track a lot of things. Other companies will lump a bunch of stuff into a small

number of categories and put a lot of stuff in “Other” or Miscellaneous. They might put

“Other” in variable or in fixed. Some might call road maintenance fixed while others might

call it variable. Some of the other things in OpEx include: Labor, taxes, lease rentals, repairs

and maintenance, equipment rental, trucking, utilities, supplies, chemicals, and custom

processing. Things like major overhauls / plant turnarounds (which you do every 3 years or

so), can be included in op cost or capital. Most operators capitalize them if they are done

less frequently than every 2 years. Also, it is often a trade-off to put many OpEx expenses in

OpEx or CapEx. For example, a piece of equipment can be rented (OpEx) or purchased

(CapEx). Oil Hauling - wells not tied into central treating facilities require their production

to be trucked. Operators will also often use a “Other” category for anything that does not

have a category; e.g., everything from weed control, to spill clean ups, consultant visits,

corrosion monitoring, painting, rags, and on and on.

Treatment of Taxes & other Fiscal Elements: In addition to distinguishing between risked vs.

un-risked analysis and between full-cycle vs. half-cycle costs, it is important to take caution

to avoid double counting. Three common areas that typically run the risk of cost double


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counting are bonuses (land acquisition), rentals & fees, and property taxes. Bonuses are

considered as CapEx while rental & fees, and property tax are often included in OpEx. It is

necessary to exclude these cost items from the technical costs and instead to include them

in the analysis as fiscal components, as they are a direct result of the application of the fiscal

and tenure terms.

The type-wells used for the summary results associated with each thumbnail description,

with the fiscal sub-component analysis, and with the fiscal systems comparison analysis are

selected to represent a range of possible cost outcomes. These estimates produce a range

of unit costs that decline as EUR increases. This represents the standard analysis approach

and the general relationship from experience, however all combinations are possible. For

oil wells the cost range is $52.05 – $14.76 per barrel and for gas wells 5.13 - $2.43 per Mcf.

Both ranges including $5.00 per barrel oil transportation costs and $1.00/Mcf gas

transportation and processing costs. While these costs reflect the type-wells we follow a

somewhat different approach for oil sands and for comparison set 6 in Part III. In these

cases we switch from analysis by well to that by field. For the oil sand field we use

representative oil sands costs, prices, etc. Similarly, for comparison set 6 we assess a

shallow water offshore project. This represents in turn a highly capital intensive long-lead

time project for which the fiscal systems in comparison set 6 we designed to accommodate.

To add important insight, sensitivity analysis is included to also demonstrate the

incremental economic results with, for example, costs held constant, and similarly with well

and field EUR, commodity price, and operating costs held constant.

For the play/well economics analysis, well costs are held constant across the type-wells.

Here the focus is on well EUR, and liquids content in the case of the gas wells. Sensitivity

analysis provides insight into the impacts of changes in key parameters – CapEX, OpEx,

prices, and per-well recoverable reserves.


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3. Definitions

This section provides definitions of the decision-making criteria and related concepts used

to both measure economic attractiveness and judge fiscal system health.

Constant Dollars: refers to Nominal Dollar values with escalation removed. Also see Nominal Dollars and Real Dollars. Costs: Costs are defined as “technical costs”, in order to exclude costs attributed to the fiscal system. Fiscal costs are included as payments to governments/resource owners. See Fiscal Costs below and Section 2 - Methodology. Cost Savings Index (CSI): the per-dollar share of cost saving retained by the investor. See Price Retention Index. Discount Rate: the rate of return that represents the investor’s expected return from comparable alternative investments, more specifically, from the next-best alternative investment. The rate incorporates three components – inflation, opportunity cost, and time-related risk. It is common practice in the upstream oil & gas sector to use a real-dollar discount rate of 10%. Economic Rent: the concept on which resource owner share is based. It is defined operationally as Operating Income, itself defined as project revenue less CapEx and OpEx. See the definition of Net Cash Flow. While there are some technically details in the conceptual definition; for example, the treatment of taxes as costs and not rent, operating income, also called divisible income, represents the after-cost, value available for sharing between producers and resource owners. Escalation: refers to an increase in prices and costs, including that for inflation. Escalation is typically sector or project specific. There can also be cost and price decreases – de-escalation. Also see Inflation. Expected Monetary Value (EMV): the Net Present Value from a successful project weighted by the probability of success, less the NPV from an unsuccessful project weighted by the probability of failure. Fiscal Cost Index: The real-dollar resource owner share expressed on a per-unit basis (resource owner revenue divided by production). Front-End Loading Share (FeLS): the resource owner share before payout. Front-End Loading Risk Share (FeLRS): the resource owner share before production start. Fiscal Risk Index (FRI): The discounted resource owner share less the undiscounted share – typically GT10% less GT0%. See Government Share.


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Government Share: the share of operating income to resource owners from all fiscal levies, including bonuses, royalties, property taxes, and corporate income tax. Government share is also referred to a resource owner share. Government share is most commonly referred to a Government Take, with the label GT0% to signify undiscounted real dollar values. Inflation: refers to a general and sustained increase in prices and costs. There can also be cost and price decreases – deflation. Maximum Sustainable Risk (MSR): used to determine the Maximum Probability of Failure (MPF) - the maximum probability of failure that a project can withstand before the EMV becomes negative. MSR = 1 + [NPVS / Absolute Value of the NPVF]:

Where: NPVS = NPV for the success case; and, NPVF = NPV for the failure case; Related components are: MPS = Maximum Probability of Success = 1 / MSR MPF = 100% - MPS

Net Cash Flow: Revenue less Costs – typically expressed as:

NCF = GR – TC = NBR – CapEx – OpEx = OprInc – FC – Gov Where: GR = Gross Revenue TC = Transportation Costs NBR = Netback revenue CapEx = Capital Costs OpEx = Operating Costs OprInc = Operating Income FC = Financing Costs Gov = Payments to Resource Owners

Net Present Value: discounted NCF. The equation is: NCFt / [(1 + dr)t ]

Where: t = the number of time periods dr = the discount rate

Nominal Dollars: refers to costs and revenues with escalation included. Also see Real Dollars and Constant Dollars. Opportunity Cost: the cost of forgoing the next-best investment opportunity. By convention, opportunity cost is reflected in the discount rate. Payout: the time (usually expressed in years) from production stare to cost recovery. The equation is: PEET: the acronym used to refer to the cash flow model – Petroleum Economics Evaluation Tool.


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Price Retention Index (PRI): the per-dollar share of a increase in price that is retained by the investor. See Cost Savings Index. Profit to Investment Ratio (PIR): discounted NCF / discounted CapEx. This ratio is also expressed in terms of risk with the CapEX including only those costs before production start (Risk CapEx) or in terms of only the Exploration Costs (Exploration Risk CapEx). Progressivity: Progressivity is contrasted with Regressivity. It refers to the change in government share for a given change in price, volume, or costs. Fiscal systems are characterized as price progressive or volume progressive if the government share increases when price or volume increase. For costs the system is progressive if government share increases as costs decrease. Also see Regressivity. There is no firm rule to determine the degree of progressivity or regressivity. Operationally a range of change can distinguish between neutral and progressive or regressive, with the degree of progressivity or regressivity being characterized as low, medium, high, or Extreme based on international experience. The formulas are constructed so that a positive change signifies progressive while negative change signifies regressive. The scales employed in PEET are:

A neutral progressivity outcome would be produced for example by a fiscal system that includes only corporate income tax and where all costs could be expensed immediately from the date incurred. Systems with front-end levies such as fixed ad valorem royalties and particularly signature bonuses, are typically regressive. Most USA fiscal systems are regressive. Progressive systems typically tie the fiscal share to project profitability. Progressivity/Regressivity is considered for four situations: (i) across type-well/field EUR, and for (ii) price changes only, (iii) volume changes only, and (iv) cost changes only. While the degree of progressivity is an important consideration in fiscal system design, care should be exercised with this indicator as it depends only on Government Share and therefore is greatly influenced by project viability and by the level of operating income for the cases used in its calculation. Rate of Return: Rate of Return (ROR) refers to the rate of return on total capital invested. It is more technically the Internal Rate of Return (IROR), signifying that it is specific (internal) to the project cash flow and that it is equivalent to the discount rate that will result in a


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project net present value of exactly zero. IROR should not be confused with accounting rate of return which is based on depreciated costs (not cash costs) and is more appropriately applied to the entire firm and for a specified time period (typically one year), rather than to the full cash flow for a given project. Real Dollars: refers to economic values (revenues and costs) with any inflation component removed. Also see Nominal Dollars and Constant Dollars. Regressivity: Fiscal systems are characterized as price regressive or volume regressive if the government share decreases when price or volume increase. For costs the system is regressive if government share decreases as costs decrease. Also see Progressivity. Risk Performance Index (RPI): RPI is calculated as EMV / the Standard Deviation. It measure the degree of variation in the EMV. Time Value of Money: refers to the preference to receive money earlier rather than later or to pay costs later. TMV involves consideration of inflation, opportunity cost, and risk. Unit Technical Cost (UTC): UTC refers to the discounted per-unit cost. This measure extends the simple per-unit cost measure to also incorporate opportunity cost and time-related risk.


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4. Key Assumptions

This section details the various assumptions on which analysis is based. Available with the

purchase of either NAEFIS service option, it provides the cost, prices, EURs (recoverable

reserves), production profiles, and other key assumptions and related parameters that form

the basis of the economics component of this service, including:

Recoverable Reserves;

Production Profiles, including Gas Composition and Liquids Yields;

Prices (Market Prices, Quality Adjustments, and Transportation Costs);

Capital Costs (by major cost category);

Operating Costs; and,

Economics Parameters,

(inflation and escalation rates, discount rates, probabilities).

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UPSTREAM OIL & GAS ECONOMICS & FISCAL INTELLIGENCE · p UPSTREAM OIL & GAS ECONOMICS & FISCAL INTELLIGENCE Part I: Service Description, Analysis Methodology, Definitions, Key Assumptions