SEC Company Response from PIONEER NATURAL RESOURCES CO (CIK 0001038357) — Jul 29, 2005
PIONEER NATURAL RESOURCES CO (CIK 0001038357)
Date: July 29, 2005 · CIK: 0001038357 · Accession: 0000950134-05-014397
AI Filing Summary & Sentiment
Referenced dates: April 27, 2005, July 15, 2005
Letter
Securities and Exchange Commission Division of Corporate Finance Attention: H. Roger Schwall Pioneer Natural Resources Company Form 10-K, Filed February 22, 2005 File No. 1-13245
Re:
Dear Mr. Schwall:
We are writing to respond to the engineering comments of the Staff of the Securities and Exchange Commission with respect to our Form 10-K in the comment letter dated July 15, 2005 (the “Comment Letter”), addressed to Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (“Pioneer” or the “Company”).
Comment Responses
The bold typeface, numbered paragraphs and headings below are taken from the Comment Letter. Our response to each such comment follows in plain text.
Form 2004 10-K for the year ended December 31, 2004
Business, page 5
Evergreen Merger, page 5
1.
Your response 1a) does not address the minimum gas production rates you require for attributing proved reserves to newly drilled exploration locations. Please tell us how you determine that proved reserves are justified in such situation.
Response: In our pure exploratory drilling, or coal bed methane (“CBM”) pilot projects, we demonstrate commercial gas production rates before claiming proved reserves. Minimum economic production rate thresholds are a function of many different factors (gas pricing, transportation cost, water lifting costs, production taxes, NRI/WI, etc.) specific to a particular location or project. For our current portfolio, we consider the minimum economic rate threshold to be a sustained rate of approximately 20 Mcf per day. At year-end 2004, we reported no proved reserves associated with CBM pilot projects in the Raton Basin.
In our Raton Basin CBM development project, the wells we drill on unproven lands are extensions of the existing producing reservoir. In some cases, we do not complete and produce these wells until they have been connected to the gathering system. In these cases,
H. Roger Schwall
Securities and Exchange Commission
Page 2
July 29, 2005
we estimate initial gas production rate by comparing data collected through the drilling process with “type wells” defined by analogous (similar reservoir properties, well spacing, completion techniques, etc.) producing wells. Reserve volumes supportable by the “type well” analog are classified as proved only if there is a plan to proceed with connection to the gathering system. We currently have more than 1,300 production wells in our Raton Basin CBM project from which to draw analogy. Based upon this significant experience, we are confident that our estimates of proved reserves attributable to extensions of our developed Raton CBM acreage meet the reasonable certainty criteria.
2.
In your response 1b), you state “The primary exception to this case would be that of an infill well which is drilled later in the life of the reservoir, where significant pressure drawdown has occurred and free gas saturation is present. In these cases, a well will more typically see its peak gas rate when it begins to produce and decline thereafter, more like a conventional gas well.” Please explain your methodology in accounting for the reduced gas-in-place in such infill wells’ proved reserve estimates.
Response: In the case of infill wells drilled in our Raton Basin CBM project, we account for the reduced gas-in-place associated with infill wells by re-allocating or re-distributing proved reserves from the parent wells to the infill well. Incremental or additional proved reserves are attributed to the infill well in some cases where an increase in the recoverable gas-in-place is justified by the increased well density.
Clarify whether the isotherms to which you refer in response 1d) are derived from desorption measurements. If you have used adsorption data in your estimates, address how you avoid overestimation of the coal bed gas content if coal beds are undersaturated as has been observed in the Powder River Basin.
Response: The isotherms to which we referred to in our response 1d) are derived from adsorption measurements in all cases. We actually have over 50 adsorption isotherms from over 40 cored wells in our Raton Basin project. We use both adsorption and desorption data in our estimates of gas-in-place to account for both saturated and undersaturated reservoir conditions where appropriate to avoid overestimation of gas content used in our gas-in-place and reserve estimates. Unlike the Powder River Basin, coals in our Raton Basin project area are generally saturated.
3.
In your response 1d), you state, “The volumetric recoverable reserves are then used to constrain the individual well forecasts on a spacing unit by spacing unit basis, typically 160 acres. Drainage areas are not explicitly estimated for each well.” This implies that you attribute 160 acres’ proved reserves to the spacing unit’s well and, presumably, to its offsetting proved undeveloped locations. If the well’s drainage area – and thus its ultimate proved reserves – is materially lower, this overestimation is leveraged in its offsetting PUD locations and a significant error can result.
Response: In our Raton Basin CBM project, we attribute 160 acres’ proved reserves to the spacing unit’s well and its offsetting proved undeveloped locations. In all cases, our volumetric recovery estimates are based upon variable recovery from a fixed area by using recovery factors derived from analogous well (similar reservoir properties, well spacing, completion techniques, etc.) performance data and/or material balance using the isotherms. Development of our Raton Basin acreage has typically occurred on 160-acre spacing and most wells appear to have adequate permeability to drain the designated area. However, we also use infill drilling to accelerate production and improve recovery in some cases.
H. Roger Schwall
Securities and Exchange Commission
Page 3
July 29, 2005
Hydraulic connection across and drainage of the 160-acre units is supported by a decline in initial static reservoir pressure measurements at such infill locations, and by infill well performance. While determination of actual drainage area is theoretically possible, it is inefficient in reservoirs of this nature and no more accurate than our alternative when adequate analogues exist. Since our acreage was developed on 160 acre spacing units, we have excellent recovery factor data for that assumed drainage area. In areas of lower permeability, we reduce the effectiveness of this drainage by lowering the estimated recovery factor for the 160-acre spacing unit. This process avoids overestimation of recoverable reserves in a given spacing unit and avoids leveraging these errors in offsetting PUD locations.
Reserve Quantity Information, page 7
4.
In your response 9, you state, “In the case of these seven non-offsetting PUDs, the areas are all “windows” within the existing field which have not yet been developed. Based upon above, the Company believes that these PUD locations are appropriately reflected in its proved reserves.” Please affirm to us that you have established pressure communication across all these undeveloped “windows”.
Response: At year-end 2004, we claimed proved reserves on four 160-acre undeveloped “windows” that were surrounded on three or more sides by producing wells located more than one offsetting location away. We have not established pressure communication across these “windows” through direct pressure measurement. Instead, in our Raton Basin CBM project, we establish pressure communication across these “windows” by interpretation of our potentiometric data. In all cases, we believe that the potentiometric data demonstrate the hydraulic continuity of the coal aquifer across these windows, and therefore pressure communication, as has been observed from pressure and well performance data as similar windows have been closed through additional drilling throughout our field. We have interpreted no discontinuities in the potentiometric data that would suggest the expected range of pressures and gas contents would not exist within these “windows.” As of June 30, 2005, we have now drilled offsetting 160-acre locations to three of the four 160-acre windows and have seen reservoir pressure continuity. As noted in our letter dated April 27, 2005, the total proved reserves associated with the four “windows” at December 31, 2004 was 4.9 Bcf or .1% of the Company’s total proved reserves. Prospectively, we will not record proved reserves in “windows” unless we have direct pressure continuity.
Please direct any questions in connection with the responses set forth in this letter to Richard P. Dealy at 972-969-4054 (direct fax 972-969-3572).
Very truly yours,
/s/ RICHARD P. DEALY
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July 29, 2005
Via facsimile and U.S. mail
Securities and Exchange Commission
Division of Corporate Finance
450 Fifth Street, N.W., Mail Stop 4-5
Washington, D.C. 20549-0405
Attention: H. Roger Schwall
Re:
Pioneer Natural Resources Company
Form 10-K, Filed February 22, 2005
File No. 1-13245
Dear Mr. Schwall:
We are writing to respond to the engineering comments of the Staff of the Securities and
Exchange Commission with respect to our Form 10-K in the comment letter dated July 15, 2005 (the
“Comment Letter”), addressed to Richard P. Dealy, Executive Vice President and Chief Financial
Officer of Pioneer Natural Resources Company (“Pioneer” or the “Company”).
Comment Responses
The bold typeface, numbered paragraphs and headings below are taken from the Comment Letter.
Our response to each such comment follows in plain text.
Form 2004 10-K for the year ended December 31, 2004
Business, page 5
Evergreen Merger, page 5
1.
Your response 1a) does not address the minimum gas production rates you require for
attributing proved reserves to newly drilled exploration locations. Please tell us how you
determine that proved reserves are justified in such situation.
Response: In our pure exploratory drilling, or coal bed methane (“CBM”) pilot projects, we
demonstrate commercial gas production rates before claiming proved reserves. Minimum economic
production rate thresholds are a function of many different factors (gas pricing,
transportation cost, water lifting costs, production taxes, NRI/WI, etc.) specific to a
particular location or project. For our current portfolio, we consider the minimum economic
rate threshold to be a sustained rate of approximately 20 Mcf per day. At year-end 2004, we
reported no proved reserves associated with CBM pilot projects in the Raton Basin.
In our Raton Basin CBM development project, the wells we drill on unproven lands are
extensions of the existing producing reservoir. In some cases, we do not complete and
produce these wells until they have been connected to the gathering system. In these cases,
H. Roger Schwall
Securities and Exchange Commission
Page 2
July 29, 2005
we estimate initial gas production rate by comparing data collected through the drilling
process with “type wells” defined by analogous (similar reservoir properties, well spacing,
completion techniques, etc.) producing wells. Reserve volumes supportable by the “type well”
analog are classified as proved only if there is a plan to proceed with connection to the
gathering system. We currently have more than 1,300 production wells in our Raton Basin CBM
project from which to draw analogy. Based upon this significant experience, we are confident
that our estimates of proved reserves attributable to extensions of our developed Raton CBM
acreage meet the reasonable certainty criteria.
2.
In your response 1b), you state “The primary exception to this case would be that of an
infill well which is drilled later in the life of the reservoir, where significant pressure
drawdown has occurred and free gas saturation is present. In these cases, a well will more
typically see its peak gas rate when it begins to produce and decline thereafter, more like a
conventional gas well.” Please explain your methodology in accounting for the reduced
gas-in-place in such infill wells’ proved reserve estimates.
Response: In the case of infill wells drilled in our Raton Basin CBM project, we account for
the reduced gas-in-place associated with infill wells by re-allocating or re-distributing
proved reserves from the parent wells to the infill well. Incremental or additional proved
reserves are attributed to the infill well in some cases where an increase in the recoverable
gas-in-place is justified by the increased well density.
Clarify whether the isotherms to which you refer in response 1d) are derived from desorption
measurements. If you have used adsorption data in your estimates, address how you avoid
overestimation of the coal bed gas content if coal beds are undersaturated as has been
observed in the Powder River Basin.
Response: The isotherms to which we referred to in our response 1d) are derived from
adsorption measurements in all cases. We actually have over 50 adsorption isotherms from over
40 cored wells in our Raton Basin project. We use both adsorption and desorption data in our
estimates of gas-in-place to account for both saturated and undersaturated reservoir
conditions where appropriate to avoid overestimation of gas content used in our gas-in-place
and reserve estimates. Unlike the Powder River Basin, coals in our Raton Basin project area
are generally saturated.
3.
In your response 1d), you state, “The volumetric recoverable reserves are then used to
constrain the individual well forecasts on a spacing unit by spacing unit basis, typically 160
acres. Drainage areas are not explicitly estimated for each well.” This implies that you
attribute 160 acres’ proved reserves to the spacing unit’s well and, presumably, to its
offsetting proved undeveloped locations. If the well’s drainage area – and thus its ultimate
proved reserves – is materially lower, this overestimation is leveraged in its offsetting PUD
locations and a significant error can result.
Response: In our Raton Basin CBM project, we attribute 160 acres’ proved reserves to the
spacing unit’s well and its offsetting proved undeveloped locations. In all cases, our
volumetric recovery estimates are based upon variable recovery from a fixed area by using
recovery factors derived from analogous well (similar reservoir properties, well spacing,
completion techniques, etc.) performance data and/or material balance using the isotherms.
Development of our Raton Basin acreage has typically occurred on 160-acre spacing and most
wells appear to have adequate permeability to drain the designated area. However,
we also use infill drilling to accelerate production and improve recovery in some cases.
H. Roger Schwall
Securities and Exchange Commission
Page 3
July 29, 2005
Hydraulic connection across and drainage of the 160-acre units is supported by a decline in
initial static reservoir pressure measurements at such infill locations, and by infill well
performance. While determination of actual drainage area is theoretically possible, it is
inefficient in reservoirs of this nature and no more accurate than our alternative when
adequate analogues exist. Since our acreage was developed on 160 acre spacing units, we have
excellent recovery factor data for that assumed drainage area. In areas of lower permeability,
we reduce the effectiveness of this drainage by lowering the estimated recovery factor for the
160-acre spacing unit. This process avoids overestimation of recoverable reserves in a given
spacing unit and avoids leveraging these errors in offsetting PUD locations.
Reserve Quantity Information, page 7
4.
In your response 9, you state, “In the case of these seven non-offsetting PUDs, the areas are
all “windows” within the existing field which have not yet been developed. Based upon above,
the Company believes that these PUD locations are appropriately reflected in its proved
reserves.” Please affirm to us that you have established pressure communication across all
these undeveloped “windows”.
Response: At year-end 2004, we claimed proved reserves on four 160-acre undeveloped “windows”
that were surrounded on three or more sides by producing wells located more than one
offsetting location away. We have not established pressure communication across these
“windows” through direct pressure measurement. Instead, in our Raton Basin CBM project, we
establish pressure communication across these “windows” by interpretation of our
potentiometric data. In all cases, we believe that the potentiometric data demonstrate the
hydraulic continuity of the coal aquifer across these windows, and therefore pressure
communication, as has been observed from pressure and well performance data as similar windows
have been closed through additional drilling throughout our field. We have interpreted no
discontinuities in the potentiometric data that would suggest the expected range of pressures
and gas contents would not exist within these “windows.” As of June 30, 2005, we have now
drilled offsetting 160-acre locations to three of the four 160-acre windows and have seen
reservoir pressure continuity. As noted in our letter dated April 27, 2005, the total proved
reserves associated with the four “windows” at December 31, 2004 was 4.9 Bcf or .1% of the
Company’s total proved reserves. Prospectively, we will not record proved reserves in
“windows” unless we have direct pressure continuity.
Please direct any questions in connection with the responses set forth in this letter to Richard P.
Dealy at 972-969-4054 (direct fax 972-969-3572).
Very truly yours,
/s/ RICHARD P. DEALY
Richard P. Dealy
Executive Vice President and
Chief Financial Officer
Cc:
Darin G. Holderness
Kerry D. Scott
Paul Onsager