SEC Company Response from PIONEER NATURAL RESOURCES CO (CIK 0001038357) — Aug 18, 2020
PIONEER NATURAL RESOURCES CO (CIK 0001038357)
Date: Aug. 18, 2020 · CIK: 0001038357 · Accession: 0001038357-20-000057
AI Filing Summary & Sentiment
File numbers found in text: 001-13245
Referenced dates: July 28, 2020
Letter
Document
August 18, 2020
Via EDGAR Submission and Email
U.S. Securities & Exchange Commission
Division of Corporation Finance
100 F Street, NE
Washington, D.C. 20549
Attention: Mr. Brad Skinner, Office Chief
Mr. John Hodgin
Re: Pioneer Natural Resources
Form 10-K for Fiscal Year Ended December 31, 2019
10-K filed February 24, 2020
File No. 001-13245
Gentlemen,
I am writing to respond to your comment letter dated July 28, 2020 (the "Review Letter"), addressed to Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company ("Pioneer" or the "Company"), with respect to the Company's Form 10-K for the year ended December 31, 2019, filed with the United States Securities and Exchange Commission (the "Commission") on February 24, 2020.
For your convenience, we have repeated the comment prior to the response. The comment is highlighted in bold, Pioneer’s response to your comment follows.
Form 10-K for the Fiscal Year Ended December 31, 2019
Properties
Drilling Activities, page 42
1.Expand the disclosure of your drilling activities to clarify the extent, if true, that your productive exploratory wells include wells drilled to extend the limits of a known reservoir, e.g. extension wells. Refer to the definition of a productive well in Item 1205(b)(2) of Regulation S-K and the definitions of a development, exploratory and extension well in Rule 4-10(a)(9), (a)(13) and (a)(14), respectively.
Response: Our disclosure of productive exploratory wells does include extension wells as defined in SEC Regulation S-X Rule 4-10(a)(14). In future filings, the Company will expand its disclosure to refer to such wells as "Exploratory/extension" wells.
Unaudited Supplementary Information
Oil & Gas Exploration and Production Activities
Reserve Quantity Information, page 108
2. The change in the net quantities of total proved reserves attributed to extensions and discoveries appears to be significantly greater than the corresponding change in the net quantities of proved undeveloped reserves for each of the last three fiscal years presented. Expand the discussion of the changes in your total proved reserves attributed to extensions and discoveries to explain the reason(s) for this difference. Refer to FASB ASC 932-235-50-5
Response: The Company will expand the discussion of the changes in total proved reserves attributed to extensions and discoveries in future filings. The following is an example of the proposed future disclosure:
Extensions and discoveries in 2019, 2018 and 2017 were primarily comprised of proved reserve additions attributable to the Company's successful horizontal drilling program in the Spraberry/Wolfcamp oil field in the Permian Basin. During 2019, 2018 and 2017, the Company drilled 280, 251 and 222 gross productive exploratory/extension wells, respectively, and added 41, 24 and 93 of proved undeveloped locations, respectively. Associated therewith, during 2019, 2018 and 2017, the Company added 276 MMBOE, 265 MMBOE and 241 MMBOE of net reserves from extensions and discoveries, respectively, of which 36 MMBOE, 23 MMBOE and 52 MMBOE, respectively, were recorded as proved undeveloped reserves.
The Permian Basin's geology is complex, consisting of multiple stacked horizons/zones, each with its own unique characteristics. The Company recognizes proved undeveloped reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or when reliable technology provides reasonable certainty of economic producibility. The Company did not add any proved undeveloped reserves using reliable technology during the years 2017 - 2019.
3. Expand the tabular disclosure of your proved reserves to present the net quantities of proved developed and proved undeveloped reserves, by individual product type, at the beginning of 2017, the first period presented in the reserves reconciliation. Refer to FASB ASC 932-235-50-4.
Response: In future filings, the Company will modify its tabular disclosure of net quantities of proved developed and proved undeveloped reserves, by individual product type, as depicted in Appendix I hereto - Tabular Disclosure of Proved Reserves.
4. The Future production and development costs shown on page 111 in the tabular presentation of the cash flows from proved undeveloped reserves as of December 31, 2019 appear to be significantly less than the corresponding production costs in the standardized measure as of December 31, 2019 and the development costs incurred to convert proved undeveloped reserves during fiscal 2019, when determined on a dollar per Boe of reserves basis.
For example, the future production costs for proved undeveloped reserves of $638 million correlates to $11.07 per Boe; however, the future production costs for total proved reserves of $19,687 million correlates to $17.34 per Boe of reserves. Similarly, the future development costs for proved undeveloped reserves of $508 million correlates to $8.81 per Boe; however, the costs incurred to convert proved undeveloped reserves during fiscal 2019 of $743 million correlates to $27.58 per Boe of reserves.
Expand your disclosure of the future cash flows from proved undeveloped reserves as of December 31, 2019 to explain the reason(s) for the differences in future production costs compared to the costs used to determine the cash flows for total proved reserves and for the differences in future development costs compared to the costs incurred to convert proved undeveloped reserves during the last fiscal year.
Response: In future filings, the Company will expand its disclosure to explain the differences in future production and development costs, on a per BOE basis, of proved undeveloped wells as compared to the production costs per BOE associated with proved developed producing properties and current year development costs per BOE, respectively.
The Company's estimated future production costs attributable to proved undeveloped reserves of $11.07 per BOE are less than the forecasted future production costs attributable to total proved reserves in 2019 of $17.34 per BOE for the following reasons:
•As of December 31, 2019, the majority of the Company's proved developed producing wells are comprised of legacy vertical wells that have higher production costs, on a per BOE basis, than the Company's proved developed producing horizontal wells. The total proved reserves production cost per BOE of $17.34 is comprised of $13.83 per BOE for horizontal wells and $34.32 per BOE for vertical wells. The Company's proved undeveloped wells as of December 31, 2019 are horizontal wells that are forecasted to have lower production costs.
•The estimated future production costs of $11.07 per BOE associated with proved undeveloped horizontal wells is marginally lower than the $13.83 per BOE average of the Company's producing horizontal wells included in total proved reserves. The lower costs take into account the initial production rates of new wells, which are higher at the beginning of a well's life, and result in a lower overall production cost, on a per BOE basis, when looked at over the well's total productive life versus a well that is later in its productive life. In addition, the future production costs on proved undeveloped horizontal wells also reflect the economies of scale of adding the wells to existing infrastructure, allowing the Company to spread certain fixed costs over a larger production volume.
The Company's estimated future development costs attributable to proved undeveloped reserves of $8.81 per BOE are less than the actual development costs incurred in 2019 of $27.58 per BOE for proved undeveloped reserves transferred to proved developed during the year for the following reasons:
•The development costs incurred include other capital investments that are not directly related to drilling and completion of the wells transferred to proved developed during the year. The costs directly related to the proved reserves transferred during the year were approximately $225 million, or $8.35 per BOE. The development costs for future proved undeveloped wells are marginally higher than historical levels because the proved undeveloped well costs include infrastructure costs (i.e. tank batteries, flowlines, pipeline connections, etc.) that are
not reflected in the historical amounts. The infrastructure costs for proved reserves transferred are included in the $120 million of aggregate facilities costs noted below.
•A significant portion of the remaining development costs (approximately $150 million) is related to the Company's ownership share of expansion capital in gas plants and related infrastructure (see description of the Company's gas plant ownership in Note 2 of Notes to Consolidated Financial Statements).
•Another large component of the remaining development costs (approximately $120 million) is related to production facilities, flowlines, pipeline connections, etc. that were incurred associated with the development wells and successful exploration/extension wells placed on production during the year.
•The other major components of development cost incurred include (i) an increase in the Company's asset retirement obligation estimates for vertical wells (see Note 9 of Notes to Consolidated Financial Statements), (ii) labor costs associated with the Company's development program, (iii) capital workovers performed during the year and (iv) capital related to non-operated well activity.
Pioneer further acknowledges that:
•the Company is responsible for the adequacy and accuracy of the disclosure in the filing;
•staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
•the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States
Please direct any questions in connection with the response set forth in this letter to Richard P. Dealy at 972-969-4054 or email at Rich.Dealy@pxd.com. In addition, we request that you advise us when the Staff has completed its review of the filing which was the subject of the Staff’s comments.
Very truly yours,
/s/ Richard P. Dealy
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filename1.htm
Document
August 18, 2020
Via EDGAR Submission and Email
U.S. Securities & Exchange Commission
Division of Corporation Finance
100 F Street, NE
Washington, D.C. 20549
Attention: Mr. Brad Skinner, Office Chief
Mr. John Hodgin
Re: Pioneer Natural Resources
Form 10-K for Fiscal Year Ended December 31, 2019
10-K filed February 24, 2020
File No. 001-13245
Gentlemen,
I am writing to respond to your comment letter dated July 28, 2020 (the "Review Letter"), addressed to Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company ("Pioneer" or the "Company"), with respect to the Company's Form 10-K for the year ended December 31, 2019, filed with the United States Securities and Exchange Commission (the "Commission") on February 24, 2020.
For your convenience, we have repeated the comment prior to the response. The comment is highlighted in bold, Pioneer’s response to your comment follows.
Form 10-K for the Fiscal Year Ended December 31, 2019
Properties
Drilling Activities, page 42
1.Expand the disclosure of your drilling activities to clarify the extent, if true, that your productive exploratory wells include wells drilled to extend the limits of a known reservoir, e.g. extension wells. Refer to the definition of a productive well in Item 1205(b)(2) of Regulation S-K and the definitions of a development, exploratory and extension well in Rule 4-10(a)(9), (a)(13) and (a)(14), respectively.
Response: Our disclosure of productive exploratory wells does include extension wells as defined in SEC Regulation S-X Rule 4-10(a)(14). In future filings, the Company will expand its disclosure to refer to such wells as "Exploratory/extension" wells.
Unaudited Supplementary Information
Oil & Gas Exploration and Production Activities
Reserve Quantity Information, page 108
2. The change in the net quantities of total proved reserves attributed to extensions and discoveries appears to be significantly greater than the corresponding change in the net quantities of proved undeveloped reserves for each of the last three fiscal years presented. Expand the discussion of the changes in your total proved reserves attributed to extensions and discoveries to explain the reason(s) for this difference. Refer to FASB ASC 932-235-50-5
Response: The Company will expand the discussion of the changes in total proved reserves attributed to extensions and discoveries in future filings. The following is an example of the proposed future disclosure:
Extensions and discoveries in 2019, 2018 and 2017 were primarily comprised of proved reserve additions attributable to the Company's successful horizontal drilling program in the Spraberry/Wolfcamp oil field in the Permian Basin. During 2019, 2018 and 2017, the Company drilled 280, 251 and 222 gross productive exploratory/extension wells, respectively, and added 41, 24 and 93 of proved undeveloped locations, respectively. Associated therewith, during 2019, 2018 and 2017, the Company added 276 MMBOE, 265 MMBOE and 241 MMBOE of net reserves from extensions and discoveries, respectively, of which 36 MMBOE, 23 MMBOE and 52 MMBOE, respectively, were recorded as proved undeveloped reserves.
The Permian Basin's geology is complex, consisting of multiple stacked horizons/zones, each with its own unique characteristics. The Company recognizes proved undeveloped reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or when reliable technology provides reasonable certainty of economic producibility. The Company did not add any proved undeveloped reserves using reliable technology during the years 2017 - 2019.
3. Expand the tabular disclosure of your proved reserves to present the net quantities of proved developed and proved undeveloped reserves, by individual product type, at the beginning of 2017, the first period presented in the reserves reconciliation. Refer to FASB ASC 932-235-50-4.
Response: In future filings, the Company will modify its tabular disclosure of net quantities of proved developed and proved undeveloped reserves, by individual product type, as depicted in Appendix I hereto - Tabular Disclosure of Proved Reserves.
4. The Future production and development costs shown on page 111 in the tabular presentation of the cash flows from proved undeveloped reserves as of December 31, 2019 appear to be significantly less than the corresponding production costs in the standardized measure as of December 31, 2019 and the development costs incurred to convert proved undeveloped reserves during fiscal 2019, when determined on a dollar per Boe of reserves basis.
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For example, the future production costs for proved undeveloped reserves of $638 million correlates to $11.07 per Boe; however, the future production costs for total proved reserves of $19,687 million correlates to $17.34 per Boe of reserves. Similarly, the future development costs for proved undeveloped reserves of $508 million correlates to $8.81 per Boe; however, the costs incurred to convert proved undeveloped reserves during fiscal 2019 of $743 million correlates to $27.58 per Boe of reserves.
Expand your disclosure of the future cash flows from proved undeveloped reserves as of December 31, 2019 to explain the reason(s) for the differences in future production costs compared to the costs used to determine the cash flows for total proved reserves and for the differences in future development costs compared to the costs incurred to convert proved undeveloped reserves during the last fiscal year.
Response: In future filings, the Company will expand its disclosure to explain the differences in future production and development costs, on a per BOE basis, of proved undeveloped wells as compared to the production costs per BOE associated with proved developed producing properties and current year development costs per BOE, respectively.
The Company's estimated future production costs attributable to proved undeveloped reserves of $11.07 per BOE are less than the forecasted future production costs attributable to total proved reserves in 2019 of $17.34 per BOE for the following reasons:
•As of December 31, 2019, the majority of the Company's proved developed producing wells are comprised of legacy vertical wells that have higher production costs, on a per BOE basis, than the Company's proved developed producing horizontal wells. The total proved reserves production cost per BOE of $17.34 is comprised of $13.83 per BOE for horizontal wells and $34.32 per BOE for vertical wells. The Company's proved undeveloped wells as of December 31, 2019 are horizontal wells that are forecasted to have lower production costs.
•The estimated future production costs of $11.07 per BOE associated with proved undeveloped horizontal wells is marginally lower than the $13.83 per BOE average of the Company's producing horizontal wells included in total proved reserves. The lower costs take into account the initial production rates of new wells, which are higher at the beginning of a well's life, and result in a lower overall production cost, on a per BOE basis, when looked at over the well's total productive life versus a well that is later in its productive life. In addition, the future production costs on proved undeveloped horizontal wells also reflect the economies of scale of adding the wells to existing infrastructure, allowing the Company to spread certain fixed costs over a larger production volume.
The Company's estimated future development costs attributable to proved undeveloped reserves of $8.81 per BOE are less than the actual development costs incurred in 2019 of $27.58 per BOE for proved undeveloped reserves transferred to proved developed during the year for the following reasons:
•The development costs incurred include other capital investments that are not directly related to drilling and completion of the wells transferred to proved developed during the year. The costs directly related to the proved reserves transferred during the year were approximately $225 million, or $8.35 per BOE. The development costs for future proved undeveloped wells are marginally higher than historical levels because the proved undeveloped well costs include infrastructure costs (i.e. tank batteries, flowlines, pipeline connections, etc.) that are
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not reflected in the historical amounts. The infrastructure costs for proved reserves transferred are included in the $120 million of aggregate facilities costs noted below.
•A significant portion of the remaining development costs (approximately $150 million) is related to the Company's ownership share of expansion capital in gas plants and related infrastructure (see description of the Company's gas plant ownership in Note 2 of Notes to Consolidated Financial Statements).
•Another large component of the remaining development costs (approximately $120 million) is related to production facilities, flowlines, pipeline connections, etc. that were incurred associated with the development wells and successful exploration/extension wells placed on production during the year.
•The other major components of development cost incurred include (i) an increase in the Company's asset retirement obligation estimates for vertical wells (see Note 9 of Notes to Consolidated Financial Statements), (ii) labor costs associated with the Company's development program, (iii) capital workovers performed during the year and (iv) capital related to non-operated well activity.
Pioneer further acknowledges that:
•the Company is responsible for the adequacy and accuracy of the disclosure in the filing;
•staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
•the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States
Please direct any questions in connection with the response set forth in this letter to Richard P. Dealy at 972-969-4054 or email at Rich.Dealy@pxd.com. In addition, we request that you advise us when the Staff has completed its review of the filing which was the subject of the Staff’s comments.
Very truly yours,
/s/ Richard P. Dealy
Richard P. Dealy
Executive Vice President and Chief Financial Officer
Cc: Margaret M. Montemayor
4
Appendix I
Tabular Disclosure of Proved Reserves:
Year Ended December 31,
2019
Oil
(MBbls) NGLs
(MBbls) Gas
(MMcf) (a) Total
(MBOE)
Total Proved Reserves:
Balance, January 1 565,010 240,914 1,458,574 1,049,020
Production (b) (77,509) (26,398) (145,026) (128,078)
Revisions of previous estimates (30,216) 29,415 94,767 14,994
Extensions and discoveries 167,022 60,069 293,507 276,009
Sales of minerals-in-place (20,603) (22,032) (202,401) (76,369)
Purchases of minerals-in-place 46 15 92 76
Balance, December 31 603,750 281,983 1,499,513 1,135,652
Proved Developed Reserves:
Balance, January 1 521,579 219,730 1,330,852 963,118
Balance, December 31 571,293 268,468 1,429,417 1,077,997
Proved Undeveloped Reserves:
Balance, January 1 43,431 21,184 127,722 85,902
Balance, December 31 32,457 13,515 70,096 57,655
Year Ended December 31,
2018
Oil
(MBbls) NGLs
(MBbls) Gas
(MMcf) (a) Total
(MBOE)
Total Proved Reserves:
Balance, January 1 482,889 210,497 1,751,880 985,366
Production (b) (69,583) (23,280) (157,278) (119,076)
Revisions of previous estimates (15,665) 21,087 257,502 48,339
Extensions and discoveries 175,067 51,414 230,272 264,859
Sales of minerals-in-place (7,722) (18,809) (623,830) (130,502)
Purchases of minerals-in-place 24 5 28 34
Balance, December 31 565,010 240,914 1,458,574 1,049,020
Proved Developed Reserves:
Balance, January 1 442,364 189,434 1,629,451 903,373
Balance, December 31 521,579 219,730 1,330,852 963,118
Proved Undeveloped Reserves:
Balance, January 1 40,525 21,063 122,429 81,993
Balance, December 31 43,431 21,184 127,722 85,902
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Year Ended December 31,
2017
Oil
(MBbls) NGLs
(MBbls) Gas
(MMcf) (a) Total
(MBOE)
Total Proved Reserves:
Balance, January 1 378,196 136,941 1,264,729 725,925
Production (b) (57,878) (20,078) (143,464) (101,867)
Revisions of previous estimates 20,140 44,995 365,275 126,015
Extensions and discoveries 146,822 49,378 266,347 240,591
Sales of minerals-in-place (4,899) (918) (4,898) (6,633)
Purchases of minerals-in-place 508 179 3,891 1,335
Balance, December 31 482,889 210,497 1,751,880 985,366
Proved Developed Reserves:
Balance, January 1 343,515 126,928 1,215,861 673,085
Balance, December 31 442,364 189,434 1,629,451 903,373
Proved Undeveloped Reserves:
Balance, January 1 34,681 10,013 48,868 52,840
Balance, December 31 40,525 21,063 122,429 81,993
________________
(a) The proved gas reserves as of December 31, 2019, 2018 and 2017 include 100,236 MMcf, 106,948 MMcf and 171,623 MMcf, respectively, of gas that the Company expected to be produced and utilized as field fuel. Field fuel is gas consumed to operate field equipment (primarily compressors) rather than being delivered to a sales point.
(b) Production for 2019, 2018 and 2017 includes 11,781 MMcf, 13,690 MMcf and 14,799 MMcf of field fuel, respectively.
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