SEC Company Response from DEVON ENERGY (DVN) — Jun 25, 2010
DEVON ENERGY CORP/DE (DVN) (CIK 0001090012)
Date: June 25, 2010 · CIK: 0001090012 · Accession: 0000950123-10-061059
AI Filing Summary & Sentiment
Reasoning
Referenced dates: April 14, 2010, April 8, 2010, June 11, 2010, March 31, 2010
Letter
Via EDGAR and Facsimile No. 703 813 6982 Attention: Mr. Norman Gholson, Division of Corporation Finance Filed February 25, 2010 Schedule 14A Filed April 28, 2010 Response Letters Dated April 14, 2010 and April 22, 2010 File No. 1-32318
Dear Mr. Schwall:
This letter responds to the staff’s comment letter dated June 11, 2010, regarding Devon Energy Corporation’s Form 10-K for the year ended December 31, 2009, filed February 25, 2010, and its Schedule 14A filed April 28, 2010 (the “Proxy Statement”) (File No. 1-32318). Devon’s responses to the staff’s comments are set forth below:
Form 10-K for the Fiscal Year Ended December 31, 2009
Preparation of Reserves Estimates and Reserves Audits, page 20
SEC Comment
1.
We note your response to prior comment four from our letter dated March 31, 2010, including your statement that the Director of the Reserve Evaluation Group “has experience in reserves estimation” for projects in specified areas. Please enhance your disclosure to provide details regarding this experience. For example, please describe his role in such projects. Also, we note that the disclosure on page 20 of your Annual Report on Form 10-K states that the Director and key members of the Group have qualifications that “include any or all of” the bulleted items on page 20. Please clarify which of these bulleted items apply specifically to the Director. Provide us with a revised version of your proposed enhanced disclosure.
Response
We propose that our future disclosures will include the following language:
The current Director of the Group has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in
U.S. Securities and Exchange Commission
page 2
June 25, 2010
reserves estimation for projects in the United States (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been employed by Devon for the past eight years, including the past two in his current position as Director of Reserves and Economics. During his career with Devon and others, he was the primary reservoir engineer for projects including, but not limited to:
Hugoton Gas Field (Kansas)
Sho-Vel-Tum CO2 Flood (Oklahoma)
West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)
Dagger Draw Oil Field (New Mexico)
Clarke Lake Gas Field (Alberta, Canada)
Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)
ACG Unit (Caspian Sea)
As the primary reservoir engineer, he was responsible for reserves estimation on each of these projects. These reserves estimates were utilized internally and for SEC filings.
From 2003 to 2010, he has served as the reservoir engineering representative on our internal Peer Review Team, reviewing reserves and resource estimates for projects including, but not limited to:
Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)
Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)
Polvo Development (Campos Basin, Brazil)
With regard to the penultimate sentence of your comment, we direct you to the first sentence of the paragraph following the bulleted items on page 20 of our Form 10-K, which states, “The current Director of the Group and the Group’s key members all have the qualifications listed above.”
Proved Oil, Natural Gas and NGL Reserves
Proved Undeveloped Reserves, page 23
SEC Comment
2.
We note your response to our prior comment five with regard to your proved undeveloped reserves related to your Jackfish project. Please address the following additional comments regarding this project:
•
Your response states that the development schedule for the Jackfish proved undeveloped reserves extends through the year 2025. Please provide us with a summary of the development plan(s) with narrations to explain the extended stages of the Jackfish project(s).
•
Your response also refers to the Jackfish field as a single development project. Please clarify whether you consider the development of the Jackfish field to be one development project or several separate projects. We refer you to the interpretation in Question 108.01 of the Oil and Gas
U.S. Securities and Exchange Commission
page 3
June 25, 2010
Rules Compliance and Disclosure Interpretations released on October 26, 2009.
•
Please address the consequences of early termination of the Jackfish project in terms of loss capital verses [sic] reduced return on capital. Explain whether a final investment decision has been made on the entire project, not just on Phase 1 of the project. We refer you to the interpretation in Question 131.04 of the Oil and Gas Rules Compliance and Disclosure Interpretations released on October 26, 2009.
•
Please provide us a detailed map of the Jackfish field which identifies the portion of the field which you have or are in the process of developing and the portion that remains undeveloped.
•
Please explain the significant terms of the Jackfish lease contract, including the expiration date.
Response
Regarding your first bulleted comment, in order to maintain maximum plant capacity at both Jackfish and Jackfish 2 central processing facilities, pad development has been staged over the life of the projects. Table 1 and Table 2 below outline the proven undeveloped reserves for each project, respectively, and the year in which development is expected to occur.
Table 1: Jackfish Reserves Summary at December 31, 2009
Net PUD
Development
Reserves
Development
Status
Reservoir
(MBbls)
Year
PUD
Pad E
13,034
PUD
Pad F
13,269
PUD
Pad G
12,460
PUD
Pad H
11,141
PUD
Pad I
13,370
PUD
Pad J
13,400
PUD
Pad K
11,194
PUD
Pad L
11,776
PUD
Pad M
5,838
PUD
Pad N
9,646
PUD
Pad O
11,081
PUD
Pad P
8,647
PUD
Pad Q
9,984
PUD
Pad R
7,152
PUD Total
14 pads
151,992
U.S. Securities and Exchange Commission
page 4
June 25, 2010
Table 2: Jackfish 2 Reserves Summary at December 31, 2009
Net PUD
Development
Reserves
Development
Status
Reservoir
(MBbls)
Year
PUD
PAD AA
8,148
PUD
PAD BB
15,348
PUD
PAD CC
14,670
PUD
PAD DD
9,771
PUD
PAD EE
15,674
PUD
PAD FF
12,240
PUD
PAD GG
12,771
PUD
PAD HH
13,736
PUD
PAD II
7,704
PUD
PAD JJ
14,223
PUD
PAD KK
9,868
PUD
PAD LL
7,455
PUD
PAD NN
10,200
PUD
PAD OO
11,723
PUD
PAD PP
12,169
PUD
PAD SS
12,765
PUD
PAD TT
10,079
PUD Total
17 pads
198,544
Regarding your second bulleted point, the development of both Jackfish and Jackfish 2 are considered to be separate projects by the regulatory bodies within Canada, specifically, Alberta’s Energy Resources Conservation Board, the Canada Revenue Agency and Alberta Environment.
Regarding your third bulleted point, as of December 31, 2009, neither the Jackfish project nor the Jackfish 2 project have reached payout, and therefore neither have provided a return on investment to date. Jackfish started production in late 2007, and Jackfish 2 is still in the construction stage. Early termination of the Jackfish project would result in 67% of the invested capital being unrecovered while an early termination of the Jackfish 2 project would result in a loss of 100% of invested capital.
The final investment decision has been made for both Jackfish and Jackfish 2 projects and approved by Devon’s Board of Directors as per sanction documents in June 2004 and June 2008, respectively.
Regarding your fourth bulleted point, the maps attached to this letter, entitled Area Map for Jackfish and Area Map for Jackfish 2, outline the proven developed subsurface drainage areas that are currently producing, and the proven undeveloped drainage areas. Please refer to Tables 1 and 2 above for development timing.
U.S. Securities and Exchange Commission
page 5
June 25, 2010
Regarding your fifth bulleted point, the oilsands rights associated with PDP and PUD reserves in the Jackfish area are leased under the provisions of Alberta Crown Oilsands Lease No. 7499050004 (primary term expiry in 2014), 7401010008 and 7401050038 (primary terms expiry in 2016).
The oilsands rights associated with PDP and PUD reserves in the Jackfish 2 area are leased under the provisions of Alberta Crown Oilsands Lease No. 7401090041 and 7401090008 (primary term expiry in 2016).
All leases in the Jackfish and Jackfish 2 areas shall be continued after the primary term based on the production and reserves present in the leased lands, pursuant to the statutorily enacted continuation mechanism and procedure for Alberta Crown oilsands leases.
Proved Reserves Cash Flow, page 24
SEC Comment
3.
We note your response to our prior comment seven which states that your year-end costs included in future net revenues are estimated using averages of several prior months’ actual costs. Tell us how your methodology complies with the guidance under ASC Topic 932-235-50-31B that states these costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. In this respect, explain how your use of average actual costs incurred provides a basis which enables you to determine current costs as of year-end.
Response
Our response deals separately with the two general types of costs included in the calculation of future net revenues — (1) production costs and (2) development costs. Our methodology for estimating the year-end production costs begins by using historical average costs. As noted in our response of April 14, 2010, averages of prior months’ costs are used because not all costs are incurred on a consistent month-to-month basis throughout a year. Focusing only on year-end costs will result in omitting the costs of activities that are incurred on a regular annual basis, but not necessarily at the end of the year.
Well workovers are a good example to illustrate this. Workovers are not conducted every month of a year and they may not, and often do not, occur as of year-end. In fact, although Devon has significant workover activity each year, very few workovers are performed on the last day of the year. During the life of many reservoirs, workover activities are routinely performed to maintain or stimulate production levels. Whether such workovers are performed in February, June or December, by using averages throughout the year we include the appropriate amount of workover activity in our cost estimates. The use of historical averages therefore ensures that our estimates of future production costs include all cost activities that are expected to be necessary to produce our proved reserves in the future.
U.S. Securities and Exchange Commission
page 6
June 25, 2010
Unlike the benchmark commodity prices that are used to estimate year-end oil and gas prices in the calculation of future cash inflows, there are no sources of similar year-end benchmark costs. Generally, averages of several months’ actual costs are a good approximation of year-end costs. However, as we develop and finalize our cost estimates, we examine cost trends in the weeks and months leading up to year-end. We are always mindful of current cost trends, including divergent trends in the geographic regions in which we operate. Operating costs can change rapidly, particularly during periods of significant changes in commodity prices. We also have certain operating costs, such as insurance, that are negotiated at set rates for specific periods of time. Changes in these negotiated rates can occur at anytime throughout a year. Therefore, if cost trends for specific operating activities at the end of the year have trended materially higher or lower than earlier in the year, we will replace average costs with more-current estimates to provide a fair representation of year-end costs.
Regarding development costs, such costs are estimated by examining the prior year’s cost structure to determine average well costs for individual project areas. This cost structure is then adjusted to account for known inflationary or deflationary changes in specific components of the cost structure that have occurred in the weeks and months leading up to year-end. Items that may be reviewed for significant contractual changes include, but are not limited to, drilling rigs, stimulation services, cementing services, oilfield tubulars and other significant tangible items.
We believe the general use of average costs, with adjustments as necessary for end-of-year changes that might occur, produces a fair representation of estimated production and development costs in accordance with Topic 932. Our methodology, or a derivation of it, to estimate year-end costs is widely used in the oil and gas industry. Representatives, including myself, from selected oil and gas companies met with Mr. Wayne Carnall, Mr. Ronald Winfrey and other SEC staff members on July 16, 2009 to discuss the FASB’s proposed amendments to Topic 932 and other issues related to the SEC’s Modernization of Oil and Gas Reporting. During that meeting, it was discussed that while the SEC’s new rules changed the historical methodology to calculate prices used to estimate future cash inflows, they did not change the methodology to calculate the related future costs. A discussion of how companies have historically estimated future costs included an acknowledgement by the SEC representatives that companies’ estimates of year-end costs have generally included the use of historical averages. No SEC staff members in attendance proposed that the use of averages to estimate year-end costs would not continue to be an acceptable method to estimate year-end costs.
Exhibits 99.1, 99.2 and 99.3
SEC Comment
4.
We note your response to prior comment one from our letter dated April 8, 2010. We may have further comments after the completion of our discussions with Ryder Scott Company.
Response
We will await any further comments from you on this matter.
U.S. Securities and Exchange Commission
page 7
June 25, 2010
SEC Comment
5.
We note your response to prior comment eight from our letter dated March 31, 2010, including your statement that “We will ensure that in our future filings such third-party reports include a declarative statement that is more easily identified.” Please provide us with an example of the enhanced disclosure.
Response
We propose to include the following language in the third-party reports in our future filings:
The assumptions, data, methods, and procedures are appropriate for the purposes served by the report.
SEC Comment
6.
Please obtain revised
Show Raw Text
CORRESP
1
filename1.htm
corresp
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260
405 552 4702 Phone
405 552 7692 Fax
danny.heatly@dvn.com
June 25, 2010
Via EDGAR and Facsimile No. 703 813 6982
Attention: Mr. Norman Gholson, Division of Corporation Finance
H. Roger Schwall
Assistant Director
U.S. Securities and Exchange Commission
100 F. Street, N.E.
Washington, D.C. 20549-7010
Re:
Devon Energy Corporation
Form 10-K for the Fiscal Year Ended December 31, 2009
Filed February 25, 2010
Schedule 14A Filed April 28, 2010
Response Letters Dated April 14, 2010 and April 22, 2010
File No. 1-32318
Dear Mr. Schwall:
This letter responds to the staff’s comment letter dated June 11, 2010, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2009, filed February 25, 2010, and its
Schedule 14A filed April 28, 2010 (the “Proxy
Statement”) (File No. 1-32318). Devon’s responses to
the staff’s comments are set forth below:
Form 10-K for the Fiscal Year Ended December 31, 2009
Preparation of Reserves Estimates and Reserves Audits, page 20
SEC Comment
1.
We note your response to prior comment four from our letter dated March 31, 2010, including
your statement that the Director of the Reserve Evaluation Group “has experience in reserves
estimation” for projects in specified areas. Please enhance your disclosure to provide
details regarding this experience. For example, please describe his role in such projects.
Also, we note that the disclosure on page 20 of your Annual Report on Form 10-K states that
the Director and key members of the Group have qualifications that “include any or all of” the
bulleted items on page 20. Please clarify which of these bulleted items apply specifically to
the Director. Provide us with a revised version of your proposed enhanced disclosure.
Response
We propose that our future disclosures will include the following language:
The current Director of the Group has been involved with reserves estimation in accordance
with SEC definitions and guidance since 1987. He has experience in
U.S. Securities and Exchange Commission
page 2
June 25, 2010
reserves estimation for projects in the United States (both onshore and offshore), as
well as in Canada, Asia, the Middle East and South America. He has been employed by Devon
for the past eight years, including the past two in his current position as Director of
Reserves and Economics. During his career with Devon and others, he was the primary
reservoir engineer for projects including, but not limited to:
Hugoton Gas Field (Kansas)
Sho-Vel-Tum CO2 Flood (Oklahoma)
West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)
Dagger Draw Oil Field (New Mexico)
Clarke Lake Gas Field (Alberta, Canada)
Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)
ACG Unit (Caspian Sea)
As the primary reservoir engineer, he was responsible for reserves estimation on each of
these projects. These reserves estimates were utilized internally and for SEC filings.
From 2003 to 2010, he has served as the reservoir engineering representative on our internal
Peer Review Team, reviewing reserves and resource estimates for projects including, but not
limited to:
Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)
Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)
Polvo Development (Campos Basin, Brazil)
With regard to the penultimate sentence of your comment, we direct you to the first sentence of the
paragraph following the bulleted items on page 20 of our Form 10-K, which states, “The current
Director of the Group and the Group’s key members all have the qualifications listed above.”
Proved Oil, Natural Gas and NGL Reserves
Proved Undeveloped Reserves, page 23
SEC Comment
2.
We note your response to our prior comment five with regard to your proved undeveloped
reserves related to your Jackfish project. Please address the following additional comments
regarding this project:
•
Your response states that the development schedule for the Jackfish proved
undeveloped reserves extends through the year 2025. Please provide us with a summary
of the development plan(s) with narrations to explain the extended stages of the
Jackfish project(s).
•
Your response also refers to the Jackfish field as a single development
project. Please clarify whether you consider the development of the Jackfish field to
be one development project or several separate projects. We refer you to the
interpretation in Question 108.01 of the Oil and Gas
U.S. Securities and Exchange Commission
page 3
June 25, 2010
Rules Compliance and Disclosure Interpretations released on October 26, 2009.
•
Please address the consequences of early termination of the Jackfish project
in terms of loss capital verses [sic] reduced return on capital. Explain whether a
final investment decision has been made on the entire project, not just on Phase 1 of
the project. We refer you to the interpretation in Question 131.04 of the Oil and Gas
Rules Compliance and Disclosure Interpretations released on October 26, 2009.
•
Please provide us a detailed map of the Jackfish field which identifies the
portion of the field which you have or are in the process of developing and the
portion that remains undeveloped.
•
Please explain the significant terms of the Jackfish lease contract,
including the expiration date.
Response
Regarding your first bulleted comment, in order to maintain maximum plant capacity at both Jackfish
and Jackfish 2 central processing facilities, pad development has been staged over the life of the
projects. Table 1 and Table 2 below outline the proven undeveloped reserves for each project,
respectively, and the year in which development is expected to occur.
Table 1: Jackfish Reserves Summary at December 31, 2009
Net PUD
Development
Reserves
Development
Status
Reservoir
(MBbls)
Year
PUD
Pad E
13,034
2010
PUD
Pad F
13,269
2011
PUD
Pad G
12,460
2012
PUD
Pad H
11,141
2014
PUD
Pad I
13,370
2015
PUD
Pad J
13,400
2016
PUD
Pad K
11,194
2017
PUD
Pad L
11,776
2018
PUD
Pad M
5,838
2019
PUD
Pad N
9,646
2021
PUD
Pad O
11,081
2022
PUD
Pad P
8,647
2023
PUD
Pad Q
9,984
2024
PUD
Pad R
7,152
2025
PUD Total
14 pads
151,992
U.S. Securities and Exchange Commission
page 4
June 25, 2010
Table 2: Jackfish 2 Reserves Summary at December 31, 2009
Net PUD
Development
Reserves
Development
Status
Reservoir
(MBbls)
Year
PUD
PAD AA
8,148
2010
PUD
PAD BB
15,348
2010
PUD
PAD CC
14,670
2010
PUD
PAD DD
9,771
2010
PUD
PAD EE
15,674
2014
PUD
PAD FF
12,240
2013
PUD
PAD GG
12,771
2020
PUD
PAD HH
13,736
2019
PUD
PAD II
7,704
2025
PUD
PAD JJ
14,223
2016
PUD
PAD KK
9,868
2025
PUD
PAD LL
7,455
2024
PUD
PAD NN
10,200
2017
PUD
PAD OO
11,723
2022
PUD
PAD PP
12,169
2015
PUD
PAD SS
12,765
2021
PUD
PAD TT
10,079
2022
PUD Total
17 pads
198,544
Regarding your second bulleted point, the development of both Jackfish and Jackfish 2 are
considered to be separate projects by the regulatory bodies within Canada, specifically, Alberta’s
Energy Resources Conservation Board, the Canada Revenue Agency and Alberta Environment.
Regarding your third bulleted point, as of December 31, 2009, neither the Jackfish project nor the
Jackfish 2 project have reached payout, and therefore neither have provided a return on investment
to date. Jackfish started production in late 2007, and Jackfish 2 is still in the construction
stage. Early termination of the Jackfish project
would result in 67% of the invested capital being unrecovered while an early termination of the
Jackfish 2 project would result in a loss of 100% of invested capital.
The final investment decision has been made for both Jackfish and Jackfish 2 projects and approved
by Devon’s Board of Directors as per sanction documents in June 2004 and June 2008, respectively.
Regarding your fourth bulleted point, the maps attached to this letter, entitled Area Map for
Jackfish and Area Map for Jackfish 2, outline the proven developed subsurface drainage areas that
are currently producing, and the proven undeveloped drainage areas. Please refer to Tables 1 and 2
above for development timing.
U.S. Securities and Exchange Commission
page 5
June 25, 2010
Regarding your fifth bulleted point, the oilsands rights associated with PDP and PUD reserves
in the Jackfish area are leased under the provisions of Alberta Crown Oilsands Lease No. 7499050004
(primary term expiry in 2014), 7401010008 and 7401050038 (primary terms expiry in 2016).
The oilsands rights associated with PDP and PUD reserves in the Jackfish 2 area are leased under
the provisions of Alberta Crown Oilsands Lease No. 7401090041 and 7401090008 (primary term expiry
in 2016).
All leases in the Jackfish and Jackfish 2 areas shall be continued after the primary term based on
the production and reserves present in the leased lands, pursuant to the statutorily enacted
continuation mechanism and procedure for Alberta Crown oilsands leases.
Proved Reserves Cash Flow, page 24
SEC Comment
3.
We note your response to our prior comment seven which states that your year-end costs
included in future net revenues are estimated using averages of several prior months’ actual
costs. Tell us how your methodology complies with the guidance under ASC Topic 932-235-50-31B
that states these costs shall be computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at the end of the year, based on
year-end costs and assuming continuation of existing economic conditions. In this respect,
explain how your use of average actual costs incurred provides a basis which enables you to
determine current costs as of year-end.
Response
Our response deals separately with the two general types of costs included in the calculation of
future net revenues — (1) production costs and (2) development costs. Our methodology for
estimating the year-end production costs begins by using historical average costs. As noted in our
response of April 14, 2010, averages of prior months’ costs are used because not all costs are
incurred on a consistent month-to-month basis
throughout a year. Focusing only on year-end costs will result in omitting the costs of activities
that are incurred on a regular annual basis, but not necessarily at the end of the year.
Well workovers are a good example to illustrate this. Workovers are not conducted every month of a
year and they may not, and often do not, occur as of year-end. In fact, although Devon has
significant workover activity each year, very few workovers are performed on the last day of the
year. During the life of many reservoirs, workover activities are routinely performed to maintain
or stimulate production levels. Whether such workovers are performed in February, June or December,
by using averages throughout the year we include the appropriate amount of workover activity in our
cost estimates. The use of historical averages therefore ensures that our estimates of future
production costs include all cost activities that are expected to be necessary to produce our
proved reserves in the future.
U.S. Securities and Exchange Commission
page 6
June 25, 2010
Unlike the benchmark commodity prices that are used to estimate year-end oil and gas prices in
the calculation of future cash inflows, there are no sources of similar year-end benchmark costs.
Generally, averages of several months’ actual costs are a good approximation of year-end costs.
However, as we develop and finalize our cost estimates, we examine cost trends in the weeks and
months leading up to year-end. We are always mindful of current cost trends, including divergent
trends in the geographic regions in which we operate. Operating costs can change rapidly,
particularly during periods of significant changes in commodity prices. We also have certain
operating costs, such as insurance, that are negotiated at set rates for specific periods of time.
Changes in these negotiated rates can occur at anytime throughout a year. Therefore, if cost
trends for specific operating activities at the end of the year have trended materially higher or
lower than earlier in the year, we will replace average costs with more-current estimates to
provide a fair representation of year-end costs.
Regarding development costs, such costs are estimated by examining the prior year’s cost structure
to determine average well costs for individual project areas. This cost structure is then adjusted
to account for known inflationary or deflationary changes in specific components of the cost
structure that have occurred in the weeks and months leading up to year-end. Items that may be
reviewed for significant contractual changes include, but are not limited to, drilling rigs,
stimulation services, cementing services, oilfield tubulars and other significant tangible items.
We believe the general use of average costs, with adjustments as necessary for end-of-year changes
that might occur, produces a fair representation of estimated production and development costs in
accordance with Topic 932. Our methodology, or a derivation of it, to estimate year-end costs is
widely used in the oil and gas industry. Representatives, including myself, from selected oil and
gas companies met with Mr. Wayne Carnall, Mr. Ronald Winfrey and other SEC staff members on July
16, 2009 to discuss the FASB’s proposed amendments to Topic 932 and other issues related to the
SEC’s Modernization of Oil and Gas Reporting. During that meeting, it was discussed that while the
SEC’s new rules changed the historical methodology to calculate prices used to estimate future cash
inflows, they did not change the methodology to calculate the
related future costs. A discussion of how companies have historically estimated future costs
included an acknowledgement by the SEC representatives that companies’ estimates of year-end costs
have generally included the use of historical averages. No SEC staff members in attendance
proposed that the use of averages to estimate year-end costs would not continue to be an acceptable
method to estimate year-end costs.
Exhibits 99.1, 99.2 and 99.3
SEC Comment
4.
We note your response to prior comment one from our letter dated April 8, 2010. We may have
further comments after the completion of our discussions with Ryder Scott Company.
Response
We will await any further comments from you on this matter.
U.S. Securities and Exchange Commission
page 7
June 25, 2010
SEC Comment
5.
We note your response to prior comment eight from our letter dated March 31, 2010, including
your statement that “We will ensure that in our future filings such third-party reports
include a declarative statement that is more easily identified.” Please provide us with an
example of the enhanced disclosure.
Response
We propose to include the following language in the third-party reports in our future filings:
The assumptions, data, methods, and procedures are appropriate for the purposes served by the
report.
SEC Comment
6.
Please obtain revised