| October 11, 2017 | |
| Re: | GeoPark Limited Form 20-F for Fiscal Year Ended December 31, 2016 Filed April 11, 2017 File No. 001-36298 |
Mr. Brad Skinner
Office of Natural Resources
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, DC 20549-3628
Dear Mr. Skinner,
We are responding to the comments from the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) relating to our Form 20-F for the fiscal year ended December 31, 2016 (the “Form 20-F”) contained in the Staff’s letter dated September 27, 2017 (the “Comment Letter”).
Set forth below is our response to the Staff’s comments. For convenience, the Staff’s comments are repeated below in italics, followed by our response to each comment as well as a summary of the responsive actions taken.
Business Overview, page 35
Oil and Natural Gas Reserves and Production, page 59
Proved Undeveloped Reserves, page 62
| 1. | Expand your disclosure to provide an appropriate narrative explanation of changes in proved undeveloped reserves and the net quantities relating to each individual factor, including offsetting factors, underlying the changes in your proved undeveloped reserves so that the change in net reserves between periods is fully explained. Your disclosure of revisions in the previous estimates of reserves in particular should identify such factors as changes caused by commodity prices, well performance, unsuccessful and/or uneconomic proved undeveloped locations or the removal of proved undeveloped locations due to changes in a previously adopted development plan. Refer to Item 1203(b) of Regulation S-K. |
Mr. Brad Skinner Office of Natural Resources
| 2 |
| Response: | In response to the Staff’s comment, we will revise the relevant disclosure in future Forms 20-F to include narrative disclosure explaining each significant change in proved undeveloped reserves. We respectfully note that the principal factors underlying the changes in proved undeveloped oil reserves were provided on page 62 of the Form 20-F, but we acknowledge that we will in the future expand our disclosure as follows: |
Changes for the year ended December 31, 2016, include (i) an increase of 9.3 MMboe in Morona Block related to the initial recognition of reserves associated with the approval of the amendment to the License Contract of Morona Block appointing GeoPark as operator and holder of 75% of the License-Contract. See “Item 4. Information on the Company—B. Business Overview—Our operations—operations in Peru.”; (ii) an increase of 6.3 MMboe resulting from appraisal success in Jacana oil field in the Llanos 34 Block and (iii) an increase of 4.8 MMboe due to revisions associated to well performance improvements and probable reserves transfers in Tigana and Chachalaca oil fields in Llanos 34 Block and in certain oil and gas fields in Fell Block.
During the year ended December 31, 2016, we had 5.3 MMboe of our proved undeveloped reserves from December 31, 2015 converted to proved developed reserves due to development drilling in the Jacana and Tigana oil fields in the Llanos 34 Block and development drilling in the Ache gas field in the Fell Block.”
| 2. | If you have material quantities of proved undeveloped reserves that will not be developed within five years of your initial disclosure, provide the information required by Item 1203(d) of Regulation S-K. If you expect that any of your proved undeveloped reserves will take more than five years to develop since initial disclosure, refer to the answer to question 131.03 in our Compliance and Disclosure Interpretations (C&DIs), and describe for us the specific circumstances that you believe justify an extended period of time. You may find the C&DIs on our website at the following address: |
http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.
| Response: | We acknowledge the Staff’s comment and respectfully advise the Staff that we plan to put approximately 81% of our reported 2016 year-end proved undeveloped reserves into production through activities to be implemented within five years of initial disclosure. The remaining 19% are expected to be developed over periods exceeding five years since initial disclosure, which are scheduled for the years ended December 31, 2020 and December 31, 2024, mainly located in oil and gas fields where the activity has been scheduled to maintain production levels in accordance with contracts and installed facilities in place. We take note of the Staff comments and advise the Staff that we will include these disclosures in future Forms 20-F. |
Mr. Brad Skinner Office of Natural Resources
| 3 |
Production, Revenues and Price History, page 63
| 3. | Expand the disclosure of production presented as average daily rates to provide this information as annual volumes for each of the last three fiscal years by final product sold with disclosure by geographical area and for each country and field that contains 15% ormore of your total proved reserves. Should you require additional guidance, refer to Item 1204(a) of Regulation S-K and Rule 4-10(a)(15) of Regulation S-X. |
| Response: | In response to the Staff’s comment, we will revise the relevant disclosure in future Forms 20-F to include annual volumes for each of the last three fiscal years by final products sold and geographical area. Set forth below is the relevant disclosure for the year ended December 31, 2016: |
| 2016 | 2015 (*) | 2014 (*) | ||||||||||||||||||||||
| Oil | Gas | Oil | Gas | Oil | Gas | |||||||||||||||||||
| Mbbl | MMcf | Mbbl | MMcf | Mbbl | MMcf | |||||||||||||||||||
| Tigana oil field | 1,871.5 | - | 1,809.7 | - | 1,221.7 | - | ||||||||||||||||||
| Jacana oil field | 1,188.6 | - | 151.3 | - | - | - | ||||||||||||||||||
| Rest of Colombia | 2,113.2 | - | 2,615.0 | - | 2,436.3 | - | ||||||||||||||||||
| Chile | 502.8 | 5,293.0 | 707.1 | 4,025.4 | 1,372.0 | 4,515.0 | ||||||||||||||||||
| Brazil | 14.0 | 6,314.0 | 17.6 | 7,213.0 | 20.0 | 7,216.0 | ||||||||||||||||||
| Argentina | - | - | - | - | - | - | ||||||||||||||||||
| Total | 5,690.1 | 11,607.0 | 5,300.7 | 11,238.4 | 5,050.0 | 11,731.0 | ||||||||||||||||||
The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia are separately included in the table above as those oil fields individually contain more than 15% of our total proved reserves as of each of the years indicated above.
(*) Please see response #6 in this letter.
Mr. Brad Skinner Office of Natural Resources
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Developed and Undeveloped Acreage, page 65
| 4. | Expand the presentation relating to your gross and net developed and undeveloped acreage to include such acreage for Argentina to comply with the disclosure requirements pursuant to Item 1208 of Regulation S-K or tell us why a revision is not necessary. |
| Response: | We acknowledge the Staff’s comment and we respectfully advise the Staff that our blocks in Argentina are exploratory and have not been drilled as of the date of filing the Form 20-F. As such, we believe that no revision is necessary pursuant to Item 1208 of Regulation S-K because our wells in Argentina are not productive wells. |
Notes to Consolidated Financial Statements
Supplemental Information on Oil and Gas Activities (Unaudited), page F-68
Estimated Oil and Gas Reserves, page F-71
| 5. | Revise the disclosure of changes in proved reserves provided pursuant to FASB ASC 932-235-50-5 to include appropriate explanation for all significant changes that occurred during the periods presented. |
| Response: | We acknowledge the Staff’s comment and we respectfully refer the Staff to the tables provided below Table 5 in Note 37 on pages F-73 and F-74. In particular, we believe that the “Revisions” and “Extensions and Discoveries” line items provide an explanation for all significant changes that occurred for all periods presented. We acknowledge that no narrative disclosure was provided as a footnote to the tables with respect to the line item in such tables entitled “Purchases of minerals in place”, but refer to the additional disclosure noted below: |
| · | Page 35: In December 2016, we obtained final regulatory approval for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement dated October 1, 2014 and its amendments were closed on December 1, 2016 following the issuance of Supreme Decree 031-2016-MEM. |
| · | Page 38: In 2013, the acquisition of Rio das Contas, which closed on March 31, 2014, gave us a 10% working interest in the BCAM-40 Concession, including the shallow-depth offshore Manati and Camarão Norte Fields in the Camamu-Almada Basin in the State of Bahia. The Manati Field is operated by Petrobras (with a 35% working interest), the Brazilian national company and the largest oil and gas operator in Brazil. Our Rio das Contas acquisition in Brazil provides us with a long-term off-take contract with Petrobras that covers approximately 100% of net proved gas reserves in the Manati Field, a valuable relationship with Petrobras and an established local platform and presence. |
| · | Page F-62: Note 34 “Business transactions” |
Notwithstanding the above, we will revise the tabular disclosures included on pages F-73 and F-74 in future Forms 20-F to include footnotes to all relevant line items explaining significant changes in proved reserves pursuant to FASB ASC 932-235-50-5.
Mr. Brad Skinner Office of Natural Resources
| 5 |
| 6. | We note there appears to be an inconsistency between the figures relating to the total production volumes used in the reconciliation of the changes in total proved reserves on pages F-73 and F-74 and the comparable figures presented on pages 98 and 104. Revise your disclosure to resolve this apparent inconsistency or include additional footnote disclosure to explain the differences. |
| Response: | In response to the Staff’s comment, we will revise the relevant disclosure in future Forms 20-F to include additional footnote disclosure to explain the differences between the figures relating to the total production volumes used in reconciliation of the changes to total proved reserves on pages F-73 and F-74 and the comparable figures presented on pages 98 and 104. |
With respect to oil production, the discrepancy is primarily due to the fact that production volumes used in the reconciliation of the changes in proved reserves on pages F-73 and F-74 is net production after royalties paid in kind, as the reported reserves are net of amounts that are expected to be paid in kind. The production figures included on pages 98 and 104, however, are before royalties in kind, as, consistent with the footnote disclosure on page 63, we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes and in line with managerial information we use internally to measure production performance.
Notwithstanding the above, when we reviewed the disclosures on page F-73, we realized that total oil production figures in 2015 should have been reported as 5.3 mmbbl instead of 5.5 mmbbl, with the difference having been reported in the revisions line for the same year. Also, total gas production figures in 2015 should have been reported as 11.2 mmcf instead of 11.4 mmcf, with the difference having been reported in the revisions line for the same year. We will correct these disclosures in future filings.
With respect to gas production, the discrepancy is primarily due to the fact that the production volumes used in the reconciliation of the changes in proved reserves on pages F-73 and F-74 are measured at the point of delivery. The information presented on pages 98 and 104, however, is gas available to be delivered into the gas pipeline after field separation but prior to compression, in line with managerial information we use internally to measure production performance.
Notwithstanding the above, we also clarify that “purchase of minerals in place” on page F-73 in Brazil for the year ended December 31, 2014 corresponds to reserves measured as of December 31, 2013 and that consequently, the production figures also correspond to the full year 2014. On page 104, the gas production figures include production for 2014 as of the date of closing, which corresponds to the period March 31, 2014-December 31, 2014. We will clarify this in future filings, as needed.
Mr. Brad Skinner Office of Natural Resources
| 6 |
We note the Staff´s comment and in future Forms 20-F will include additional disclosure throughout the document to clarify the foregoing as follows:
| Net Production Volumes | 2016 | 2015 |
| Oil (mmbbl) (a) | 6,189 | 5,518 |
| Gas (mcf) (b) | 11,911 | 11,493 |
| Total Net Production (mboe) | 8,174 | 7,434 |
———————
(a) We present production figures before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes. Oil production figures presented on page F-73 are net of royalties.
(b) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on pages F-73 and F-74 is gas measured at the point of delivery.
| 7. | Modify the line item entitled “Incorporation” in the tabular presentation of the changes in total proved reserves as of December 31, 2016 to correspond to one of the standardized change categories under FASB ASC 932-235-50-5. |
| Response: | We acknowledge the Staff’s comment and we respectfully advise the Staff that in future filings we will replace the line item entitled “Incorporation” in the tabular presentation of the changes in total proved reserves with line “Purchase of Minerals in place” with the appropriate footnote disclosure that corresponds to one of the standardized change categories underFASB ASC 932-235-50-5. |
| 8. | We note your footnote disclosure accompanying the tabular presentation of the consolidated reserves shown in Table 4 regarding LG International Corporation’s (“LGI”) 20% interest. Note that FASB ASC 932-235-50-8 requires the disclosure of the approximate portion of reserve quantities attributable to a consolidated subsidiary in which there is a significant non-controlling interest. Expand your disclosure to provide the net quantities of reserves corresponding to LGI’s interests or tell us why such disclosure is not necessary. Provide similar type disclosure regarding the standardized measure on page F-75. |
| Response: | We acknowledge the Staff’s comment and we respectfully advise the Staff that we believe the footnote disclosure accompanying the tabular presentation of the consolidated reserves shown in Table 4 relating to LGI provides information to disclose the approximate portion of consolidated reserves attributable to non-controlling interest as required by FASB ASC 932-235-50-8. Notwithstanding the above, we note the Staff´s comment and in future Forms 20-F will include additional disclosure to include the approximate number of reserves and similar disclosure with regards to the standardized measure, as follows: |
| - | The amounts of proved reserves disclosed herein as of December 31, 2016 include 8,796.2 thousand barrels of crude oil condensate and natural gas liquids and 7,356.0 million cubic feet of natural gas corresponding to non-controlling interest held by LGI. |
| - | The amounts of proved reserves disclosed herein as of December 31, 2015 include 7,281.3 thousand of barrels of crude oil condensate and natural gas liquids and 7,345.8 million of cubic feet of natural gas corresponding to non-controlling interest held by LGI. |
Mr. Brad Skinner Office of Natural Resources
| 7 |
| - | The amounts of proved reserves disclosed herein as of December 31, 2014 include 6,275.2 thousand of barrels of crude oil condensate and natural gas liquids and 6,948.4 million of cubic feet of natural gas corresponding to non-controlling interest held by LGI. |
| - | The amounts of the standardized measure of discounted future net cash flows herein for the year ended December 31, 2016, 2015 and 2014 include $61.4 million, $73.9 million and $164.2 million that correspond to the non-controlling interest held by LGI. |
Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves, page F-74
| 9. | Your disclosure on page 62 indicates that you incurred approximately $10.1 million in capital expenditures to convert 5.3 MMboe of proved undeveloped reserves to developed reserves which equates to a unit development cost of approximately $1.906 per boe. This appears to be significantly less than the unit development costs indicated from the figures presented in your standardized measure which would equate to a projected future unit development cost of approximately $9.78 per boe ($470.5 million/48.1 MMboe). Explain the significant differences between your historical and projected future development costs and reconcile the difference between the $10.1 million incurred to convert proved undeveloped reserves and the total development costs incurred during the year of $17.3 million as disclosed on page F-68. |
| Response: | We acknowledge the Staff’s comment and respectfully advise the Staff that the development costs of $1.9 per boe incurred in 2016 is significantly lower than the consolidated projected future development costs presented in the standardized measure due to the fact that, significant capital expenditures in 2016 allocated principally to convert proven undeveloped reserves in Colombia. The development costs associated with the conversion of these proven undeveloped reserves incurred in 2016 on a per boe basis are consistent with those derived from the standardized measure of approximately $2.5 per boe ($70 million /27.8 MMboe). In addition, we also advise the Staff that projected future development costs are impacted by our entry into Peru in 2016, and the subsequent addition of proved developed and undeveloped reserves in Peru, for which the future development costs are $234 million. This figure represents 50% of our consolidated future development costs but only 25% of total proved reserves (or 19% of proved undeveloped reserves) as of December 31, 2016, thus significantly increasing consolidated average future unit of developments costs. |
The table below provides a breakdown of development costs incurred in 2016 to reconcile the $10.1 million invested to convert proven undeveloped reserves to proven developed reserves to the total development costs of $17.3 million reported in Costs Incurred tabular disclosures included on page F-68:
| Description | Amount (million $) |
| Conversion of PUD to PD | $10.1 |
| Facilities (*) | $8.5 |
| Asset Retirement Obligations (**) | ($1.3) |
| Total development costs | $17.3 |
(*) Correspond mainly to facilities in Llanos 34 Block in Colombia. (**) Corresponds to the effect of change in estimate of asset retirement obligations in Colombia. | |
Mr. Brad Skinner Office of Natural Resources
| 8 |
Please do not hesitate to contact me at +54-11-4312-9400 or aocampo@geo-park.com if you have any questions regarding the foregoing or if I can provide any additional information.
Very truly yours
/s/ Andrés Ocampo
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Andrés Ocampo Chief Financial Officer GeoPark Limited
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| cc: | Via E-mail Maurice Blanco, Davis Polk & Wardwell LLP Yasin Keshvargar, Davis Polk & Wardwell LLP Ezequiel Mirazon, Price Waterhouse & Co. S.R.L., Argentina German Moss, DeGolyer and MacNaughton
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