This document provides a framework for valuing oil and gas projects based on reserves classifications from the Petroleum Resources Management System (PRMS). It values projects through a discounted cash flow analysis at the project, company, and industry levels. As an example, it values the proved, probable, and possible reserves of Touchstone Exploration's oil project in Trinidad. The total valuation of Touchstone's Trinidad project reserves and resources is $43.8 million before corporate taxes. Key factors in the valuation include oil price assumptions, production decline rates, capital and operating costs, and risk discount factors applied to less proven reserves categories.

1. Guide to Valuation
and Value Creation:
Oil and Gas Projects
Ashley Mangano
B.Engineering (Hons), B.Commerce, MBA (Oxon), LLM (Candidate)

2. 1 INTRODUCTION
This short guide provides a framework to value oil and gas projects and subsequently discusses the
mechanisms that go on to create value in these projects. While the framework is provided in an oil and gas
context, it is also applicable to mining and the general extractive industries. This guide and accompanying
calculations spreadsheet (available here) uses only information made available in a prospectus or through
continuous disclosure obligations for listed companies. It is a guide only and is not intended to provide
financial or investing advice.
Touchstone Exploration (TSE:TXP), a Canadian based company listed on the Toronto stock exchange, is
used as an example. While the company has projects in Trinidad and Canada, only the Trinidadian project
is considered, using information from the 2014 annual report, denominated in Canadian dollars and
available on the company’s website.
Oil and gas reserves and resources are classified according to the Petroleum Resources Management System
(PRMS) industry code, and accordingly, the framework is based on this. The framework is applicable for
all extractive industries and substitution of PRMS for the mining reserves classification system, the JORC
Code, allows this framework to be applied to mining projects.
This summary provides explanation and context for the valuation framework captured in the accompanying
spreadsheet. The analysis is high-level to suit retail investors: if clarity or additional discussion on any part
of the process is desired, please contact me via LinkedIn. This guide should be read in conjunction with
my previous guide, Guide to Fundraising in the Natural Resources Sector: Company and Investor Perspectives, with
particular reference to:
I. Risks (section 3.4);
II. Business Model (section 3.3);
III. Resource Companies (section 1.2); and,
IV. Rationale for Fundraising (section 1.3).

3. 2 VALUATION
In its entirety, the valuation process in natural resources can be viewed as consisting of three inter-
dependent levels with each requiring different valuation techniques and methodologies. As seen in Figure
1 (below) these are: project, company and industry. If there are multiple projects (as is most commonly the
case), their individual valuations must be aggregated prior to company analysis. Tax implications at a
corporate level often lead to project valuations being completed on a before-tax basis for comparison
purposes.
Industry or Macro-Level
Company-Level
Project-Level
Project 1 Project 2 Project 3
Table 1: Natural resources valuation environments
Project-level valuation is considered in this guide; company level analysis specific to the extractive industries
(oil and gas, mining) will be discussed in a follow-up publication. The basis of project value hinges on the
relationship between project phase (exploration, development, or production)1, PRMS reserves category,
and risk. The general relationship between these items is illustrated in Figure 2. Reserves can be classified
as proved, probable or possible, and hence this framework steps through valuing each classification, with
the final project valuation being an aggregation of all categories.
Figure 1: General relationship between project phase, commodity reserves category, risk and value
1
See Guide to Fundraising in the Natural Resources Sector: Company and Investor Perspectives
100% $21.21
Risk Value
(%) ($/Barrel)
0% $0
Project Phase Production
Probable
Resources
Resources
Proved
Undeveloped
(1P)
Proved
Developed
Producing
(1P)
Geological Risk
Factor
100 - 90%
Non-Geological
Risk Factor
Estimated Total
Discount Factor
(% of Value of One
Produced Unit of
Commodity)
99.5% 10% 5%
PRMS Category
Possible (3P) Probable (2P)
Exploration Development
JORC Category
Resources
90% 50%
Proved
Reserves
Reserves
90 - 50% 50 - 10% 10 - 0%
Variable (see 'Risk' section of fundraising guide)
Inferred Measured

4. Points to note on Figure 2 include:
I. Risk, both geological and non-geological, is at a maximum during initial exploration and reduces
to a minimum at production;
II. Value per barrel is at a minimum (zero) during initial exploration and increases to a maximum at
production;
III. Value is created by reducing geological and non-geological risk, through exploration, development
and production activities, and company activities;
IV. ‘Geological Risk Factor’ is taken directly from PRMS category, the JORC categories are inserted
to provide guidance for mining projects; and,
V. ‘Non-Geological Risk Factor’ includes project, company and industry risks as well as market
sentiment and appetite to invest in oil and gas projects, which varies significantly and is best
quantified with a separate company and industry analysis.

5. 3 PROJECT VALUATION
3.1 OVERVIEW
This framework values oil and gas projects by calculating the maximum value realised per barrel, the pre-
tax marginal profit per barrel, then working backwards through the PRMS categories and applying discount
factors to calculate the value of all company production, reserves and resources. The aggregation of these
values gives the final pre-tax project valuation at that point in time.
The PRMS categories, in decreasing order of value, are:
I. Proved developed producing;
II. Proved undeveloped;
III. Probable;
IV. Possible; and,
V. Resources.
3.2 PROVED DEVELOPED PRODUCING
Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data,
can be estimated with 90% or greater certainty to be commercially recoverable:
I. from a given date forward;
II. from known reservoirs; and,
III. under defined economic conditions, operating methods and government regulations.
Proved Developed Producing reserves are quantities expected to be recovered from existing wells and
facilities. They are expressed as a current daily production volume (barrels of oil per day) and a reserves
volume (barrels of oil) which remain drilled but are yet to flow to surface.
Conceptually, it can be easiest to understand the full valuation process by starting with the value of one
produced barrel of oil that is ready for sale. Figure 3 breaks down the average value flows from one barrel
of oil produced by TXP in 2014 (reference the associated spreadsheet ‘Valuation -PDP’ tab, column C).
I. Realised oil price, including hedging, is the final value one barrel of oil was sold for in 2014 and
averaged $90.46, of which $29.15 flowed to government royalty payments and $27.57 flowed to
expenses attributed to operating the facilities required to produce the oil (also called lifting costs);
II. This results in an operating netback (an industry term used for comparative purposes) of $33.73;
III. Subtracting general and administrative expenses and the Trinidad specific ‘special petroleum tax’
(derived from gross revenues, not a profit tax, which is calculated later) the final pre-tax profit per
barrel to TXP was $21.20;
IV. Note, as this is existing production the final marginal profit per barrel excludes the initial drilling
capital expenditure required to bring the well(s) into production.

6. Figure 3: Value breakdown for one barrel of oil for sale (‘Cost Breakdown Per Barrel’ tab)
This $21.21 profit can be considered the highest valuation of a barrel of oil to the company at the realised
oil price at this point in time, with all other factors remaining constant. All geological and non-geological
risk attached to exploring, developing and producing the oil is reduced to zero as the physical barrel of oil
reaches the sale point and is sold to the buyer. This is the starting point for valuing all other barrels of oil,
and is shown in the top right-hand corner of Figure 2 as the maximum value of a barrel of oil for TXP in
2014.
Valuing the proved developed producing (PDP) reserves is a matter of completing a discounted cash flow
(DCF)2 3 valuation on the remaining reserves with key assumptions being:
I. Discount rate which uses the industry standard of 10% giving valuation consistency for
comparative purposes, whereas the weighted average cost of capital (WACC), which is company
specific, is used at a company analysis level;
II. Oil price which varies and is often forecast using the forward-price curve and sensitivities analysis,
although in this case the realised price less hedging is carried forward;
III. Oil production decline rate which varies according to pressure-drive type specific to each well
and geological setting, with mature wells declining at a lower rate than wells new to production. It
can be up to 40% per year in onshore Trinidad which can also be typical of non-conventional
‘frac’ed’ wells in onshore United States;
IV. Operational expenses which are based on historical financial statements and gives insight into
company performance when compared to other companies operating in the same area;
V. Tax structure which is jurisdiction specific and dependent on capitalized previous expenditures.
2
More information on discounted cash flow analysis: https://www.investopedia.com/university/dcf/
3
Nick Antill, Valuing oil and gas companies: a guide to the assessment and evaluation of assets, performance
and prospects (Woodhead Publishing, 2000) 133.
$21.21
$4.93
$7.59
$27.57
$29.15
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
$100.00
Government
Royalties
Operating
Expenses
General &
Administrative
Expenses
Special Petroleum
Tax
Company Profit,
Before-Tax
Oil Price, Realised: $90.46
$21.21
$4.93
$7.59
$27.57
$29.15
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Government Royalties
Operating Expenses
General & Administrative Expenses
Special Petroleum Tax
Profit
Oil Price Realised: $90.46
Operating Netback: $33.73

7. The final PDP pre-tax valuation is just over $54 million based on reserves of 5,475,000 barrels of oil, giving
an average present value of all future PDP production of $9.90 per barrel. This value is significantly lower
than the 2014 average value of $21.20 per barrel, largely due to the time value of money which requires
discounting to present value PDP reserves physically produced over the next 30 years.
3.3 PROVED UNDEVELOPED
Proved undeveloped reserves (PUD) are quantities of oil that can be recovered through:
I. Future development, requiring capital expenditure for drilling and completion or workover
activities; and,
II. Production.
These reserves are entirely undrilled and remain subsurface, however carry more than 90% geological
certainty of their presence. Valuation again takes the form of a DCF analysis, with the key difference that
this oil needs a well to be drilled (or other production enabling activities) before it can be produced. This
requires a capital expenditure component upfront. It is assumed for this analysis that surface equipment
and facilities can accept the subsequent increase in production, however, this may not necessarily be the
case and in a deeper valuation this capital expenditure would need to be included.
Valuation starts by calculating a ‘type well’, which is the estimated economics for a future well based on
well costs, subsequent production, and associated royalties and expenditures. Type well information may
be available from the company, however it usually in the form of a net present value (NPV) figure for an
exploration well.
The ‘Type Well Economics’ tab includes the information and calculation, noting that based on 2014 drilling
and reserves additions, each new well drilled by TXP had an average cost of just over $2 million, with a net
present value of $856,000 and an internal rate of return of 24%.
The ‘Valuation-PUD’ tab then aggregates these type wells to simulate drilling out the volume of reserves in
the PUD category, 3,441,000 barrels of oil. After inclusion of decommissioning costs, the present value per
barrel of the PUD reserves is calculated at $4.35 per barrel. This is significantly reduced from the $9.90 per
barrel in the producing (PDP) reserves, with the main reason for this being the inclusion of capital
expenditure required to drill the PUD reserves.
As there is now geological and non-geological risk attached to successfully executing drilling and production
activities, a discount factor to account for this risk needs to be included in the valuation. Pages 22 to 25 of
the TXP 2014 annual report go into some detail on these risks.
3.4 PROBABLE RESERVES, POSSIBLE RESERVES AND RESOURCES
Probable reserves carry more overall risk than proved reserves and are allocated a geological risk factor,
according to PRMS, of between 10 to 50%. Similarly, possible reserves carry more risk than probable
reserves and are allocated a geological risk factor of between 50 to 90%, while resources carry more risk
than possible reserves and are allocate a geological risk factor of between 90 to 100%.
The increasing geological and non-geological risk attached to the probable, possible and resources
categories means that the maximum possible value per barrel will be less than the previous category, proved
undeveloped, which was valued at $4.35 per barrel. Conversely, the minimum value attributable will be
zero so the final valuation for each barrel of oil associated with each category will be on a sliding scale
between these two boundaries.
Identifying industry-nuanced non-geological and geological risk and either accounting for or mitigating
these risks forms a large part of valuation and due diligence in the natural resources sector for investing
professionals. This basic framework for retail investors captures risk with aggregate discount factors.

8. These categories do not generally use a discounted cash flow analysis as the accuracy of assumptions behind
the risk discount factor would render the accuracy of going through a DCF analysis meaningless. Instead,
a PRMS category-specific discount factor is applied to the proved undeveloped reserves discounted cash
flow value per barrel.
The final discount factors are determined by multiplying the geological risk factor, according to PRMS, and
the non-geological discount factors together. From Figure 2 we can see the following PRMS categories and
their estimated associated discount factors are as follows:
Figure 2: PRMS category discount factors
For further justification of correct values per barrel, other sources can be referenced. This includes
deriving the multiples used in mergers and acquisitions activity, enterprise value of companies listed on a
stock exchange, and farmout or joint-venture agreements.
3.5 SUMMARY
The final step in the project valuation process is to calculate the value of reserves in each PRMS category
then aggregate all categories valuations to determine the final reserves and resources valuation. From this
reserves and resources valuation, known future expenses need to be deducted, of which the often-
significant items to consider are decommissioning costs and future work obligations. The latter refers to
exploration and development activities included in the company’s petroleum license(s) held with the host
government. As shown in Figure 4 below, the valuation for TXP’s Trinidad project is calculated as
$43,825,651, before corporate tax.
Valuation
Methodology
Geological
Risk
(PRMS)
Non-
Geological
Risk
Final
Discount
Factor
Base Value
Value Per
Barrel
Financial
Analysis
0% 0% Not Used Not Used $ 21.21
Proved
Developed
Producing
Discounted
Cash Flow
5 - 10% 10% Not Used Not Used $ 9.90
Proved
Undeveloped
Discounted
Cash Flow
5 - 10% 20% Not Used Not Used $ 4.35
2P Probable
Per Barrel
Multiple
10 - 50% 50% 0.70 4.35 $ 1.31
3P Possible
Per Barrel
Multiple
50 - 90% 70% 0.95 4.35 $ 0.22
Per Barrel
Multiple
90 - 100% 90% 0.995 4.35 $ 0.02
PRMS Category
Produced
Reserves
1P
Resources
x
x
x
=
=
=

9. Figure 3: Project valuation summary
Oil price is a key assumption in this valuation. To apply context, CA$90.46 (US$70) per barrel was realised
by TXP in 2014 which then dipped to under US$40 per barrel two years later, and at the time of publication
the West Texas Intermediate oil price hovers around the US$60 per barrel. The economics and valuation
will change significantly according to changes in oil price. Two points to note are:
I. When it comes to commodities, the lowest marginal cost producer will be the most oil-price
resilient, so look for industry-leading company performance to mitigate oil price risk;
II. Costs lag oil price, so a reduction in oil price may immediately result in a worsening of project
economics. However, over time service providers will in turn be compressed, resulting in reduced
costs for oil companies and improved project economics4.
The other point to note is that value and valuation is specific to each party, in that there are often strategic
or company-specific reasons why a project may be more valuable to certain parties, significantly changing
the valuation. These valuations can be derived from joint-venture agreements, farm-in agreements, or direct
acquisitions. For retail investors however, the above framework can provide a basis for identifying the
relative strength of certain investments.
4
https://www.eia.gov/todayinenergy/detail.php?id=25592
Certified Volume
(Barrels)
Value Per
Barrel
Value
Not Used $ 21.21 -
Proved
Developed
Producing
5,475,000 $ 9.90 $ 54,202,500
Proved
Undeveloped
3,441,000 $ 4.35 $ 14,953,676
2P Probable 5,824,000 $ 1.31 $ 7,600,320
3P Possible None $ 0.22 -
None $ 0.02 -
$ 76,756,496
$ 13,979,000
$ 18,951,845
$ 43,825,651
Decommissioning Costs:
Future Work Obligations:
Project Valuation (Pre-Tax):
PRMS Category
1P
Reserves
Resources
Produced
Reserves and Resources Valuation:

10. 4 VALUE CREATION
With a framework for valuing oil and gas projects as a basis, the process of creating value in oil and gas
companies, that is, how oil and gas companies create value for shareholders, can be outlined.
There are four ways by which value can be created in oil and gas companies which retail investors should
take into consideration in any investment decision:
4.1 RESERVES INCREASES
This can be achieved through the company’s work program (organic growth through exploration and
development) or through acquisition of new projects (inorganic growth).
The work program describes the exploration, development and production activities aimed at increasing
volumes of oil in reserves or shifting volumes of oil into improved PRMS categories. A drilling campaign
or program may convert possible reserves to probable, and probable reserves to proved and producing.
This work program has an estimated quantifiable value creation, with quantifiable costs and understandable
risks, so an informed investment decision can be made.
For pure exploration, the Expected Value (EV) technique is used to determine the value of certain wells;
noting that exploration wells carry binary risk (in that if a well is unsuccessful, the investment is lost except
for an improved geological understanding of the area). To calculate the EV the following formula is used:
EV of Exploration Well = (Chance of Success x Unrisked Net Present Value) – Exploration Costs5
When new acreage or projects are acquired to increase reserves, the framework described can be used to
assign value, using costs specific to the acquiring company, and if the acquisition price is less than the
company-specific valuation, the transaction is value creating for the acquirer.
On this point, we note TXP completed an acquisition in the 2014 financial year with the following metrics:
I. Acquisition price of $33.965 million;
II. Acquired proved (1P reserves) of 7,520,000 barrels of oil; and,
III. Acquired probable (2P reserves) of 4,177,000 barrels of oil.
Figure 4: TXP 2014 acquisition analysis
4.2 OPERATIONAL IMPROVEMENTS
The main operational improvements are achieved through cost reduction or increased production.
Reviewing TXP 2014 financial statements we see the average operational expense on a per barrel basis was
$27.27, almost a third of the realised oil price.
5
Nick Antill, above n 3, 145.
Certified Volumes
Acquired (Barrels)
Value Per Barrel
(TXP)
Value
1P
Proved
Undeveloped
7,520,000 $ 4.35 $ 32,712,000
2P Probable 4,177,000 $ 1.31 $ 5,450,985
$ 38,162,985
$ 33,695,000
$ 4,467,985
PRMS Category
Before Tax Valuation:
Purchase Price:
Gain, Pre-Tax:
Reserves

11. From personal experience operating similar fields in Trinidad, it may be possible to reduce this cost down
to as low as $10 per barrel. Implementing these cost rationalisation measures could, upon quick analysis in
the attached spreadsheet, increases the pre-tax valuation to more than $80 million, almost doubling the
project valuation. This highlights the importance and value of strong in-country management teams.
Through various production enhancement techniques, it is also possible to improve production rates and
increase revenues. This is a technical field and can significantly improve revenues, noting that these
operational improvements will not increase the ultimate volumes of reserves, only improve the efficiency
of extraction.
4.3 LEVERAGE
Popular in private equity investments, the process of acquiring debt (project finance, reserves-based or
corporate) can significantly improve the valuation of an oil project and company by way of:
I. Tax shield on interest expenses; and,
II. Improved management focus on efficient operations;
Upon quick analysis in the attached spreadsheet, we can see that acquiring $40 million of debt to fund
drilling of the 20 proved undeveloped wells, at an interest rate of 15% and corporate tax rate of 55%,
increases the pre-tax valuation by more than 25%.
4.4 IMPROVED MARKET CONDITIONS
Finance analysts generally use multiples of certain metrics to quickly determine the relative value of oil and
gas companies. The equity market valuation is divided by certain metrics to achieve a valuation multiple for
the current market: usually volume of proved plus probable reserves, EBITDAX (earnings before interest,
tax, depreciation, amortization and exploration costs) and current production or other industry-unspecific
metrics such as earnings or cash-flow.
If the market conditions improve, these multiples improve along with the project and company valuation,
even if all other factors remain constant.
A natural resource sector specific guide to company analysis will be provided. In the meantime, further
information on company analysis and value investing can be found online at
https://www.investopedia.com/university/fundamentalanalysis/ or the following recommended books:
• Vause, Bob, The Economist Guide To Analysing Companies 6th Edition. (Profile Books, 2014)
• Graham, Benjamin, Warren E Buffett and Jason Zweig, The Intelligent Investor: A Book of Practical Counsel.
(Harper Collins, 2013)
For more information on oil and gas company and project valuation the following books are recommended:
• Nick Antill, Valuing oil and gas companies: a guide to the assessment and evaluation of assets, performance and
prospects (Woodhead Publishing, 2000)
• Colombano, Alfonso and Alberto Colombano, Oil & Gas Company Analysis: Upstream, Midstream &
Downstream (2015)
• Wright, Charlotte J and Rebecca A Gallun, Fundamentals of Oil & Gas Accounting (2017)
• Kasriel, Ken and David Wood, Upstream Petroleum Fiscal and Valuation Modeling in Excel: A Worked
Examples Approach (2013)
• Johnston, Daniel, International Exploration Economics, Risk and Contracts Analysis. (PennWell, 2006)