Attached files
file | filename |
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10-K/A - FORM 10-K/A - DEVON ENERGY CORP/DE | d75451e10vkza.htm |
EX-99.1 - EX-99.1 - DEVON ENERGY CORP/DE | d75451exv99w1.htm |
EX-23.3 - EX-23.3 - DEVON ENERGY CORP/DE | d75451exv23w3.htm |
EX-23.2 - EX-23.2 - DEVON ENERGY CORP/DE | d75451exv23w2.htm |
EX-23.4 - EX-23.4 - DEVON ENERGY CORP/DE | d75451exv23w4.htm |
EX-31.1 - EX-31.1 - DEVON ENERGY CORP/DE | d75451exv31w1.htm |
EX-31.2 - EX-31.2 - DEVON ENERGY CORP/DE | d75451exv31w2.htm |
EX-99.3 - EX-99.3 - DEVON ENERGY CORP/DE | d75451exv99w3.htm |
Exhibit 99.2
DEVON ENERGY CORPORATION
OFFSHORE DIVISION
GULF PROPERTIES
Estimated
Future Proved Reserves and Income
Attributable to Certain
Leasehold and Royalty Interests
S. E. C.
Economic Parameters
As of
December 31, 2009
/s/ Fred W. Ziehe | ||||
Fred W. Ziehe, P.E. | ||||
TBPE License No. 63630 Managing Sr. Vice President RYDER SCOTT COMPANY, L.P. TBPE Firm License No. F-1580 [SEAL] |
||||
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
TBPE REGISTERED ENGINEERING FIRM F-1580
|
FAX (713) 651-0849 | |
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5235
|
TELEPHONE (713) 651-9191 |
August 9, 2010
Devon Energy Corporation
20 North Broadway, Suite 1500
Oklahoma City, Oklahoma 73102-8260
20 North Broadway, Suite 1500
Oklahoma City, Oklahoma 73102-8260
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved
reserves, future production, and income attributable to certain leasehold and royalty interests of
Devon Energy Corporation (Devon) as of December 31, 2009. The subject properties are located in
Devons Offshore Division in the state and federal waters of the Gulf of Mexico. The reserves and
income data were estimated based on the definitions and disclosure guidelines contained in the
United States Securities and Exchange Commission Title 17, Code of Federal Regulations,
Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal
Register (SEC regulations). Our third party study, completed on January 18, 2010, and presented
herein, was prepared for public disclosure by Devon in filings made with the SEC in accordance with
the disclosure requirements set forth in the SEC regulations. Based on information
provided by Devon, the total proved reserves summarized in our report represent approximately 3
percent of Devons reported total proved reserves on a barrel equivalent basis for their continuing
operations.
The estimated reserves and future net income amounts presented in this report, as of December
31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation
of this report are based on the average prices during the 12-month period prior to the ending date
of the period covered in this report, determined as unweighted arithmetic averages of the prices in
effect on the first-day-of-the-month for each month within such period, unless prices were defined
by contractual arrangements, as required by the SEC regulations. Actual future prices may
vary significantly from the prices required by SEC regulations; therefore, volumes of reserves
actually recovered and the amounts of income actually received may differ significantly from the
estimated quantities presented in this report. The results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
DEVON ENERGY CORPORATION
OFFSHORE DIVISION GULF PROPERTIES
As of December 31, 2009
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
DEVON ENERGY CORPORATION
OFFSHORE DIVISION GULF PROPERTIES
As of December 31, 2009
Total Proved | ||||
Developed and | ||||
Undeveloped | ||||
Net Remaining Reserves |
||||
Oil/Condensate MBarrels |
32,684.5 | |||
Plant Products MBarrels |
2,342.7 | |||
Gas MMCF |
341,994 | |||
Oil Equivalent MBOE |
92,026.1 | |||
Income Data M$ |
||||
Future Gross Revenue |
$ | 3,421,296 | ||
Deductions |
2,096,330 | |||
Future Net Income (FNI) |
$ | 1,324,966 | ||
Discounted FNI @ 10% |
$ | 966,866 |
1200, 530 8TH AVENUE, S.W.CALGARY, ALBERTA T2P 3S8 TEL (403) 262-2799 |
FAX (403) 262-2790 | |
621 17TH STREET, SUITE 1550DENVER, COLORADO 80293-1501 TEL (303) 623-9147 |
FAX (303) 623-4258 |
Devon Energy Corporation
August 9, 2010
Page 2
August 9, 2010
Page 2
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels. All gas volumes
are reported on an as sold basis expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas reserves are located. The oil
equivalent volumes shown above are calculated assuming a conversion of 6.0 MCF per 1.0 barrel oil
and are expressed as thousands of equivalent barrels (MBOE). In this report, the revenues,
deductions, and income data are expressed as thousands of U.S. dollars (M$).
The estimates of the reserves, future production, and income attributable to properties in
this report were prepared using the economic software package Merak Peep Petroleum Economic
Evaluation and Decline Analysis Software, a copyrighted program of Schlumberger Limited. The
program was used solely at the request of Devon. Ryder Scott has found this program to be
generally acceptable, but notes that certain summaries and calculations may vary due to rounding
and may not exactly match the sum of the properties being summarized. Furthermore, one line
economic summaries may vary slightly from the more detailed cash flow projections of the same
properties, also due to rounding. The rounding differences are not material.
The proved future gross revenue is before the deduction of production taxes. The deductions
are comprised of the normal direct costs of operating the wells, ad valorem taxes, production
taxes, certain transportation costs, recompletion costs, development costs, and certain abandonment
costs net of salvage. The future net income is before the deduction of state and federal income
taxes and general administrative overhead, and has not been adjusted for outstanding loans that may
exist nor does it include any adjustment for cash on hand or undistributed income. Liquid
hydrocarbon reserves account for approximately 60 percent and gas reserves account for the
remaining 40 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10
percent per annum compounded monthly. Future net income was discounted at three other discount
rates which were also compounded monthly. These results are shown in summary form as follows.
Discounted Future Net Income M$ | ||||
As of December 31, 2009 | ||||
Discount Rate | Total | |||
Percent | Proved | |||
5 | $ | 1,125,017 | ||
15 | $ | 840,154 | ||
20 | $ | 737,427 |
The results shown above are presented for your information and should not be construed as
our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities
and Exchange Commissions Regulations Part 210.4-10 (a). An abridged version of the SEC reserves
definitions from 210.4-10(a) entitled Petroleum Reserves Definitions is included as an attachment
to this report.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 3
August 9, 2010
Page 3
The various proved reserve status categories are defined under the attachment entitled
Petroleum Reserves Definitions in this report. The developed proved non-producing reserves
included herein consist of the shut-in and behind pipe categories.
No attempt was made to quantify or otherwise account for any accumulated gas production
imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in
operations as reserves.
Reserves are those estimated remaining quantities of petroleum which are anticipated to be
economically producible, as of a given date, from known accumulations under defined conditions.
All reserve estimates involve an assessment of the uncertainty relating the likelihood that the
actual remaining quantities recovered will be greater or less than the estimated quantities
determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of
reliable geologic and engineering data available at the time of the estimate and the interpretation
of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of
two principal classifications, either proved or unproved. Unproved reserves are less certain to be
recovered than proved reserves and may be further sub-classified as probable and possible reserves
to denote progressively increasing uncertainty in their recoverability. At Devons request, this
report addresses only the proved reserves attributable to the properties evaluated herein.
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. The proved reserves included herein were estimated using
deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty
for proved reserves as a high degree of confidence that the quantities will be recovered.
Proved reserve estimates will generally be revised only as additional geologic or engineering
data become available or as economic conditions change. For proved reserves, the SEC states that
as changes due to increased availability of geoscience (geological, geophysical, and geochemical),
engineering, and economic data are made to the estimated ultimate recovery (EUR) with time,
reasonably certain EUR is much more likely to increase or remain constant than to decrease.
Moreover, estimates of proved reserves may be revised as a result of future operations, effects of
regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved
reserves included in this report are estimates only and should not be construed as being exact
quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could
be more or less than the estimated amounts.
Devons operations may be subject to various levels of governmental controls and regulations.
These controls and regulations may include, but may not be limited to, matters relating to land
tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices,
environmental protection, marketing and pricing policies, royalties, various taxes and levies
including income tax and are subject to change from time to time. Such changes in governmental
regulations and policies may cause volumes of proved reserves actually recovered and amounts of
proved income actually received to differ significantly from the estimated quantities.
The estimates of reserves presented herein were based upon a detailed study of the properties
in which Devon owns an interest; however, we have not made any field examination of the properties.
No consideration was given in this report to potential environmental liabilities that may exist
nor were any costs included for potential liability to restore and clean up damages, if any, caused
by past operating practices.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 4
August 9, 2010
Page 4
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination
results in the estimation of the quantities of recoverable oil and gas and the second determination
results in the estimation of the uncertainty associated with those estimated quantities in
accordance with the definitions set forth by the Securities and Exchange Commissions Regulations
Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves
relies on the use of certain generally accepted analytical procedures. These analytical procedures
fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based
methods and (3) analogy. These methods may be used singularly or in combination by the reserve
evaluator in the process of estimating the quantities of reserves. The reserve evaluator must
select the method or combination of methods which in their professional judgment is most
appropriate given the nature and amount of reliable geoscience and engineering data available at
the time of the estimate, the established or anticipated performance characteristics of the
reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the
subsequent interpretation of this data may indicate a range of possible outcomes in an estimate,
irrespective of the method selected by the evaluator. When a range in the quantity of reserves is
identified, the evaluator must determine the uncertainty associated with the incremental quantities
of the reserves. If the reserve quantities are estimated using the deterministic incremental
approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by
the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve
quantities as proved, probable and/or possible that addresses the inherent uncertainty in the
estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as
reasonable certainty wherein the quantities actually recovered are much more likely than not to be
achieved. The SEC states that probable reserves are those additional reserves that are less
certain to be recovered than proved reserves but which, together with proved reserves, are as
likely as not to be recovered. The SEC states that possible reserves are those additional
reserves that are less certain to be recovered than probable reserves and the total quantities
ultimately recovered from a project have a low probability of exceeding proved plus probable plus
possible reserves. All quantities of reserves within the same reserve category must meet the SEC
definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the
future as additional geoscience or engineering data become available. Furthermore, estimates of
reserves quantities and their associated reserve categories may also be revised due to other
factors such as changes in economic conditions, results of future operations, effects of regulation
by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods,
the volumetric method, analogy, or a combination of methods. Approximately 50 percent of the
proved producing reserves attributable to producing wells and/or reservoirs were estimated by
performance methods. The performance method included, but may not be limited to, decline curve
analysis, which utilized extrapolations of historical monthly and/or daily production data and
pressure data generally available through August 2009 in those cases where such data were
considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by
Devon or obtained from
public data sources and were considered sufficient for the purpose thereof. The remaining 50
percent of the proved producing reserves were estimated by a combination of the performance and
volumetric methods where there were inadequate historical performance data to establish a
definitive trend and where the use of production performance data alone as a basis for the reserve
estimates was considered to be inappropriate.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 5
August 9, 2010
Page 5
All of the proved non-producing and undeveloped reserves included herein were estimated by the
volumetric method, analogy, or a combination of methods. The volumetric analysis utilized
pertinent well and seismic data supplied to Ryder Scott by Devon or which we have obtained from
public data sources that were generally available through November 2009. The data utilized from
the analogues, as well as seismic and well data incorporated into our volumetric analysis were
considered sufficient for the purpose thereof.
It should be noted that the proved reserve volumes described herein consist of primary
recovery, including both pressure depletion and natural water drive mechanisms.
To estimate economically recoverable proved oil and gas reserves and related future net cash
flows, we consider many factors and assumptions including, but not limited to, the use of reservoir
parameters derived from geological, geophysical and engineering data which cannot be measured
directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of
future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves
must be anticipated to be economically producible from a given date forward based on existing
economic conditions including the prices and costs at which economic producibility from a reservoir
is to be determined. While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such production may
increase or decrease from those under existing economic conditions, such changes were, in
accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Devon has informed us that they have furnished us all of the material accounts, records,
geological and engineering data, and reports and other data required for this investigation. In
preparing our forecast of future production and income, we have relied upon data furnished by Devon
with respect to property interests owned, production and well tests from examined wells, normal
direct costs of operating the wells or leases, other costs such as transportation and/or processing
fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after
salvage, product prices based on the SEC regulations, geological structural and isochore maps, well
logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent verification of the data supplied by
Devon. We consider the factual data used in this report appropriate and sufficient for the purpose
of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this
report appropriate for the purpose hereof, and we have used all such methods and procedures that we
consider necessary and appropriate to prepare the estimates of reserves herein. The proved
reserves included herein were determined in conformance with the United States Securities and
Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all
references to Regulation S-X and Regulation S-K, referred to herein collectively as the SEC
Regulations. In our opinion, the proved reserves presented in this report comply with the
definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on
historical performance data. If no production decline trend has been established, future
production rates were held constant, or adjusted for the effects of curtailment where appropriate,
until a decline in ability to produce was anticipated. An estimated rate of decline was then
applied to depletion of the reserves. If
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 6
August 9, 2010
Page 6
a decline trend has been established, this trend was used as the basis for estimating future
production rates.
Test data and other related information were used to estimate the anticipated initial
production rates for those wells or locations that are not currently producing. For reserves not
yet on production, sales were estimated to commence at an anticipated date furnished by Devon.
Wells or locations that are not currently producing may start producing earlier or later than
anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate
production. Such factors may include the availability of rigs, the sequence of drilling,
completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are
not currently producing may be more or less than estimated because of changes including, but not
limited to, reservoir performance, operating conditions related to surface facilities, compression
and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or
allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices
during the 12-month period prior to the ending date of the period covered in this report,
determined as the unweighted arithmetic averages of the prices in effect on the
first-day-of-the-month for each month within such period, unless prices were defined by contractual
arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed
and determinable escalations, exclusive of inflation adjustments, were used until expiration of the
contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic
average as previously described.
Devon furnished us with the above mentioned average prices in effect on December 31, 2009.
These initial SEC hydrocarbon prices were determined using the 12-month average
first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons
are sold. These benchmark prices are prior to the adjustments for differentials as described
herein. The table below summarizes the benchmark prices and price reference used for the
geographic area included in the report. In certain geographic areas, the pricing reference and
benchmark prices may be defined by contractual arrangements.
The product prices which were actually used to determine the future gross revenue for each
property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or
distance from market, referred to herein as differentials. The differentials used in the
preparation of this report were estimated by us based on information supplied by Devon.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for
differentials and referred to herein as the average realized prices. The average realized prices
shown in the table below were determined from the total future gross revenue before production
taxes and the
total net reserves for the geographic area and presented in accordance with SEC disclosure
requirements for the geographic area included in the report.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 7
August 9, 2010
Page 7
Benchmark | Average | |||||||||||||||
Price | Benchmark | Realized | ||||||||||||||
Geographic Area | Product | Reference | Price | Price | ||||||||||||
Offshore Division |
Oil/Cond | WTI Cushing | $61.18/ Bbl | $60.83/ Bbl | ||||||||||||
Gulf Properties |
Gas | Henry Hub | $3.87/ MMBTU | $4.03/ Mcf | ||||||||||||
Ngl | Mt. Belvieu | $28.89/Bbl | $24.06/Bbl |
The effects of derivative instruments designated as price hedges of oil and gas
quantities are not reflected in our individual property evaluations.
Costs
Operating costs for the leases and wells in this report were provided by Devon and include
only those costs directly applicable to the leases or wells. The operating costs include a portion
of general and administrative costs allocated directly to the leases and wells. When applicable for
operated properties, the operating costs include an appropriate level of corporate general
administrative and overhead costs. The operating costs for non-operated properties include the
COPAS overhead costs that are allocated directly to the leases and wells under terms of operating
agreements. The initial operating costs for each property, provided by Devon are based on current
operating costs, but may include adjustments due to ongoing projects in certain fields which might
affect future operating costs. In certain cases, a portion of the operating costs is considered
fixed and remains constant as production declines. The remaining portion is considered
variable and is reduced over time as variables such as production throughput and/or well counts
decline. In addition, certain gathering and transportation fees, as provided by Devon, were
included in this report and shown as Transport Costs. These costs and the related assumptions,
provided by Devon, were accepted without independent verification. No deduction was made for loan
repayments, interest expenses, or exploration and development prepayments that were not charged
directly to the leases or wells.
Development costs were furnished to us by Devon and are based on authorizations for
expenditure for the proposed work or actual costs for similar projects. The estimated net cost of
abandonment after salvage was included for properties where abandonment costs net of salvage, as
provided by Devon, was significant. The estimates of the net abandonment costs furnished by Devon
were accepted without independent verification. Ryder Scott has not performed a detailed study of
the abandonment costs or the salvage value and makes no warranty for Devons estimate.
The proved non-producing and undeveloped reserves in this report have been incorporated herein
in accordance with Devons plans to develop these reserves as of December 31, 2009. The
implementation of Devons development plans as presented to us and incorporated herein is subject
to the approval process adopted by Devons management. As the result of our inquires during the
course of preparing this report, Devon has informed us that the development activities included
herein have been subjected to and received the internal approvals required by Devons management at
the appropriate local, regional and/or corporate level. In addition to the internal approvals as
noted, certain development activities may still be subject to specific partner AFE processes, Joint
Operating Agreement (JOA) requirements or other administrative approvals external to Devon.
Additionally, Devon has assured us that they are not aware of any legal, regulatory, political or
economic obstacles that would significantly alter their plans.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 8
August 9, 2010
Page 8
In certain instances, mainly in the Deep Water District, some proved undeveloped reserves
are scheduled to be drilled beyond five years from the as of date of this report. This is largely
due to the lack of well bore availability in these offshore properties. However, the senior
management of Devon has provided us a letter that states Even though Devon has announced intent to
divest their assets in the offshore Gulf of Mexico, Devon is committed to development of their
non-producing reserves and in the event Devon continues to own the assets when the non-producing
reserves are to be developed, their approved 15-year Long Range Plan contains sufficient capital
funding specifically designated for the development of . . . these reserves . . .
Current costs used by Devon were held constant throughout the life of the properties, except
as noted above.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee
owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We
have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our
firm and the large number of clients for which we provide services, no single client or job
represents a material portion of our annual revenue. We do not serve as officers or directors of
any publicly traded oil and gas company and are separate and independent from the operating and
investment decision-making process of our clients. This allows us to bring the highest level of
independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry related professional societies and organizes an
annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of
our staff have authored or co-authored technical papers on the subject of reserves related topics.
We encourage our staff to maintain and enhance their professional skills by actively participating
in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and
geoscientists have received professional accreditation in the form of a registered or certified
professional engineers license or a registered or certified professional geoscientists license,
or the equivalent thereof, from an appropriate governmental authority or a recognized
self-regulating professional organization.
We are independent petroleum engineers with respect to Devon. Neither we nor any of our
employees have any interest in the subject properties and neither the employment to do this work
nor the compensation is contingent on our estimates of reserves for the properties which were
reviewed.
The results of this study, presented herein, are based on technical analysis conducted by
teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the
undersigned, the technical person primarily responsible for overseeing, reviewing and approving the
evaluation of the reserves information discussed in this report, are included as an attachment to
this letter.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Devon Energy Corporation
August 9, 2010
Page 9
August 9, 2010
Page 9
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in
accordance with the disclosure requirements set forth in the SEC regulations and intended for
public disclosure as an exhibit in filings made with the SEC by Devon.
Devon makes periodic filings on Form 10-K and/or 10-K/A with the SEC under the 1934 Exchange
Act. Furthermore, Devon has certain registration statements filed with the SEC under the 1933
Securities Act into which any subsequently filed Form 10-K and/or 10-K/A is incorporated
by reference. We have consented to the incorporation by reference in the registration statements
on Form S-3 and Form S-8 of Devon of the references to our name as well as to the references to our
third party report for Devon, which appears in the December 31, 2009 annual report on Form 10-K
and/or 10-K/A of Devon. Our written consent for such use is included as a separate exhibit to the
filings made with the SEC by Devon.
We have provided Devon with a digital version of the original signed copy of this report
letter. In the event there are any differences between the digital version included in filings
made by Devon and the original signed report letter, the original signed report letter shall
control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination
by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 |
||||
/s/ Fred W. Ziehe | ||||
Fred W. Ziehe, P.E. | ||||
TBPE License No. 63630 Managing Senior Vice President [SEAL] |
||||
FWZ/sm
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of
geoscientists and engineers from Ryder Scott Company, L.P. Mr. Fred W. Ziehe was the primary
technical person responsible for overseeing the estimate of the reserves, future production and
income presented herein.
Mr. Ziehe, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1976, is a Managing Sr. Vice
President and also serves as an Engineering Group Coordinator responsible for coordinating and
supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies
worldwide. Before joining Ryder Scott, Mr. Ziehe was a Reservoir Engineer with Exxon Company
U.S.A. For more information regarding Mr. Ziehes geographic and job specific experience, please
refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.
Mr. Ziehe earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in
1974, with Magna Cum Laude honors and is a registered Professional Engineer in the State of Texas.
He is also a member of the Society of Petroleum Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of
Professional Engineers requires a minimum of fifteen hours of continuing education annually,
including at least one hour in the area of professional ethics, which Mr. Ziehe fulfills. As part
of his 2009 continuing education hours, Mr. Ziehe attended sixteen hours of internally presented
formalized training, as well as four hours at a public forum and at professional society
presentations specifically on the new SEC regulations relating to the definitions and disclosure
guidelines contained in the United States Securities and Exchange Commission Title 17, Code of
Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009
in the Federal Register. Mr. Ziehe attended an additional eighteen hours of formalized in-house
training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management
System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures
and software and ethics for consultants. Mr. Ziehe served as a speaker at a public forum and as an
in-house class instructor concerning the revised pricing criteria of the new SEC regulations.
Based on his educational background, professional training and more than 35 years of practical
experience in the estimation and evaluation of petroleum reserves, Mr. Ziehe has attained the
professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article
III of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the
Modernization of Oil and Gas Reporting; Final Rule in the Federal Register of National Archives
and Records Administration (NARA). The Modernization of Oil and Gas Reporting; Final Rule
includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X,
revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and
codifies Industry Guide 2 in Regulation S-K. The Modernization of Oil and Gas Reporting; Final
Rule, including all references to Regulation S-X and Regulation S-K, shall be referred to herein
collectively as the SEC Regulations. The SEC Regulations take effect for all filings made with
the United States Securities and Exchange Commission as of December 31, 2009, or after January 1,
2010. Reference should be made to the full text under Title 17, Code of Federal Regulations,
Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions,
descriptions and explanations rely wholly or in part on excerpts from the original document (direct
passages excerpted from the aforementioned SEC document are denoted in italics herein).
Reserves are those estimated remaining quantities of petroleum which are anticipated to be
economically producible, as of a given date, from known accumulations under defined conditions.
All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the
amount of reliable geologic and engineering data available at the time of the estimate and the
interpretation of these data. The relative degree of uncertainty may be conveyed by placing
reserves into one of two principal classifications, either proved or unproved. Unproved reserves
are less certain to be recovered than proved reserves and may be further sub-classified as probable
and possible reserves to denote progressively increasing uncertainty in their recoverability.
Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may
optionally disclose estimated quantities of probable or possible oil and gas reserves in documents
publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of
estimates of oil and gas resources other than reserves and any estimated values of such resources
in any document publicly filed with the Commission unless such information is required to be
disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised as additional geologic or engineering data become
available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved
recovery methods include all methods for supplementing natural energy or altering natural forces in
the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance,
natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed in the future as
petroleum technology continues to evolve.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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Reserves may be attributed to either conventional or unconventional petroleum accumulations.
Petroleum accumulations are considered as either conventional or unconventional based on the nature
of their in-place characteristics, extraction method applied, or degree of processing prior to
sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane
(CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.
These unconventional accumulations may require specialized extraction technology and/or significant
processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating
quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as
follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development
projects to known accumulations. In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a revenue interest in the
production, installed means of delivering oil and gas or related substances to market, and all
permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated
by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as
economically producible. Reserves should not be assigned to areas that are clearly separated from
a known accumulation by a non-productive reservoir (i.e., absence of reservoir,
structurally low reservoir, or negative test results). Such areas may contain prospective
resources (i.e., potentially recoverable resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas
reserves 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 produciblefrom a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulationsprior 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
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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(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.
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(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.
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RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and
reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part
210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on
excerpts from the original documents (direct passages excerpted from the aforementioned SEC and
SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and
gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
(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.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas
reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as
Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are
open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project
is in operation.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDELINES
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Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) | completion intervals which are open at the time of the estimate but which have not yet started producing; | ||
(2) | wells which were shut-in for market conditions or pipeline connections; or | ||
(3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will
require additional completion work or future re-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure
compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and
gas reserves as follows:
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
paragraph (a)(2) of this section, or by other evidence using reliable technology
establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS