EX-15 16 exhibit15aiii.htm EXHIBIT 15(A)(III) REPORT OF DEGOLYER AND MCNAUGHTON
.
- Equinor, Annual Report on Form 20-F 2021
1
February 15, 2022
Equinor ASA
Forusbeen 50
N-4035 Stavanger
Norway
Ladies and Gentlemen:
Pursuant to your request, this report of third party
presents an independent evaluation,
as of December 31, 2021, of the estimated
net proved oil, condensate, liquefied petroleum gas
(LPG), and sales gas reserves of certain properties
(Table
1) in which Equinor ASA
(Equinor) has represented it holds an interest.
This evaluation was completed on February 15,
2022. Equinor has represented that these
properties account for 100 percent,
on a net equivalent barrel basis,
of Equinor’s net proved reserves as of
December 31, 2021, and that
Equinor’s estimates of net proved reserves
have been prepared in accordance with the
reserves definitions of Rules 4–10(a)
(1)–(32) of Regulation S–X of the United States Securities
and Exchange Commission (SEC). It is our
opinion that the procedures and
methodologies employed by Equinor for the preparation
of its proved reserves estimates as of December
31, 2021, comply with the current
requirements of the SEC. We have reviewed information
provided to us by Equinor that it represents to
be Equinor’s estimates of the net
reserves, as of December 31, 2021,
for the same properties as those which we
have independently evaluated.
This report was prepared in
accordance with guidelines specified in Item 1202
(a)(8) of Regulation S–K and is to be
used for inclusion in certain SEC filings by Equinor.
Reserves estimated herein are expressed as net
reserves as represented by Equinor and as
estimated by DeGolyer and
MacNaughton.
Gross reserves are defined as the total estimated
petroleum remaining to be produced from these properties
after December
31, 2021. Net reserves are defined as that portion
of the gross reserves attributable to the interests
held by Equinor after deducting all
interests held by others.
Estimates of reserves should be regarded
only as estimates that may change as further production
history and additional
information become available. Not only are such estimates
based on that information which is currently available,
but such estimates are also
subject to the uncertainties inherent in the application
of judgmental factors in interpreting such information.
Information used in the preparation of this report
was obtained from Equinor. In the preparation of this report
we have relied, without
independent verification, upon information furnished by Equinor
with respect to the property interests being
evaluated, production from such
properties, current costs of operation and development,
current prices for production, agreements relating
to current and future operations and
sale of production, and various other information
and data that were accepted as represented.
A field examination was not considered
necessary for the purposes of this report.
Definition of Reserves
Petroleum reserves estimated by Equinor and by
us included in this report are classified as proved.
Only proved reserves have been
evaluated for this report. Reserves classifications
used by Equinor and by us in this report are
in accordance with the reserves definitions
of
Rules 4–10(a) (1)–(32) of Regulation S–X of the
SEC. Reserves are judged to be economically
producible in future years from known
reservoirs under existing economic and operating
conditions and assuming continuation of current regulatory
practices using known
production methods and equipment. In the analyses of production-decline
curves, reserves were estimated only to the
limit of economic rates
2
Equinor, Annual Report on Form 20-F 2021
of production under existing economic and operating
conditions using prices and costs consistent with
the effective date of this report,
including consideration of changes in existing prices
provided only by contractual arrangements
but not including escalations based upon
future conditions. The petroleum reserves are classified as
follows:
Proved oil and gas reserves
– Proved oil and gas reserves are those
quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from
a
given date forward, from known reservoirs, and
under existing economic conditions, operating
methods, and government
regulations—prior to the time at which contracts providing
the right to operate expire, unless evidence indicates
that
renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used
for the estimation.
The project to extract the hydrocarbons must
have commenced or the operator must be
reasonably certain that it will
commence the project within a reasonable time.
(i) The area of the reservoir considered
as proved includes:
(A) The area identified by drilling and limited
by fluid contacts, if any, and (B) Adjacent undrilled portions of the
reservoir that can, with reasonable certainty, be judged to be continuous with
it and to contain economically
producible oil or gas on the basis of available
geoscience and engineering data.
(ii) In the absence of data on fluid contacts,
proved quantities in a reservoir are limited by
the lowest known
hydrocarbons (LKH) as seen in a well penetration unless
geoscience, engineering, or performance data
and
reliable technology establishes a lower contact with
reasonable certainty.
(iii) Where direct observation from well penetrations
has defined a highest known oil (HKO) elevation
and the
potential exists for an associated gas cap, proved
oil reserves may be assigned in the structurally
higher
portions of the reservoir only if geoscience, engineering,
or performance data and reliable technology
establish
the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically
through application of improved recovery techniques
(including, but not limited to, fluid injection) are
included in the proved classification when:
(A) Successful testing by a pilot project in an
area of the reservoir with properties no more
favorable than in the
reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable
certainty of the engineering analysis on which
the project or program was based; and (B) The
project has been approved for development
by all necessary
parties and entities, including governmental entities.
(v) Existing economic conditions include prices and
costs at which economic producibility from a reservoir
is to
be determined. The price shall be the average price
during the 12-month period prior to the ending
date of the
period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices
are defined by contractual arrangements, excluding
escalations based upon future conditions.
Developed oil and gas reserves
– Developed oil and gas reserves are reserves
of any category that can be expected
to
be recovered:
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- Equinor, Annual Report on Form 20-F 2021
3
(i) Through existing wells with existing equipment
and operating methods or in which the
cost of the required
equipment is relatively minor compared to the
cost of a new well; and
(ii) Through installed extraction equipment and
infrastructure operational at the time of the reserves
estimate if
the extraction is by means not involving a
well.
Undeveloped oil and gas reserves –
Undeveloped oil and gas reserves are reserves
of any category that are expected to
be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major
expenditure is required
for recompletion.
(i) Reserves on undrilled acreage shall be limited
to those directly offsetting development spacing areas
that are
reasonably certain of production when drilled, unless
evidence using reliable technology exists
that establishes
reasonable certainty of economic producibility at greater
distances.
(ii) Undrilled locations can be classified as having
undeveloped reserves only if a development
plan has been
adopted indicating that they are scheduled to be drilled
within five years, unless the specific circumstances
justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped
reserves be attributable to any acreage for
which
an application of fluid injection or other improved
recovery technique is contemplated, unless such
techniques
have been proved effective by actual projects in
the same reservoir or an analogous reservoir, as defined in
[section 210.4–10 (a) Definitions],
or by other evidence using reliable technology establishing
reasonable
certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use
of appropriate geologic, petroleum engineering,
and evaluation principles and
techniques that are in accordance with the reserves
definitions of Rules 4–10(a) (1)–(32) of Regulation
S–X of the SEC and with practices
generally recognized by the petroleum industry as
presented in the publication of the Society of
Petroleum Engineers entitled “Standards
Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information (revised June 2019)
Approved by the SPE Board on 25 June
2019” and in Monograph 3 and Monograph
4 published by the Society of Petroleum Evaluation
Engineers. The method or combination of
methods used in the analysis of each reservoir was
tempered by experience with similar reservoirs, stage
of development, quality and
completeness of basic data, and production history.
Based on the current stage of field development,
production performance, the development plans provided
by Equinor, and
analyses of areas offsetting existing wells with test
or production data, reserves were classified as
proved. The proved undeveloped reserves
estimates were based on opportunities identified
in the plan of development provided by Equinor.
Equinor has represented that its senior
management is committed to the development plan
provided by Equinor and that Equinor
has the financial capability to execute the development
plan, including the drilling and completion of
wells and the installation of equipment and
facilities.
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Equinor, Annual Report on Form 20-F 2021
When applicable, the volumetric method was used
to estimate the original oil in place (OOIP) and
original gas in place (OGIP).
Structure maps were prepared to delineate each
reservoir, and isopach maps were constructed to estimate reservoir volume.
Electrical logs,
radioactivity logs, and other available data were
used to prepare these maps as well as
to estimate representative values for porosity and
water saturation. When adequate data were available
and when circumstances justified, material-balance
and other engineering methods
were used to estimate OOIP and OGIP.
For those fields where the volumetric method was
applied, estimates of ultimate recovery were
obtained after applying recovery
factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy
inherent in the reservoirs, analyses of
the petroleum, the structural positions of the reservoirs,
and the production histories.
When applicable, material-balance and other engineering
methods were used to estimate recovery factors
based on an analysis of reservoir pressure and
reservoir fluid properties.
For depletion-type reservoirs or those whose performance
disclosed a reliable decline in producing-rate
trends or other diagnostic
characteristics, reserves were estimated by the application
of appropriate decline-curve or other performance
relationships. In the analyses of
production decline curves, reserves were estimated
only to the limits of economic production as defined
under the Definition of Reserves
heading of this report or to the limit of production
licenses as appropriate.
For the evaluation of unconventional reservoirs,
a performance-based methodology integrating the appropriate
geology and
petroleum engineering data was utilized for this report.
Performance-based methodology primarily includes
(1) production diagnostics, (2)
decline-curve analysis, and (3) model-based analysis
(if necessary, based on availability of data). Production diagnostics include
data quality
control, identification of flow regimes, and characteristic
well performance behavior. These analyses were performed for all well
groupings (or
type-curve areas).
Characteristic rate-decline profiles from diagnostic
interpretation were translated to modified hyperbolic
rate profiles, including one or
multiple b-exponent values followed by an exponential
decline. Based on the availability of data,
model-based analysis may be integrated to
evaluate long-term decline behavior, the effect of dynamic reservoir and fracture
parameters on well performance, and complex
situations
sourced by the nature of unconventional reservoirs.
In certain cases, reserves were estimated by incorporating
elements of analogy with similar wells or reservoirs
for which more
complete data were available.
Data provided by Equinor from wells drilled through October
31, 2021, and made available for this evaluation
were used to prepare
the reserves estimates herein. These reserves estimates
were based on consideration of monthly production
data available for certain
properties only through October 2021.
Estimated cumulative production, as of December
31, 2021, was deducted from the estimated gross
ultimate recovery to estimate gross reserves.
This required that production be estimated
for up to 2 months.
Oil and condensate reserves estimated herein are
those to be recovered by normal field separation. LPG
reserves estimated herein
consist primarily of propane and butane fractions and
are the result of low-temperature plant processing.
Oil, condensate, and LPG reserves
included in this report are expressed in millions of
barrels (10
6
bbl). In these estimates, 1 barrel equals 42
United States gallons.
Gas quantities estimated herein are expressed
as sales gas. Sales gas is defined as
the total gas to be produced from the
reservoirs after reduction for shrinkage from field or platform
handling, separation, processing (including liquid removal),
fuel usage, flaring,
reinjection, pipeline losses, and onshore processing
measured at the point of delivery. Gas reserves estimated herein are
reported as sales
.
- Equinor, Annual Report on Form 20-F 2021
5
gas. Gas quantities are expressed at a temperature
base of 15.6 degrees Celsius (°C) and at
a pressure base of 14.696 pounds per
square
inch absolute (psia). Gas quantities included in
this report are expressed in billions of
cubic feet (10
9
ft
3
).
Gas quantities are identified by the type of reservoir
from which the gas will be produced. Nonassociated
gas is gas at initial
reservoir conditions with no oil present in the reservoir. Associated gas includes
both gas-cap gas and solution gas. Gas-cap
gas is gas at
initial reservoir conditions and is in communication
with an underlying oil zone. Solution gas is gas
dissolved in oil at initial reservoir conditions.
The gas quantities estimated herein consist of both
associated and nonassociated gas reserves.
At the request of Equinor, sales gas reserves estimated herein were
converted to oil equivalent using an energy equivalent
factor of
5,612.1 cubic feet of gas per 1 barrel of oil equivalent.
Primary Economic Assumptions
This report has been prepared using initial prices,
expenses, and costs provided by Equinor in United
States dollars (U.S.$). Future
prices were estimated using guidelines established by
the SEC and the Financial Accounting Standards Board
(FASB). The following
economic assumptions were used for estimating the reserves
reported herein:
Oil, Condensate,
and LPG Prices
Equinor has represented that the oil, condensate,
and LPG prices were based on a reference
price,
calculated
as the unweighted arithmetic average of the first-day-of-the-month
price for each month within the 12-month
period prior to the end of the reporting period,
unless prices are defined by contractual agreements.
Equinor
supplied differentials by field to a Brent oil reference
price of U.S.$69.22 per barrel and the prices
were held
constant thereafter. The volume-weighted average prices
attributable to the estimated proved reserves over the
lives of the properties were U.S.$67.61 per barrel
of oil, U.S.$65.02 per barrel of condensate, and
U.S.$47.17
per barrel of LPG.
Gas Prices
Equinor has also represented that the gas prices
were based on a reference price, calculated
as the
unweighted arithmetic average of the first-day-of-the-month
price for each month within the 12-month period
prior to the end of the reporting period, unless
prices are defined by contractual agreements. A significant
quantity of the gas sold by Equinor is subject
to contract prices, and the range of such prices
is varied. Where
appropriate, Equinor supplied differentials by field to a United
Kingdom National Balancing Point Index
reference price of U.S.$14.01 per million Btu and
the prices were held constant thereafter. The volume-
weighted average price attributable to the estimated proved
reserves over the lives of the properties was
U.S.$11.89 per million Btu of gas.
Operating Expenses,
Capital Costs,
and Abandonment Costs
Historical and budgeted operating expenses,
capital costs, and abandonment costs, provided by
Equinor, were
used in estimating future costs required to operate
the properties. In certain cases, future expenditures,
either
higher or lower than existing expenditures,
may have been used because of anticipated
changes in operating
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Equinor, Annual Report on Form 20-F 2021
conditions,
but no general escalation that might result
from inflation was applied. Abandonment costs are those
costs associated with the removal of equipment, plugging
of wells, and reclamation and restoration associated
with the abandonment.
The abandonment costs were not escalated for
inflation and are inclusive of costs
incurred for existing wells and facilities as well
as those for future development associated with
the proved
reserves estimated herein.
Operating expenses, capital costs, and abandonment
costs were considered in determining the economic
viability of the undeveloped reserves estimated herein.
In our opinion, the information relating to estimated
proved reserves of oil, condensate, LPG,
and sales gas contained in this report
has been prepared in accordance with Paragraphs
932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9
of the Accounting
Standards Update 932-235-50,
Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve
Estimation and Disclosures
(January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation
S–X and Rules 302(b), 1201, 1202(a)
(1), (2), (3), (4), (8), and 1203(a)
of Regulation S–K of the SEC; provided, however, that estimates of
proved developed and proved undeveloped reserves
are not presented at
the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations
of an accounting or legal nature, we,
as engineers, are necessarily unable to express an
opinion as to whether the above-described information
is in accordance therewith or
sufficient therefor.
.
- Equinor, Annual Report on Form 20-F 2021
7
Summary of Conclusions
Equinor has represented that its estimated net proved
reserves attributable to the evaluated properties
were based on the definition
of proved reserves of the SEC. Equinor has represented
that its estimates of the net proved reserves,
as of December 31, 2021, attributable to
these properties, which represent 100 percent of
Equinor’s reserves on a net equivalent
basis, are summarized as follows, expressed in
millions of barrels (10
6
bbl), billions of cubic feet (10
9
ft
3
), and millions of barrels of oil equivalent
(10
6
boe):
Estimated by Equinor
Net Proved Reserves as of December 31, 2021
Oil
(10
6
bbl)
Condensate
(10
6
bbl)
LPG
(10
6
bbl)
Sales
Gas
(10
9
ft
3
)
Oil
Equivalent
(10
6
boe)
Properties Evaluated by
DeGolyer and MacNaughton
Total Proved
2,311.1
43.6
260.7
15,380.7
5,356.0
Note: Sales gas reserves estimated herein were
converted to oil equivalent using an energy
equivalent factor of
5,612.1 cubic feet of gas per 1 barrel of oil equivalent.
DeGolyer and MacNaughton’s independent estimates of Equinor’s
net proved reserves,
as of December 31, 2021, attributable to the
evaluated properties were based on the definition
of proved reserves of the SEC and are summarized
as follows, expressed in millions of
barrels (10
6
bbl), billions of cubic feet (10
9
ft
3
), and millions of barrels of oil equivalent
(10
6
boe):
Estimated by DeGolyer and MacNaughton
Net Proved Reserves as of December 31, 2021
Oil
(10
6
bbl)
Condensate
(10
6
bbl)
LPG
(10
6
bbl)
Sales
Gas
(10
9
ft
3
)
Oil
Equivalent
(10
6
boe)
Properties Evaluated by
DeGolyer and MacNaughton
Total Proved
2,353.0
98.2
283.2
15,448.7
5,487.2
Note: Sales gas reserves estimated herein were
converted to oil equivalent using an energy equivalent
factor of
5,612.1 cubic feet of gas per 1 barrel of oil equivalent.
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Equinor, Annual Report on Form 20-F 2021
In comparing the detailed net proved reserves estimates
prepared by DeGolyer and MacNaughton
and by Equinor, differences have
been found, both positive and negative, resulting
in an aggregate difference of 2.4 percent when compared
on the basis of net equivalent
barrels. It is DeGolyer and MacNaughton’s opinion that the net
proved reserves estimates prepared by Equinor
on the properties evaluated
and referred to above, when compared on the basis
of net equivalent barrels, in aggregate, do not
differ materially from those prepared by
DeGolyer and MacNaughton.
While the oil and gas industry may be subject
to regulatory changes from time to time that
could affect an industry participant’s
ability to recover its reserves, we are not aware
of any such governmental actions which would
restrict the recovery of the December 31,
2021,
estimated reserves.
DeGolyer and MacNaughton is an independent petroleum
engineering consulting firm that has been providing
petroleum consulting
services throughout the world since 1936. DeGolyer
and MacNaughton does not have any financial
interest, including stock ownership, in
Equinor. Our fees were not contingent on the results of our evaluation.
This letter report has been prepared at the
request of Equinor.
DeGolyer and MacNaughton has used all assumptions, data,
procedures, and methods that it considers necessary
and appropriate to prepare
this report.
Submitted,
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
.
- Equinor, Annual Report on Form 20-F 2021
9
CERTIFICATE of QUALIFICATION
I, Regnald A. Boles, Petroleum Engineer with DeGolyer
and MacNaughton, 5001 Spring Valley Road,
Suite 800 East, Dallas, Texas,
75244 U.S.A., hereby certify:
1.
That I am a Senior Vice President with DeGolyer and MacNaughton,
which firm did prepare the report of third party addressed
to
Equinor dated February 15, 2022, and that I, as
Senior Vice President, was responsible for the preparation
of this report of third
party.
2.
That I attended Texas A&M
University,
and that I graduated with a Bachelor of Science
degree in Petroleum Engineering in the year
1983; that I am a Registered Professional Engineer
in the State of Texas; that I am a member of the Society of Petroleum
Engineers; that I am a member of the European
Association of Geoscientists and Engineers; and
that I have in excess of 38 years
of experience in oil and gas reservoir studies
and evaluations.
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Equinor, Annual Report on Form 20-F 2021
TABLE 1
Country
Field
Algeria
In Amenas
In Salah
Angola
Acacia
Cravo
Dalia
Girassol
Kizomba A
Kizomba B
Lirio
Marte
Mondo
Orquidea-Violeta
Perpetua-Hortensia
Plutao
Rosa
Saturno
SaxiBatuque
Venus
Zinia
Argentina
Bandurria Sur
Azerbaijan
Azeri-Chirag-Gunashli
Azeri-Chirag-Gunashli-ACE
Brazil
Bacalhau Concession
Bacalhau PSC
Peregrino
Roncador
Canada
Hebron
Hibernia
Hibernia Southern Extension
Republic of Ireland
Corrib
Libya
Murzuq
Nigeria
Agbami
.
- Equinor, Annual Report on Form 20-F 2021
11
TABLE 1
–
(Continued)
Country
Field
Norway
Aasta Hansteen
Aerfugl
Alve
Asgard
Bauge
Breidablikk
Byrding
Ekofisk
Eldfisk
Embla
Enoch
Fram
Fram H-North
Gimle
Gina Krog
Goliat
Grane
Grasel
Gudrun
Gullfaks Area
Gungne
Hanz
Heidrun
Hyme
Ivar Aasen
Johan Castberg
Johan Sverdrup
Johan Sverdrup Phase 2
Kristin
Kristin South Phase 1
Kvitebjorn
Martin Linge
Marulk
Mikkel
Morvin
Njord
Norne
Ormen Lange
Oseberg
Oseberg East
Oseberg South
Sigyn
Sindre
Skarv
Skuld
Sleipner East
Sleipner West
Snadd Outer
Snohvit
Snorre
Statfjord
TABLE 1
–
(Continued)
Country
Field
Norway –
(Continued)
12
Equinor, Annual Report on Form 20-F 2021
Statfjord East
Statfjord North
Svalin
Sygna
Tor
Tordis
Trestakk
Troll
Tune
Tyrihans
Urd
Utgard
Valemon
Veslefrikk
Vigdis
Visund
Visund South
Russia
Kharyaga
North Danilovsky
North Komsomolskoye
United Kingdom
Barnacle
Mariner
United States
APB North Non Op
APB Op
APB South Non Op
Big Foot
Caesar-Tonga
Heidelberg
Jack
Julia
St. Malo
Stampede
Tahiti
Titan
Vito