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| PRIVILEGED AND CONFIDENTIAL | ||
August 5, 2021
VIA EDGAR
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
100 F Street, N.E.
Washington, DC 20549
Attention: | Sandra Wall | |
| Brad Skinner |
| Re: | Contango Oil & Gas Company |
Form 10-K for the Fiscal Year Ended December 31, 2020, Filed March 10, |
2021 (File No. 001-16317) |
Ladies and Gentlemen:
On behalf of Contango Oil & Gas Company, a Texas corporation (the “Company”), set forth below are responses of the Company to the comments of the staff of the Division of Corporation Finance (the “Staff”) of the U.S. Securities and Exchange Commission (the “Commission”) contained in your letter dated July 27, 2021 (the “Comment Letter”) regarding the above-referenced Form 10-K for the Fiscal Year Ended December 31, 2020, File No. 001-16317 (the “2020 Annual Report”). Capitalized terms used herein and otherwise not defined herein shall have the meanings assigned to such terms in the 2020 Annual Report.
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. All references to page numbers and captions correspond to the 2020 Annual Report unless otherwise specified.
We respectfully note for the Staff that on June 7, 2021, the Company entered into a definitive agreement (the “Transaction Agreement”) with Independence Energy, LLC, a Delaware limited liability company (“Independence”), an entity managed by KKR & Co. Inc. (“KKR”), IE PubCo Inc., a Delaware corporation (“New PubCo”), and certain other entities affiliated with Independence, New PubCo and KKR. New PubCo was incorporated and formed for the purpose of effecting a merger between the Company and Independence through a series of transactions pursuant to the Transaction Agreement (the
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 2
“Transactions”). It is a condition to the consummation of the Transactions that the shares of New PubCo Class A common stock to be issued in connection with the Transactions be authorized for listing on a nationally recognized stock exchange. New PubCo intends to apply for listing on the NYSE. If and when the Transactions are completed, the Company’s common stock currently listed on the NYSE American would cease to be listed on the NYSE American and will be deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Company would no longer be required to file reports with the Commission pursuant to the Exchange Act. Closing is expected to occur in the fourth quarter of 2021.
Exploration and Development Acreage, page 47
| 1. | We note your disclosure of the undeveloped acreage subject to expiration over the next three fiscal years represents approximately 86% of your total net undeveloped acreage. Please tell us the extent to which you have assigned any proved undeveloped reserves to locations which are currently scheduled to be drilled after lease expiration. |
Response: We acknowledge the Staff’s comment and respectfully advise the Staff that we do not have any wells, including proved undeveloped locations, scheduled to be drilled after lease expiration.
At December 31, 2020, we had four gross locations associated with proved undeveloped reserves scheduled to be drilled in 2021. Additionally, we had two unproved wells scheduled to be drilled in 2021. Three of these wells were recently drilled on one pad and are awaiting completion. Drilling of the second pad of three wells is in process at this time. Commencing drilling operations extends the lease term for each of the leases associated with all of our proved undeveloped reserves. Completion of the wells, included in our adopted development plan, will fully hold the leases and associated acreage.
Exploration and Development Acreage, page 47
| 2. | If there are material quantities of net proved undeveloped reserves relating to such locations, expand the disclosure here or in an appropriate section elsewhere to provide the net quantities of such reserves and explain the steps and related |
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
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| costs, if material, which would be necessary to extend the time to the expiration of such leases. Refer to Rule 4-10(a)(26) of Regulation S-K and FASB ASC 932-235-50-10. |
Response: We respectfully advise the Staff that the quantities of net proved undeveloped reserves relating to such locations are not material. We also advise that, as of December 31, 2020, we had approved drilling plans for 2021 that, when implemented, would extend the leases associated with our proved undeveloped reserves without requiring any additional steps or further costs to be incurred.
Properties
Drilling Activity, page 47
| 3. | Expand your disclosure to address your present activities, including the number of gross and net wells in the process of being drilled, completed, or waiting on completion and any other related activities of material importance as of December 31, 2020. Refer to the disclosure requirements in Item 1206 of Regulation S-K. |
Response: We respectfully advise the Staff that during the first quarter of 2020, we suspended our onshore drilling program and well completion operations for the remainder of the year due to the low and volatile commodity price environment for oil and natural gas. We suspended our offshore drilling program during the second quarter of 2020. As of December 31, 2020 and including up to the filing date of March 10, 2021, there were no wells being drilled, completed or waiting on completion or any other related activities of material importance.
Proved Undeveloped Reserves, page 52
| 4. | Please expand the disclosure relating to the conversion of your proved undeveloped reserves to provide the dollar amounts of capital expenditures made during the year to convert proved undeveloped reserves to proved developed reserves. Refer to Item 1203(c) of Regulation S-K and your response to comment 1 in our letter dated September 24, 2015. |
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 4
Response: We respectfully advise the Staff that during 2020, we incurred $164,000 (net) of capital expenditures converting proved undeveloped reserves to proved developed reserves. One gross location was brought on production in January 2020 and resulted in the conversion of 125 MBoe from proved undeveloped reserves to proved developed reserves. We substantially reduced our capital spend in 2020 in response to the severe economic uncertainty associated with the COVID-19 pandemic and the supply and demand imbalances in the oil and gas market. We acknowledge the Staff’s comment and intend in applicable future filings to more explicitly disclose the amount of capital expenditures made during the year to convert proved undeveloped reserves reported as of the prior year-end.
Proved Undeveloped Reserves, page 52
| 5. | Disclosure provided in Form 10-K for the fiscal years ending December 31, 2020, 2019, 2018, 2017 and 2016 indicates you converted approximately 1.0%, 3.4%, 5.5%, 0% and 0%, respectively, of the opening balance of your proved undeveloped reserves during each of those periods. Please tell us how you have taken into consideration your low historical conversion rates in adopting a development plan that results in the conversion of the 6,680 MBoe of proved undeveloped reserves as of December 31, 2020 within five years of initial disclosure of such reserves. Refer to Rule 4-10(a)(31)(ii) of Regulation S-X and the Question 131.04 in the Compliance and Disclosure Interpretations (C&DIs). |
Response: We acknowledge the Staff’s comment regarding low historic conversion rates of proved undeveloped reserves in fiscal years 2016-2020. As stated in our disclosure, our current business strategy is “… pursuing accretive, opportunistic acquisitions that meet our short-term and long-term strategic and financial objectives” (pg. 5). In addition, we disclosed our intent to “minimize our drilling program” and “… limit near-term drilling capital for the foreseeable future to that necessary to fulfill leasehold commitments, and preserve core acreage when appropriate, and where the opportunity exists, to drill on acquired acreage where we can add production and cash flow at attractive rates of return” (pg. 5).
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 5
In response to an ongoing low commodity price environment, we have continued to execute our strategy to minimize our drilling program. As a result of general economic and industry conditions and our strategic responses thereto, our drilling program associated with proved undeveloped locations was reduced from 58 gross locations across multiple regions (21 gross locations in West Texas; 35 gross locations in Southeast Texas; and two gross locations in South Texas and Wyoming) for the year ended December 31, 2019 to 32 gross locations at our NE Bullseye asset in West Texas (12 gross locations added and one location converted to proved developed) and two drilled, but uncompleted wells (“DUCs”) in our Mid-Continent region for the year ended December 31, 2020. Our adopted drilling program is conservative and reflects both our shift in business strategy and confidence in our financial ability to execute our adopted development program through future economic cycles.
Proved Undeveloped Reserves, page 52
| 6. | Please provide us with your development schedule, indicating for each future annual period, the number of gross wells to be drilled, the net quantities of reserves converted, and the estimated capital expenditures incurred resulting in the conversion of all of the proved undeveloped reserves disclosed as of December 31, 2020 to developed reserves. Refer to Rule 4-10(a)(31)(ii) of Regulation S-X. |
Response: As requested, please find below our current development schedule for each future annual period.
Fiscal Year | Gross | Net quantities of reserves converted (Mboe) | Estimated capital expenditures (net) ($M) | |||||||||
2021 | 5 | 895 | 11,209 | |||||||||
2022 | 6 | 1,367 | 19,078 | |||||||||
2023 | 11 | 2,519 | 35,519 | |||||||||
2024 | 11 | 1,788 | 25,601 | |||||||||
2025 | 1 | 110 | 1,683 | |||||||||
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Total | 34 | 6,680 | 93,090 | |||||||||
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 6
Note: The data provided for 2021 and 2022 includes two DUCs in our Mid-Continent region that were acquired as part of the White Star acquisition in the fourth quarter of 2019.
Exhibit Number 99.2 Report of W.D. Von Gonten and Company, page 80
| 7. | The reserve report does not include certain disclosures required by Item 1202 (a)(8) of Regulation S-K. Please obtain a revised report to address the following information in order to satisfy your filing obligations. Also refer to your response to comment 9 in our letter dated September 24, 2015. |
| • | The purpose for which the report was prepared (e.g. for inclusion as an exhibit in a filing made with the U.S. Securities and Exchange Commission (SEC) (Item 1202(a)(8)(i)). |
| • | The date on which the report was completed (Item 1202(a)(8)(ii)). |
| • | The proportion of the registrant’s total reserves covered by the report (Item 1202(a)(8)(iii) and the percentage of the registrant’s total reserves reviewed in connection with the preparation of the report (Item 1202(a) (8)(iv)). |
| • | A statement that the assumptions, data, methods, and procedures are appropriate for the purpose served by the report (Item 1202(a)(8)(iv)). |
| • | The average realized prices by product for the reserves included in the report as part of the discussion of primary economic assumptions (Item 1202(a)(8)(v)). |
| • | A statement that the third party has used all methods and procedures as it considered necessary under the circumstance to prepare the report (Item 1202(a)(8)(viii)). |
Response: W.D. Von Gonten and Company has delivered a revised reserve report as of December 31, 2020 addressing the foregoing comments, a copy of which is attached as Exhibit A hereto.
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 7
Exhibit Number 99.2 Report of W.D. Von Gonten and Company, page 80
| 8. | Disclosure of the “Reporting Requirements” provided on page 2 references the SPE PRMS and Rule 4-10 of Regulation S-X but appears to indicate that the estimated proved reserves shown in the report were prepared in conformance with the SPE definitions. Furthermore, the disclosure refers to regulations and standards under Item 102 of Regulation S-K and the Financial Accounting Standards Board (FASB) Statement No. 69 which have been updated pursuant to the Modernization of Oil and Gas Reporting; Final Rule. Please revise the disclosure to resolve these inconsistencies or tell us why a revision is not needed. |
Response: W.D. Von Gonten and Company has delivered a revised reserve report as of December 31, 2020 addressing the foregoing comments, a copy of which is attached as Exhibit A hereto.
Exhibits and Financial Statement Schedules
Exhibits
Exhibit Number 99.1 Report of William M. Cobb & Associates, Inc., page 80
| 9. | The reserve report does not include certain disclosures required by Item 1202(a)(8) of Regulation S-K. Please obtain a revised report to address the following information in order to satisfy your filing obligations. |
| • | The date on which the report was completed (Item 1202(a)(8)(ii)). |
Response: William M. Cobb & Associates, Inc. has delivered a revised reserve report as of December 31, 2020 addressing the foregoing comments, a copy of which is attached as Exhibit B hereto.
Exhibit Number 99.1 Report of William M. Cobb & Associates, Inc., page 80
| 10. | Disclosure on page 5 indicating that Cobb & Associates used the reserves definitions set forth in the SPE PRMS appears to be inconsistent with disclosure elsewhere on page 2 indicating the reserves estimates in the report were prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission and conform to the FASB Accounting Standards Codification Topic 932. Please revise the disclosure to resolve this inconsistency or tell us why a revision is not needed. |
Response: William M. Cobb & Associates, Inc. has delivered a revised reserve report as of December 31, 2020 addressing the foregoing comments, a copy of which is attached as Exhibit B hereto.
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 8
Exhibit Number 99.1 Report of William M. Cobb & Associates, Inc., page 80
| 11. | Please tell us, and if true, expand the disclosure in the revised report to clarify the extent to which the salvage value for the lease and well equipment and the costs of abandoning all of the properties have been included. Refer to Item 1202(a)(8)(iv) of Regulation S-K and your response to comment 7 in our letter dated September 24, 2015. |
Response: William M. Cobb & Associates, Inc. has delivered a revised reserve report as of December 31, 2020 addressing the foregoing comments, a copy of which is attached as Exhibit B hereto.
Exhibit Number 99.1 Report of William M. Cobb & Associates, Inc., page 80
| 12. | The reserve report refers to additional information contained in Appendix A and Appendix B that are not included as attachments to Exhibit 99.1. Please obtain and file a revised report to include the referenced attachments as supplemental information. Alternatively, remove these references if you do not intend to include this supplemental information in Exhibit 99.1. Also refer to your response to comment 8 in our letter dated September 24, 2015. |
Response: William M. Cobb & Associates, Inc. has delivered a revised reserve report as of December 31, 2020 addressing the foregoing comments, a copy of which is attached as Exhibit B hereto.
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 9
Supplemental Oil and Gas Disclosure (Unaudited)
Oil and Natural Gas Reserves, page F-44
| 13. | Please expand the discussion of the changes in the net quantities of your total proved reserves for each of the periods presented, including the year ended December 31, 2019, to clearly identify the source of each change consistent with the line items shown in your tabular reconciliation, e.g. revisions, improved recovery, extensions and discoveries, sales and acquisitions, and include an appropriate narrative explanation relating to each of the items you identify. To the extent that two or more unrelated factors are combined to arrive at the overall change for an item, your disclosure should separately identify and quantify each individual factor that contributed to a significant change so that the change in net reserve quantities between periods is fully explained. |
The disclosure of revisions in the previous estimates of your proved reserves in particular should identify the individual factors such as the changes caused by commodity prices, costs, 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 FASB ASC 932-235-50-5.
Response: We acknowledge the Staff’s comment and will expand the disclosure related to overall changes in total proved reserves between periods in applicable future filings of our Annual Report on Form 10-K, in particular to include further detail on uneconomic proved undeveloped locations or the removal of proved undeveloped locations due to changes in a previously adopted development plan.
For applicable future filings, we propose an expanded discussion as given below.*
During the year ended December 31, 2020, our proved reserves decreased by approximately 18.5 MMBoe, primarily due to a 21.1 MMBoe decrease related to negative revisions related to lower commodity prices. In response to an ongoing low commodity price environment, we continued to execute our strategy to minimize our drilling program throughout 2020. As a result, we removed 37 gross proved undeveloped locations (35 in Southeast Texas and one each in South Texas and Wyoming) representing 6.7 MMBoe (6.4 MMBoe from Southeast Texas and 0.3
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 10
MMboe from South Texas and Wyoming) from our development plan. Additional revisions include a 1.0 MMBoe decrease related to property sales in our Central Oklahoma (0.3 MMBoe) and Western Anadarko (0.7 MMBoe) regions and 2020 production of 6.1 MMBoe, partially offset by a 7.5 MMBoe increase related to positive performance revisions attributable to our success in lowering operating expenses, primarily in our Central Oklahoma (4.5 MMBoe) and West Texas regions (4.1 MMBoe), and a 2.3 MMBoe positive revision is attributable to 12 gross new PUD locations in our West Texas area resulting from the success of our 2019 drilling program.
*[Portions in italics represent additions to our prior disclosure.]
Oil and Natural Gas Reserves, page F-44
| 14. | We note disclosure on page 54 and in the reserve report filed as Exhibit 99.2 of the quantities of proved reserves and the estimated future net revenues attributable to your equity-method investment in Exaro as of December 31, 2020. However, we are unable to locate the Supplemental Oil and Gas Disclosure pursuant to FASB ASC 932 comparable to the disclosure provided for Exaro on pages F-37 through F-41 in your Form 10-K for the year ended December 31, 2019. Please tell us your rationale for omitting these disclosures in your current filing. Also refer to your response to comment 2 in our letter dated December 7, 2015. |
Response: The Company owns a 37% equity investment in Exaro, which owns a minor non-operated interest in a portion of the Jonah Gas Field in Sublette County, Wyoming. We account for that investment using the equity method and do not consolidate the results of operations of Exaro, or recognize our portion of the Exaro reserves in our financial statements. For the fiscal year ended December 31, 2019, the financial results and reserves of Exaro represented a more meaningful supplement to our financial results and reserves. We do not believe it is meaningful for the fiscal year ended December 31, 2020. Our Exaro investment became even less significant following our acquisitions of Mid-Con on January 21, 2021 and Silvertip on February 1, 2021. We filed pro forma financial statements for Mid-Con on March 10, 2021, which is the same day we filed our 2020 Annual Report. We filed pro forma financial statements for Silvertip on April 9, 2021.
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 11
Exaro’s results of operations, net assets and reserves were significantly below the 20% threshold (less than 10%) that would have triggered inclusion of those results in the footnotes to our 2020 audited financial statements under Regulation S-X. Given that measurement and our belief that our investment in Exaro is not meaningful to investors, we did not include Exaro financial statements and the supplemental disclosures were not included. Rather, we included a more abbreviated summary of Exaro’s proved reserves for reference. For the Commission’s consideration, our 37% equity interest in the PV10 value of Exaro’s year end 2020 reserves was only 3.8% of our PV10 value at December 31, 2020 and only 1.4% of the Company’s reserve value at year end 2020, giving pro forma effect to the Mid-Con and Silvertip acquisitions. Should the Company again be required to reflect the financial statements of Exaro in its financial statements pursuant to Regulation S-X, we will also include the Supplemental Oil & Gas Disclosure information in the corresponding applicable future filing as well.
We also respectfully request that the Commission consider the Company and New PubCo filed a joint Registration Statement on Form S-4 on July 26, 2021, related to the Transactions. Pursuant to the Transactions, New PubCo will apply for listing on the NYSE. If and when the Transactions are completed, the Company’s common stock currently listed on the NYSE American would cease to be listed on the NYSE American and will be deregistered under the Exchange Act, and the Company would no longer be required to file reports with the Commission pursuant to the Exchange Act, including the Supplemental Oil and Gas Disclosures for Exaro under Regulation S-X. Closing is expected to occur in the fourth quarter of 2021. Accordingly, we respectively submit to the Commission that, given our Exaro investment is not material to our investors, we believe requiring the Company to file an amended 2020 Annual Report for the sole purpose of including the supplemental Exaro disclosures provides no incremental benefit to the Company’s investors in their assessment of our value.
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 12
Please direct any questions concerning this letter to the undersigned at (713) 236-7575 or JGrady@contango.com.
Very truly yours,
/s/ E. Joseph Grady |
| E. Joseph Grady |
Senior Vice President and Chief Financial Officer
| cc: | Hillary H. Holmes, Gibson, Dunn & Crutcher LLP |
Charles L. McLawhorn, Senior Vice President, General Counsel and Corporate
Secretary
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 13
Exhibit A
[Updated W.D. Von Gonten and Company Report]
July 29, 2021
Mr. Joseph Grady
Senior Vice President
Contango Oil & Gas Company
717 Texas Ave, Ste. 2900
Houston, Texas 77002
Re: Engineering Evaluation
Estimate of Reserves & Revenues
Year End 2020 SEC Pricing
“As of” January 1, 2021
Dear Mr. Grady:
At your request, W.D. Von Gonten & Co. has estimated future reserves and projected net revenues attributable to certain oil and gas interests currently owned by Exaro Energy III, LLC (Exaro). Contango Oil & Gas Company (Contango) owns a portion of Exaro’s interest in these oil and gas assets and does not consolidate the reserves listed below with their own. This report was initially completed on January 26, 2021 and is being amended on July 29, 2021. The properties represented herein are located in the Jonah field of Sublette County, Wyoming. A summary of the discounted future net revenue attributable to Exaro’s Proven reserves, “As of” January 1, 2021, is as follows:
Year End 2020 SEC Pricing | Net to Exaro Energy III, LLC | |||||||||||||||
| Proved Developed Producing | Total Proved | |||||||||||||||
| New Wells | Old Wells | Total | ||||||||||||||
Reserve Estimates | ||||||||||||||||
Oil/Cond., Mbbl | 207.1 | 218.3 | 425.4 | 425.4 | ||||||||||||
Gas, MMcf | 16,240.4 | 23,641.7 | 39,882.2 | 39,882.2 | ||||||||||||
Gas Equivalent, MMcfe | 17,483.2 | 24,951.3 | 42,434.6 | 42,434.6 | ||||||||||||
Revenues | ||||||||||||||||
Oil, $ (15.8)% | 7,786,012 | 8,249,960 | 16,035,972 | 16,035,972 | ||||||||||||
Gas, $ (84.2)% | 30,815,028 | 54,433,304 | 85,248,328 | 85,248,328 | ||||||||||||
Total, $ | 38,601,040 | 62,683,264 | 101,284,300 | 101,284,300 | ||||||||||||
Expenditures | ||||||||||||||||
AdValorem Taxes, $ | 1,384,242 | 2,799,908 | 4,184,150 | 4,184,150 | ||||||||||||
Severance Taxes, $ | 1,490,000 | 2,983,723 | 4,473,723 | 4,473,723 | ||||||||||||
Direct Operating Expense, $ | 12,003,124 | 25,867,406 | 37,870,528 | 37,870,528 | ||||||||||||
Variable Operating Expense, $ | 12,003,101 | 17,183,949 | 29,187,046 | 29,187,046 | ||||||||||||
Total, $ | 26,880,467 | 48,834,986 | 75,715,447 | 75,715,447 | ||||||||||||
Investments | ||||||||||||||||
Capital, $ | 1,625,308 | 4,259,730 | 5,885,039 | 5,885,039 | ||||||||||||
Estimated Future Net Revenues(FNR) | ||||||||||||||||
Undiscounted FNR, $ | 10,095,265 | 9,588,539 | 19,683,804 | 19,683,804 | ||||||||||||
FNR Disc. @ 10%, $ | 6,524,855 | 7,673,112 | 14,197,970 | 14,197,970 | ||||||||||||
Allocation Percentage by Classification | ||||||||||||||||
FNR Disc. @ 10%, $ | 46.0 | % | 54.0 | % | 100.0 | % | ||||||||||
*Dueto computer rounding, numbers in the above table may not sum exactly. |
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Report Preparation
Purpose of Report – The original purpose of this report was to provide Exaro with a projection of future reserves and revenues attributable to certain Proved oil and gas interests presently owned. Subsequently, the purpose of this amended report is to provide Contango with a report to be included as an exhibit in a filing made by Contango with the U.S. Securities and Exchange Commission (SEC). W.D. Von Gonten & Co. has utilized all methods and procedures it considers necessary to prepare this report. The assumptions, data, methods, and procedures utilized have been deemed appropriate by us for the purpose served by this report. This report represents 100% of the oil and gas related assets owned by Exaro.
Scope of Report – W.D. Von Gonten & Co. was engaged by Exaro to estimate the reserves and revenues associated with the properties included in this report. Once reserves were estimated, future revenue projections were generated utilizing SEC pricing guidelines.
Reporting Requirements – The Society of Petroleum Engineers (SPE) requires Reserves to be economically recoverable with prices and costs in effect on the “as of” date of the report. In conjunction with World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), Society of Petroleum Evaluation Engineers (SPEE), Society of Exploration Geophysicists (SEG), Society of Petrophysicists and Well Log Analysts (SPWLA), and the European Associated of Geoscientists and Engineers (EAGE), the SPE has issued Petroleum Resources Management System (2018 ed.), which sets forth the definitions and requirements associated with the determination and classification of both Reserves and Resources. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information (2019 ed.), which sets requirements for the qualifications and independence of qualified reserves evaluators and auditors.
Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and Regulation S-X, Rule 4-10, and Financial Accounting Standards Board (FASB) Statement No. 69 requires oil and gas reserve information to be reported by publicly held companies as supplemental financial information. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% and based on constant prices and costs.
The estimated Proved Reserves herein have been prepared in conformance with all definitions and requirements in the above referenced publications, rules, and requirements.
Projections – The attached reserve and revenue projections are on a calendar year basis with the first time period being January 1 through December 31, 2021.
Property Discussion
Exaro signed an Earning and Development Agreement (EDA) with Ovintiv Inc. (Ovintiv), previously known as Encana Oil & Gas, in April 2012 that allowed them to gradually obtain increasing levels of ownership in the Jonah field. As part of the EDA, Exaro’s interest in each well drilled prior to the April 2012 agreement (old Proved Developed Producing (PDP) wells) continued to increase as Ovintiv drilled additional wells (new wells) within the field. Exaro’s interest in the new wells stayed constant for the life of each well. For each new well drilled within the EDA, Exaro paid for 100% of the capital costs and earned 32.5% of Ovintiv’s interest in the new wellbore until Exaro was fully earned into their devoted interest. In addition, for each new well drilled, Exaro earned 0.40% interest in the old PDP wells and related leasehold if Ovintiv’s working interest in the new well location was 100% and a proportional share if not.
As of the date of this report, Ovintiv has sold its ownership to Jonah Energy, LLC (Jonah Energy). Exaro notified Jonah Energy of its intent to terminate the EDA effective May 12, 2014, and thereafter participate under the existing Joint Operating Agreements (JOA’s) going forward. Exaro currently has no locations left under the EDA.
Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – July 29, 2021 – Page 2
Production in this area is primarily from the Lance sand which can range from 8,000’ to 11,000’ in depth and approach 3000’ in gross interval thickness.
Beginning in 2014, Jonah Energy began drilling horizontal wells across the eastern sections of Exaro’s acreage. To date, there are six horizontal wells currently producing.
Starting in February 2015, Jonah Energy began line pressure reduction projects in the field on varying groups of wells. They started by lowering the pressure from 200 psi to 50 psi in seventeen wells located in section 35. Lowering the pressure caused an increase to the production rate and reserves on most of the connected wells. Based on provided daily production data, W.D. Von Gonten & Co. was able to assign these wells a minor uplift. Jonah Energy has since begun and maintained several similar projects throughout Exaro’s acreage.
Figure 1 displays the comparison of Exaro’s historical monthly net production and W.D. Von Gonten & Co.’s forecasted net monthly production beginning January 1, 2021.
Figure 1: Historical Net Production and PDP Reserves Forecast as of January 1, 2021
Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – July 29, 2021 – Page 3
Figure 2 below is a graphical comparison of Exaro’s October 2019 through September 2020 historical net revenue and W.D. Von Gonten & Co.’s forecasted net revenue beginning January 1, 2021.
Figure 2: Historical Net Revenue and Forecasted Net Revenue as of January 1, 2021
Reserves Discussion
Reserves estimates represented herein were generally determined through the implementation of various methods including, but not limited to, performance decline, analogy, and type curve analysis. Based on the amount of available data, one or more of the above methods was utilized as deemed appropriate. Reserves and schedules of production included in this report are only estimates. The amount of available data, reservoir and geological complexity, reservoir drive mechanism, and mechanical aspects can have a material effect on the accuracy of these reserve estimates. Due to inherent uncertainties in future production rates, commodity prices, and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom, and/or the actual costs incurred could be more or less than the estimated amounts.
Product Prices Discussion
SEC pricing is determined by averaging the first day of each month’s closing price for the previous calendar year using published benchmark oil and gas prices. This method, as applied for the purposes of this report, renders a price of $39.54 per barrel of oil and $2.03 per MMBtu of gas. These prices were held constant throughout the life of the properties as per SEC guidelines.
Pricing differentials were applied on a field basis to reflect the actual prices received at the wellhead. Differentials typically account for transportation costs, geographical differentials, marketing bonuses or deductions, and any other factors that may affect the price actually received at the wellhead. W.D. Von Gonten & Co. determined the historical pricing differentials from lease operating data provided by Exaro representing the time period October 2019 through September 2020. The average realized prices for the new wells are $37.59 per barrel of oil and $1.897 per mcf of gas while the average realized prices for the old wells are $37.80 per barrel of oil and $2.302 per mcf of gas.
Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – July 29, 2021 – Page 4
Figures 3 and 4 illustrate the comparison between historical differentials versus those projected.
Figure 3: Historical and Forecasted Oil Differential
Figure 4: Historical and Forecasted Gas Differential
W.D. Von Gonten & Co. has included the historical NGL revenue and processing fees within the gas price differential for the new wells only. Due to existing and new contracts, the old wells do not include any NGL revenues or fees.
Operating Expenses and Capital Costs Discussion
Projected monthly operating expenses associated with the Jonah properties were based on the review of lease operating data provided by Exaro for the time period October 2019 through September 2020. Using the supplied data, W.D. Von Gonten & Co. applied a gross direct expense to each well on an individual basis. The horizontal wells have an increased monthly expense compared to vertical wells based on historical observations. A gross variable deduct, which covers gathering fees, has been applied to all wells. In addition, a salt water disposal (SWD) expense supplied by Exaro has been applied to each well. All direct and variable operating expenses were held constant for the economic life of each property.
Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – July 29, 2021 – Page 5
Figure 5 below is a graphical comparison of historical net lease operating expenses for October 2019 through September 2020 versus comparable forecasted expenses for the subsequent twelve months. June 2020 is showing a negative expense which can be attributed to the SWD.
Figure 5: Historical and Forecasted Lease Operating Expense
There are no capital costs associated with any of the properties included herein. Currently, Exaro has no knowledge of anticipated work efforts scheduled by the operator.
Other Considerations
Abandonment Costs – Cost estimates regarding future plugging and abandonment liabilities associated with these properties were supplied by Exaro for the purposes of this report. As we have not inspected the properties personally, W.D. Von Gonten & Co. expresses no warranties as to the accuracy or reasonableness of these assumptions. A third party study would be necessary in order to accurately estimate all future abandonment liabilities.
Data Sources – Data furnished by Exaro included basic well information, lease operating statements, ownership, pricing, and production information on certain leases. IHS Energy archives was utilized to view the monthly production for some of the wells included in this report.
Context – We specifically advise that any particular reserve estimate for a specific property not be used out of context with the overall report. The revenues and present worth of future net revenues are not represented to be market value either for individual properties or on a total property basis.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2021 estimated oil and gas volumes. The reserves in this report can be produced under current regulatory guidelines. Actual future commodity prices may differ substantially from the utilized pricing scenario which may or may not extend or limit the estimated reserves and revenue quantities presented in this report.
Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – July 29, 2021 – Page 6
We have not inspected the properties included in this report, nor have we conducted independent well tests. W.D. Von Gonten & Co. and our employees have no direct ownership in any of the properties included in this report. Our fees are based on hourly expenses, and are not related to the reserve and revenue estimates produced in this report. The responsible technical personnel referenced below have obtained the qualifications and meet the requirements of objectivity for Qualified Reserves Evaluator employed internally by W.D. Von Gonten & Co. as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information (2019 ed.) promulgated by the SPE.
Thank you for the opportunity to assist Exaro Energy III, LLC with this project.
 | Respectfully submitted,
| |||
| Phillip Hunter, P.E. | ||||
| TX #96590 | ||||
| ||||
| Jamie Foster | ||||
Reviewed by: | ||||
| ||||
W.D. Von Gonten, Jr., P.E. | ||||
| TX #73244 |
Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – July 29, 2021 – Page 7
U.S. Securities and Exchange Commission
Division of Corporation Finance
Office of Energy & Transportation
August 5, 2021
Page 14
Exhibit B
[Updated William M. Cobb & Associates, Inc. Report]
Worldwide Petroleum Consultants
| 12770 Coit Road, Suite 907 | (972) 385-0354 | |
| Dallas, Texas | Fax: (972) 788-5165 | |
| E-Mail: office@wmcobb.com |
July 29, 2021
Mr. Chad Roller
Contango Oil & Gas Company
717 Texas Avenue, Suite 2900
Houston, TX 77002
Dear Mr. Roller:
In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of January 1, 2021, attributable to the interest of Contango Oil & Gas Company and its subsidiaries (Contango) in certain oil and gas properties located in Oklahoma, Texas, Louisiana, state and federal waters of the Gulf of Mexico, Wyoming, Mississippi, and Kansas. This report was completed on February 25, 2021 and minor revisions to the wording were made on July 29, 2021.
Reserves presented in this report are classified as proved and are further categorized as proved developed producing (PDP), proved non-producing (PNP), proved shut-in (PSI), and proved undeveloped (PUD). Table 1 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscounted and discounted at ten percent using SEC pricing.
TABLE 1
CONTANGO OIL AND GAS COMPANY
TOTAL PROVED RESERVES AND CASH FLOW SUMMARY
AS OF JANUARY 1, 2021
YEAR-END 2020 SEC PRICE
| Net Reserves | Future Net Cash Flow | |||||||||||||||||||
Reserves Category | Oil (MBBL) | Gas (MMCF) | NGL (MBBL) | Undisc. (M$) | Disc. 10% (M$) | |||||||||||||||
PDP | 7,163 | 82,257 | 6,562 | 158,852 | 111,943 | |||||||||||||||
PNP | 4 | 531 | 32 | 202 | 160 | |||||||||||||||
PSI | 0 | 0 | 0 | 0 | 0 | |||||||||||||||
PUD | 5,838 | 1,694 | 559 | 49,548 | 14,273 | |||||||||||||||
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TOTAL PROVED | 13,004 | 84,482 | 7,154 | 208,602 | 126,376 | |||||||||||||||
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Values shown were determined utilizing constant oil and gas prices and well operating expenses. The discounted present worth of future income values shown in Table 1 are not intended to represent an
Mr. Chad Roller
July 29, 2021
Page 2
estimate of fair market value. These estimates were prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Certification Topic 932, Extraction Activities – Oil and Gas.
Reserve and cash flow summary projections for total proved reserves by category, a one-line summary for total proved reserves by category, a cash flow and one-line summary of reserves by region, field and reserve category have been delivered separately to Contango in support of this report.
Oil and NGL volumes are expressed in thousands of stock tank barrels (MBBL). A stock tank barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of standard cubic feet (MMCF) as determined at 60o Fahrenheit and the legal pressure base for the specific location of the gas reserves.
Cobb & Associates reviewed 100 per cent of the properties included in this report. This report, which was prepared for Contango’s use in filing with the SEC and will be filed with Contango’s Form 10-K for fiscal year ending December 31, 2020 (the “Form 10-K”) and covers 100 percent of the total company present value discounted at ten percent (PV10) presented in Contango’s Form 10-K. All assumptions, data, methods, and procedures considered necessary and appropriate were used to prepare this report.
DISCUSSION
The Contango properties are divided into five regions: Central Oklahoma, Offshore, Onshore, Western Anadarko, and West Texas. The Central Oklahoma and Western Anadarko properties are located in Oklahoma and north west Texas and 47.5 and 12.5 percent, respectively, of the total proved discounted present value are attributable to these properties. These properties were acquired from White Star Petroleum and Will Energy in late 2019. The onshore properties are located in Louisiana, Mississippi, east Texas, and Wyoming and make up 5.3 percent of the total proved discounted value. The offshore properties are located in Louisiana state and federal waters of the Gulf of Mexico and contribute 7.5 percent of the total proved discounted value. The west Texas properties are located in Pecos County in the Delaware Basin and provide 27.2 percent of the total proved discounted value.
Reserve estimates were prepared using generally accepted petroleum engineering principles and practices. The method, or combination of methods, utilized in the study of each property or reservoir included an assessment of the stage of reservoir development, quality of data, and length of production history. Geologic and engineering data was obtained from Contango, public sources, and the non-confidential files of Cobb & Associates.
Performance data through December of 2020 was used to forecast reserves for all producing properties where available. Reserve classification was based on the status of each well as of January 1, 2021 for operated wells, and on the most recently available information for non-operated wells.
For most regions in the report, the PDP reserve estimates were based on decline curve analysis. Some of the properties have produced for only a short period of time and did not exhibit an identifiable performance decline trend. In these cases, reserve estimates were based primarily on geological interpretation, mapping, and analogy to offset producers. Past performance, and offsetting performance data were used to estimate behind pipe and undeveloped reserves. Fields where additional analysis or methodology was used for the reserve assignments are discussed in more detail. These fields include Eugene Island 11 and properties in west Texas.
Mr. Chad Roller
July 29, 2021
Page 3
Offshore - Eugene Island 11
Eugene Island 11 is located in federal and Louisiana state waters of the Gulf of Mexico, at a water depth of approximately 13 feet. Production is primarily from a single CibOp sand, the JRM-1 sand, at a depth of approximately 15,000 feet. The field was discovered in September, 2006 by the Contango Operators Dutch 1 well. Contango has since drilled four more wells, the Dutch 2, 3, 4 and 5, on Federal acreage. The Dutch 5 well is depleted and is scheduled for abandonment in December 2021.
Contango also has properties in Louisiana state waters in this field. These properties are referred to as the Mary Rose prospect. Five Mary Rose wells have been drilled to date. Four Mary Rose wells, numbers 1 through 4, have produced from the main CibOp sand. The Mary Rose 4 well is depleted and has been abandoned. The Mary Rose 3 is also depleted, with abandonment scheduled for December 2021.
The Mary Rose 5 well produced from a separate, and much smaller, CibOp reservoir that is now depleted. Abandonment of the Mary Rose 5 was completed in 2019.
Proved reserves for the Eugene Island 10 main CibOp sand are based on analysis of historical rate versus time decline curves and P/Z performance plots, supplemented by volumetric calculations of original-gas-in-place (OGIP) using all available well log and 3D seismic data. The reservoir has been effectively drilled to the lowest structural datum and no significant aquifer has been found. Performance to date indicates a depletion drive system.
All Dutch and Mary Rose wells now flow to compression on the ‘H’ platform, allowing for a decrease in producing flowing tubing pressures. This two-stage compression lowers line pressure to approximately 200 psi. There are no remaining capital or startup costs for compression on the ‘H’ platform. Abandonment costs were provided by Contango and scheduled at the end-of-project life for all wells and the ‘H’ platform.
West Texas – Bullseye and North East Bullseye
During 2017, Contango embarked on a drilling program for Wolfcamp Shale wells in Pecos County, Texas. In the Bullseye area, 14 wells have been drilled and completed and are carried as proved developed producing (PDP) in this report. In December 2019, Contango acquired additional acres and designated this as the north east Bullseye area. Four wells have been drilled and completed and are currently producing as of January 1, 2021 in the north east Bullseye area.
There are three prospective formations in the north east Bullseye area, from the deepest to the shallowest, these are the Wolfcamp B, Wolfcamp A, and the 2nd Bone Springs. One bench of wells in the Wolfcamp B and the 2nd Bone Springs have been planned as well as two benches of wells in the Wolfcamp A.
Traditional decline curve analysis has difficulty predicting the well-to-well interactions between long horizontal wells in the shale plays. As a result, to improve the long-term prediction of PUD reserves, advanced simulation software and automatic parameter variation within certain ranges based on the
Mr. Chad Roller
July 29, 2021
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estimated range and uncertainty in the reservoir and completion properties in the area was used to develop probabilistic history matches for the existing wells. The history matches were based on the optimal matches to oil, gas, and water production and bottom hole pressure data for each well.
The reservoir properties from these matches were then used to study the optimal well spacing for the north east Bullseye development. Based on the results from this study, the optimum well spacing was determined to be 1,100 ft in the Wolfcamp formation. With the available space in a typical unit with dimensions of one mile by two miles and the 1,100 ft well spacing there are space for five locations in the Wolfcamp A and four locations in the Wolfcamp B.
The second part of the simulation study assessed the well-to-well interactions in order to develop a type curve that accounted for these interactions. A model with an existing Wolfcamp A well and an existing Wolfcamp B well was used for this evaluation. A large number of simulations were run with different reservoir properties to generate a probabilistic reserve distribution for the Wolfcamp PUD locations. These were then analyzed and a P50 profile was generated for each location. These location profiles were then averaged to generate a type curve to be used for the Wolfcamp A and Wolfcamp B. Locations within the Contango five-year capital plan taking into account market uncertainty were booked as PUD reserves in this report.
OIL AND GAS PRICING
Projections of proved reserves contained in this report utilize constant product prices of $2.14 per MMBTU of gas and $39.57 per barrel of oil. These are the average first-of-month prices for the prior 12-month period for Henry Hub gas and West Texas Intermediate (WTI) oil. Appropriate oil and gas pricing differentials, residue gas shrink, NGL yields, and NGL pricing as a fraction of WTI were calculated for each field using 12 months of revenue data where available. After applying appropriate differentials for each property, the weighted average realized product prices for 2021 were $36.74 per barrel of oil and $1.87 per MCF of gas, resulting in average 2021 differentials of negative $2.83 per barrel and negative $0.27 per MCF.
OPERATING COSTS
Future operating costs for each of the Contango wells are held constant at current values for the life of the property. These costs were calculated using 12-month lease operating expense (LOE) statements provided by Contango. In general, the LOE statements for each of the properties were analyzed by field or production area. LOE data was available for most areas through the second quarter of 2020 for most areas. Each well was assigned a fixed monthly operating cost, variable costs for oil and gas, and water handling costs per produced barrel of water. Oil, gas, and NGL transportation and processing fees were also assigned to each well by product purchaser using net revenue data in a similar manner that product differentials were determined.
LOE data for the Eugene Island 11 properties was analyzed at a well level. Fixed operating costs were divided into three categories: producing well, non-producing well, and platform expenses. Non-producing wells are wells that are awaiting abandonment in 2021 and had costs attributable to insurance. Platform expenses include shared compression equipment rental and operating costs, pipeline costs, and other costs that were assigned to platform cost centers.
Mr. Chad Roller
July 29, 2021
Page 5
For the west Texas Delaware Basin properties, LOE was also analyzed at a well or cost center level. An additional water operating cost for shared water handling facilities was calculated and assigned per barrel of produced water.
CAPITAL & ABANDONMENT COSTS
Capital expenditures to recomplete behind-pipe zones in existing wells, re-activate or work over existing wells, drill new wells, and install production facilities were provided by Contango and appear to be reasonable.
Abandonment cost for Eugene Island 11 was included in the value calculations as it was supplied to Cobb & Associates by Contango as determined by a third party report. Apart from determining that the numbers looked reasonable, Cobb & Associates have not done a field visit or in any other way attempted to verify the abandonment estimates.
Abandonment costs for all onshore (all other properties in the report) properties have not been included in the economic evaluation. Contango’s assumption regarding onshore well abandonment has been that the equipment salvage value would be very close to the cost of abandonment. Cobb & Associates have not checked this assumption and a third party assessment of the properties would be required to assess the detailed salvage value and abandonment cost.
PROFESSIONAL GUIDELINES
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years, from known reservoirs under expected economic and operating conditions. Reserves are considered proved if economic productivity is supported by either actual production or conclusive formation tests.
Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves, but more certain to be recovered than possible reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
The reserve estimates shown in this report are those estimated to be recoverable in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X and the guidelines specified in Item 1202 (a)(8) of Regulation S-K of the U.S. Securities and Exchange Commission (SEC), and with the exception of the exclusion of future income taxes, conforms to the FASB Accounting Standards Codification Topic 932, Extractive Industries - Oil and Gas. The definitions for oil and gas reserves in accordance with SEC Regulation S-X are set forth in this report.
The reserves included in this report are estimates only and should not be construed as being exact quantities. Governmental policies, uncertainties of supply and demand, the prices actually received for the reserves, and the costs incurred in recovering such reserves, may vary from the price and cost assumptions in this report. Estimated reserves using price escalations may vary from values obtained using constant price scenarios. In any case, estimates of reserves, resources, and revenues may increase or decrease as a result of future operations.
Mr. Chad Roller
July 29, 2021
Page 6
Cobb & Associates has not examined titles to the appraised properties nor has the actual degree of interest owned been independently confirmed. The data used in this evaluation were obtained from Contango Oil & Gas Company and the non-confidential files of Cobb & Associates and were considered accurate.
We have not made a field examination of the Contango properties, therefore, operating ability and condition of the production equipment have not been considered. Also, environmental liabilities, if any, caused by Contango or any other operator have not been considered, nor has the cost to restore the property to acceptable conditions, as may be required by regulation, been taken into account.
In evaluating available information concerning this appraisal, Cobb & Associates has excluded from its consideration all matters as to which legal or accounting interpretation, rather than engineering, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and conclusions necessarily represent only informed professional judgments.
William M. Cobb & Associates, Inc. is an independent consulting firm founded in 1983. Its compensation is not contingent on the results obtained or reported. Frank J. Marek, a Registered Texas Professional Engineer and a senior technical advisor of William M. Cobb & Associates, Inc., is primarily responsible for overseeing the preparation of the reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977; member of the Society of Petroleum Engineers; member of the Society of Petroleum Evaluation Engineers; and 40 years of experience in estimating and evaluating reserve information and estimating and evaluating reserves.
Cobb & Associates appreciates the opportunity to be of service to you. If you have any questions regarding this report, please do not hesitate to contact us.
Sincerely,
WILLIAM M. COBB & ASSOCIATES, INC. Texas Registered Engineering Firm F-84 | ||
Frank J. Marek, P.E. Senior Vice President |  | |
Mr. Chad Roller
July 29, 2021
Page 7
|
Tor Meling Senior Vice President |
|
Andrea S. Mielcarek Reservoir Engineer |
FJM:ar
Attachments
M:\Contango\_YE 2020 RESERVES REVIEW\REPORT\MCF02252021