Talos Energy Inc 8-K, filed Sep 11, 2020
Talos Energy Inc. (TALO)
About this 8-K
Talos Energy Inc filed this 8-K on September 11, 2020.
Items reported
- Item 8.01: Other events
- Item 9.01: Financial statements and exhibits
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported):
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(I.R.S. Employer Identification No.) |
| |
||||
| (Address of principal executive offices) | (Zip Code) |
(Registrant’s telephone number, including area code)
Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class |
Trading Symbol(s) |
Name of Each Exchange on Which Registered | ||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
Explanatory Note
On March 2, 2020, Talos Energy Inc. (the “Company”) filed a Current Report on Form 8-K (the “Prior Report”) with the U.S. Securities and Exchange Commission (the “SEC”) announcing the consummation of a previously announced acquisition of the outstanding limited liability company interests in certain wholly owned subsidiaries (the “Acquisitions”) of each of ILX Holdings, LLC, a Delaware limited liability company (“ILX Holdings”), ILX Holdings II, LLC, a Delaware limited liability company (“ILX Holdings II”), ILX Holdings III, LLC, a Delaware limited liability company (“ILX Holdings III”) and Castex Energy 2014, LLC, a Delaware limited liability company (“Castex 2014” and, together with ILX Holdings, ILX Holdings II and ILX Holdings III, the “Riverstone Sellers”) and Castex Energy 2016, LP, a Delaware limited partnership (“Castex 2016” and, together with the Riverstone Sellers, the “Sellers”) pursuant to separate Purchase and Sale Agreements, dated as of December 10, 2019, as amended from time to time, between the Company, Talos Production Inc., a Delaware corporation (“Talos Production”), and each of the Sellers. The Acquisitions were consummated on February 28, 2020, with such Acquisitions having an effective date of July 1, 2019. The Prior Report was amended on May 13, 2020 to incorporate by reference and include, respectively, certain historical financial statements and pro forma financial information relating to the Acquisitions. This Current Report on Form 8-K is being filed to provide certain additional historical financial statements and pro forma financial information relating to the Acquisitions.
| Item 8.01 | Other Events. |
This Current Report includes the following historical financial statements as exhibits 99.1 through 99.4:
The historical audited consolidated financial statements of ILX Holdings, LLC and subsidiaries as of and for the year ended December 31, 2019, and the related notes thereto, together with the report of Deloitte & Touche LLP, independent auditors, concerning those statements and related notes, are filed herewith as Exhibit 99.1 and incorporated herein by reference.
The historical audited consolidated financial statements of ILX Holdings II, LLC and subsidiaries as of and for the year ended December 31, 2019, and the related notes thereto, together with the report of Deloitte & Touche LLP, independent auditors, concerning those statements and related notes, are filed herewith as Exhibit 99.2 and incorporated herein by reference.
The consolidated financial statements of Castex Energy 2014, LLC as of and for the fiscal years ended December 31, 2019 and 2018, and the related notes thereto, together with the report of BDO USA, LLP, independent auditor, concerning those statements and related notes, are filed herewith as Exhibit 99.3 and incorporated herein by reference.
The consolidated financial statements of Castex Energy 2016, LP as of and for the fiscal years ended December 31, 2019 and 2018, and the related notes thereto, together with the report of BDO USA, LLP, independent auditor, concerning those statements and related notes, are filed herewith as Exhibit 99.4 and incorporated herein by reference.
This Current Report includes the following pro forma financial information as Exhibit 99.5:
The unaudited pro forma condensed combined financial statements of the Company as of and for the year ended December 31, 2019, giving effect to the Acquisition and related financing transactions, is filed herewith as Exhibit 99.5 to this Current Report on Form 8-K and incorporated herein by reference.
This Current Report includes the following reserves information as Exhibits 99.6 and 99.7:
The Netherland, Sewell & Associates, Inc. reserve report of ILX Holdings, LLC as of December 31, 2019.
The Netherland, Sewell & Associates, Inc. reserve report of ILX Holdings II, LLC as of December 31, 2019.
2
| Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits.
| * | Filed herewith. |
3
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Date: September 11, 2020
| TALOS ENERGY INC. | ||
| By: | /s/ William S. Moss III | |
| Name: | William S. Moss III | |
| Title: | Executive Vice President, General Counsel and Secretary | |
4
Exhibit 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement Nos. 333-231925 on Form S-3 and 333-225058 on Form S-8 of Talos Energy Inc. of our report dated April 28, 2020, relating to the financial statements of ILX Holdings, LLC, appearing in this Current Report on Form 8-K of Talos Energy Inc. filed on September 11, 2020. We also consent to the reference to us under the heading “Experts” in such Registration Statements.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
September 11, 2020
Exhibit 23.2
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement Nos. 333-231925 on Form S-3 and 333-225058 on Form S-8 of Talos Energy Inc. of our report dated April 28, 2020, relating to the financial statements of ILX Holdings II, LLC, appearing in this Current Report on Form 8-K of Talos Energy Inc. filed on September 11, 2020. We also consent to the reference to us under the heading “Experts” in such Registration Statements.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
September 11, 2020
Exhibit 23.3
Consent of Independent Auditor
Talos Energy Inc.
Houston, Texas
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-231925) and Form S-8 (No. 333-225058) of Talos Energy Inc. of our report dated August 24, 2020, relating to the consolidated financial statements of Castex Energy 2014, LLC as of and for the years ended December 31, 2019 and 2018.
/s/ BDO USA, LLP
Houston, Texas
September 11, 2020
Exhibit 23.4
Consent of Independent Auditor
Talos Energy Inc.
Houston, Texas
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-231925) and Form S-8 (No. 333-225058) of Talos Energy Inc. of our report dated August 24, 2020, relating to the consolidated financial statements of Castex Energy 2016, LP as of and for the years ended December 31, 2019 and 2018.
/s/ BDO USA, LLP
Houston, Texas
September 11, 2020
Exhibit 23.5
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We consent to the incorporation by reference into the Registration Statements on Form S-3 (No. 333-231925) and Form S-8 (No. 333-225058) of Talos Energy Inc., of (i) our report dated September 10, 2020, containing information relating to ILX Holdings, LLC’s estimated reserves as of December 31, 2019, and (ii) all references to our firm or such reports included in such Registration Statements.
| NETHERLAND, SEWELL & ASSOCIATES, INC. | ||
| By: | /s/ Richard B. Talley, Jr. | |
| Richard B. Talley, Jr., P.E. Senior Vice President | ||
Houston, Texas
September 11, 2020
Exhibit 23.6
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We consent to the incorporation by reference into the Registration Statements on Form S-3 (No. 333-231925) and Form S-8 (No. 333-225058) of Talos Energy Inc., of (i) our report dated September 10, 2020, containing information relating to ILX Holdings II, LLC’s estimated reserves as of December 31, 2019, and (ii) all references to our firm or such reports included in such Registration Statements.
| NETHERLAND, SEWELL & ASSOCIATES, INC. | ||
| By: | /s/ Richard B. Talley, Jr. | |
| Richard B. Talley, Jr., P.E. Senior Vice President | ||
Houston, Texas
September 11, 2020
Exhibit 99.1
ILX HOLDINGS, LLC
AND SUBSIDIARIES
Independent Auditors’ Report
Consolidated Financial Statements
as of and for the Year Ended
December 31, 2019
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| PAGE | ||||
| Independent Auditors’ Report |
1 | |||
| Consolidated Balance Sheet as of December 31, 2019 |
2 | |||
| Consolidated Statement of Operations for the year ended December 31, 2019 |
3 | |||
| Consolidated Statement of Changes in Members’ Capital for the year ended December 31, 2019 |
4 | |||
| Consolidated Statement of Cash Flows for the year ended December 31, 2019 |
5 | |||
| Notes to Consolidated Financial Statements |
6 | |||
| Supplementary Financial Information – Information about Oil and Gas Producing Activities – Unaudited |
17 | |||
INDEPENDENT AUDITORS’ REPORT
To ILX Holdings, LLC and Subsidiaries:
We have audited the accompanying consolidated financial statements of ILX Holdings, LLC and its subsidiaries (the “Company”), which comprise the consolidated balance sheet as of December 31, 2019, and the related consolidated statement of operations, changes in members’ capital, and cash flows for the year then ended, and the related notes to the consolidated financial statements (the “financial statements”).
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of ILX Holdings, LLC and its subsidiaries as of December 31, 2019, and the results of their operations, changes in their members’ capital and their cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matter
As discussed in Note 3 to the financial statements, on December 10, 2019, the Company entered into a purchase and sale agreement to sell the limited liability company interests in the Company’s wholly-owned subsidiaries that hold the Company’s working interests in all of its producing oil and gas properties, primary term acreage and prospects to Talos Production, Inc. in exchange for consideration comprising cash and newly issued convertible preferred stock of the parent company of Talos Production, Inc. The transaction closed on February 28, 2020. As a result, the Company classified the assets and liabilities of the subject interests as held for sale on the Company’s balance sheet as of December 31, 2019. Our opinion is not modified in respect of this matter.
Other Matter
Accounting principles generally accepted in the United States of America require that the Supplemental Oil, Natural Gas, and NGL Information be presented to supplement the financial statements. Such information, although not a part of the financial statements, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the financial statements, and other knowledge we obtained during our audits of the financial statements. We do not express an opinion or provide any assurance on the supplemental information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
/s/ Deloitte & Touche LLP
Parsippany, NJ
April 28, 2020
1
ILX HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(in thousands)
| December 31, 2019 | ||||
| Assets |
||||
| Current assets: |
||||
| Cash and cash equivalents |
$ | 25,589 | ||
| Production receivable |
11,892 | |||
| Due from affiliate (Note 4) |
51 | |||
| Other current assets |
490 | |||
| Current assets held for sale (Note 3) |
104,245 | |||
|
|
|
|||
| Total current assets |
142,267 | |||
| Other assets |
281 | |||
|
|
|
|||
| Total assets |
$ | 142,548 | ||
|
|
|
|||
| Liabilities and Members’ Capital |
||||
| Current liabilities: |
||||
| Due to operator |
$ | 7,398 | ||
| Accrued expenses |
3,244 | |||
| Derivative instrument liabilities |
2,580 | |||
| Other current liabilities |
896 | |||
| Current liabilities held for sale (Note 3) |
5,854 | |||
|
|
|
|||
| Total current liabilities |
19,972 | |||
|
|
|
|||
| Total liabilities |
19,972 | |||
|
|
|
|||
| Commitments and contingencies (Note 8) |
||||
| Members’ capital |
||||
| Capital contributions |
330,108 | |||
| Distributions |
(269,002 | ) | ||
| Retained earnings |
61,470 | |||
|
|
|
|||
| Total members’ capital |
122,576 | |||
|
|
|
|||
| Total liabilities and members’ capital |
$ | 142,548 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
2
ILX HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands)
| Year ended December 31, 2019 |
||||
| Revenue |
||||
| Oil and gas revenue |
$ | 106,161 | ||
| Overriding royalty interest revenue |
4,959 | |||
| Other revenue |
890 | |||
|
|
|
|||
| Total revenue |
112,010 | |||
|
|
|
|||
| Expenses |
||||
| Depletion and amortization |
26,282 | |||
| Operating expenses |
36,796 | |||
| Overhead reimbursement (Note 6) |
3,350 | |||
| General and administrative expenses |
3,173 | |||
| Other general expense |
625 | |||
|
|
|
|||
| Total expenses |
70,226 | |||
|
|
|
|||
| Income from operations |
41,784 | |||
| Other income (loss) |
||||
| Dividend income |
597 | |||
| Derivative instrument loss, net |
(6,014 | ) | ||
|
|
|
|||
| Total other loss |
(5,417 | ) | ||
|
|
|
|||
| Net income |
$ | 36,367 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
3
ILX HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF
CHANGES IN MEMBERS’ CAPITAL
(in thousands)
| Year ended December 31, 2019 |
||||
| Balance, January 1, 2019 |
$ | 154,609 | ||
| Capital contributions, net |
124 | |||
| Distributions |
(68,524 | ) | ||
| Net income |
36,367 | |||
|
|
|
|||
| Balance, December 31, 2019 |
$ | 122,576 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
4
ILX HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
| Year ended December 31, 2019 |
||||
| Cash flows from operating activities |
||||
| Net income |
$ | 36,367 | ||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||
| Depletion and amortization |
26,282 | |||
| Accretion expense |
357 | |||
| Unrealized derivative instrument loss, net |
2,927 | |||
| Changes in assets and liabilities: |
||||
| Increase in production receivable |
(1,738 | ) | ||
| Increase in due from affiliate |
(3 | ) | ||
| Decrease in other current assets and other assets |
2,459 | |||
| Increase in due to operator |
1,759 | |||
| Increase in accrued expenses |
1,937 | |||
| Increase in other current liabilities |
839 | |||
|
|
|
|||
| Net cash provided by operating activities |
71,186 | |||
|
|
|
|||
| Cash flows from investing activities |
||||
| Capital expenditures for oil and gas properties |
(11,460 | ) | ||
| Reimbursement from operator for capital expenditures |
1,759 | |||
| Decrease in salvage fund |
13,514 | |||
|
|
|
|||
| Net cash provided by investing activities |
3,813 | |||
|
|
|
|||
| Cash flows from financing activities |
||||
| Return of capital contributions |
(14,923 | ) | ||
| Distributions |
(53,477 | ) | ||
|
|
|
|||
| Net cash used in financing activities |
(68,400 | ) | ||
|
|
|
|||
| Net increase in cash and cash equivalents |
6,599 | |||
| Cash and cash equivalents, beginning of year |
18,990 | |||
|
|
|
|||
| Cash and cash equivalents, end of year |
$ | 25,589 | ||
|
|
|
|||
| Supplemental disclosure of non-cash investing activities |
||||
| Due to operators for accrued capital expenditures for oil and gas properties |
$ | 2,272 | ||
|
|
|
|||
| Supplemental disclosure of non-cash financing activities |
||||
| Distributions recycled as capital contributions |
$ | 15,047 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
5
ILX HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Company Structure
ILX Holdings, LLC (“ILX” or the “Company”), a Delaware limited liability company, was formed on July 27, 2010 and operates pursuant to the fourth amended and restated limited liability company agreement (the “LLC Agreement”) as of January 1, 2016 by and among Riverstone/Carlyle Global Energy and Power Fund IV (RW), L.P., a Delaware limited partnership, R/C Energy IV Ridgewood Partnership, L.P., a Delaware limited partnership, Riverstone Energy Coinvestment IV (U.S.), L.P., a Delaware limited partnership, and Carlyle Energy Coinvestment IV (U.S.), L.P., a Delaware limited partnership (each a “Member” and collectively, the “Members”). Pursuant to the LLC Agreement, the managing committee (the “Managing Committee”) of the Company has the power and authority to manage, direct and control the business, affairs and properties of the Company. The members of the Managing Committee are affiliates of Riverstone Holdings, LLC.
The Company entered into a participation agreement, as amended and restated on February 10, 2016, (the “Participation Agreement”) with Ridgewood Energy Corporation (“Ridgewood” or the “Manager”) to acquire certain interests in offshore Gulf of Mexico Federal oil and gas leases (the “ILX Leasehold Interests”) from and participate in joint exploration and development of such interests with, Ridgewood. Other than certain enumerated ILX Leasehold Interests, the Company is not required under the Participation Agreement to acquire from or make any investments with the Manager.
Ridgewood, ILX-Ridgewood I, LLC (“IREC I”), an affiliate of the Manager, and the Company entered into a management services agreement, as amended and restated on February 10, 2016 (the “Management Services Agreement”) pursuant to which Ridgewood provides certain management, administrative and technical services to the Company in connection with the ILX Leasehold Interests and is paid overhead reimbursement for such services. The Management Services Agreement does not require Ridgewood to provide any services to, or give it any authority to make decisions for, the Company related to the Company’s governance or management issues, including, without limitation, the Company’s distributions of cash or property, issuance or sales of membership interests, tax management, liquidations or mergers, appointment of officers or managers, compensation benefits or other employee related matters, or changes to governing documents.
With respect to the ILX Leasehold Interests, the Manager locates potential projects, conducts due diligence, negotiates and completes the transactions subject to the approval of the Company’s Managing Committee. The Manager manages the ILX Leasehold Interests, including exploration and development of oil and gas prospects on such ILX Leasehold Interests and performs all customary management related responsibilities regarding the ILX Leasehold Interests. The Manager also manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 6 and 8.
On February 28, 2020, the Company and Ridgewood entered into a side letter agreement (“Ridgewood Side Letter Agreement”) pursuant to which the Management Services Agreement was terminated as it relates to the ILX Leasehold Interests that were sold as described in Note 3 but remained in full force and effect as it relates to the Company and Ridgewood in order to assist the Company in satisfying its obligations relating to the ILX Leasehold Interests that were sold pursuant to the sale and purchase agreement described in Note 3. On March 24, 2020, Ridgewood, IREC I and the Company entered into a side letter agreement (“MSA Side Letter”) to memorialize the Ridgewood Side Letter Agreement and pursuant to which Ridgewood will continue to provide the services and other support to the Company required under the terms and conditions of the Management Services Agreement subsequent to the closing of the sale of the ILX Leasehold Interests on February 28, 2020 as described in Note 3. The MSA Side Letter also provided for the payment of $16.0 million to IREC I in complete satisfaction of the obligations of the Company under the Management Services Agreement to pay IREC I a profit participation upon the sale of the ILX Leasehold Interests, which constituted as disposition and complete exit under the terms of the Management Services Agreement. In addition, pursuant to the MSA Side Letter, the Company will no longer pay overhead reimbursement to the Manager effective July 1, 2020. The MSA Side Letter will remain in effect until the termination of the Management Services Agreement or the mutual written agreement of the parties. See Note 3. “Assets Held for Sale” for additional information on the sale of the ILX Leasehold Interests.
6
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company’s consolidated financial statements include the accounts of ILX and its subsidiaries. All intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to the Company or ILX are to ILX Holdings, LLC and its subsidiaries.
Use of Estimates
The preparation of consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenue and expense during the reporting period. Estimates included in the Company’s consolidated financial statements include those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates.
Fair Value Measurements
The Company follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its consolidated financial statements. The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. The Company’s derivative instruments are recorded at fair value based on Level 2 inputs. See “Derivative Instruments” below and Note 7. “Derivative Instruments” for additional information. The Company also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis.
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the consolidated balance sheet. As of December 31, 2019, the Company had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2019, the Company’s bank balances, which were maintained at Wells Fargo Bank, N.A, exceeded federally insured limits by $25.3 million. During 2019, the Company reclassified the salvage fund to cash and cash equivalents as a result of the sale of assets discussed in Note 3.
Salvage Fund
The Company deposits cash in a separate account, or salvage fund, to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its oil and gas properties at the end of their useful lives in accordance with applicable federal and state laws and regulations. The salvage fund is expected to be funded through amounts withheld from operating income. There are no restrictions on withdrawals from the salvage fund.
Investment in Delta House
The Company has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by Murphy Exploration & Production Company—USA. The investment in Delta House is valued using the measurement alternative to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. At each reporting period, the Company reviews its investment in Delta House to evaluate whether the investment is impaired. Additionally, upon classifying the investment in Delta House as held for sale, the Company reviewed its investment for impairment. During the year ended December 31, 2019, there were no impairments of the Company’s investment in Delta House.
7
Oil and Gas Properties
Through its consolidated wholly-owned subsidiaries, the Company invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Company’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.
Acquisition, exploration and development costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Company receives adjustments to certain projects from their respective operators upon review and audit of the projects’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred.
Once a property has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.
The Company may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties.
Overriding Royalty Interest (“ORRI”)
The Company has investments in the ORRIs of certain oil and natural gas properties. Such investments are classified as proved properties.
The Company’s oil and gas properties, including ORRIs, that are subject to the sale discussed in Note 3 are classified as “Current assets held for sale” on the Company’s consolidated balance sheet.
Accrued Expenses
Accrued expenses consist of the following:
| December 31, 2019 | ||||
| (in thousands) | ||||
| Accrued transaction costs |
$ | 2,322 | ||
| Accrued royalty |
595 | |||
| Accrued transportation expense |
259 | |||
| Accrued accounting and legal fees |
68 | |||
|
|
|
|||
| $ | 3,244 | |||
|
|
|
|||
Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Company recognizes the fair value of a liability for an asset retirement obligation in the period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Company’s credit-adjusted risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the year ended December 31, 2019:
| December 31, 2019 | ||||
| (in thousands) | ||||
| Balance, beginning of year |
$ | 5,362 | ||
| Accretion expense |
357 | |||
| Revision of estimates |
135 | |||
|
|
|
|||
| Balance, end of year |
$ | 5,854 | ||
|
|
|
|||
8
Accretion expense is included in the consolidated statement of operations within “Operating expenses”. The Company’s asset retirement obligations associated with the Company’s oil and gas properties that are the subject of the sale discussed in Note 3 are classified within “Current liabilities held for sale” on the Company’s consolidated balance sheet.
Revenue Recognition
The Company recognizes oil and gas revenue from contracts with customers at the point when control of oil and natural gas is transferred to the customer at an amount that reflects the consideration the Company expects to be entitled to in accordance with Accounting Standard Codification 606 Revenue from Contracts with Customers (“ASC 606”). The Company’s revenue recognition policies, performance obligations and significant judgements in applying ASC 606 are described below.
Oil and Gas Revenue
Generally, the Company sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. Natural gas liquid (“NGL”) sales are included within gas sales. The Company’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances.
In the first type of agreement, a netback agreement, the Company receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Company records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Company delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Company pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Company records the transportation expense within operating expenses in the consolidated statement of operations.
Under the Company’s natural gas processing contracts, the Company delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Company for the sale of NGLs. In this type of arrangement, the Company evaluates whether it is the principal or agent in the transaction. The Company concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Company recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded within operating expenses in the consolidated statement of operations.
In certain instances, the Company may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Company delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Company recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded within operating expenses in the consolidated statement of operations.
The Company assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Company satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Company’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery are reflected in revenue in the month payments are received.
Transaction Price Allocated to Remaining Performance Obligations
Under the Company’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer.
9
Contract Balances
The Company invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Company’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Company’s oil and gas revenue are included within “Production receivable” on the Company’s consolidated balance sheet.
Other Revenue
Other revenue is generated from the Company’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. The Company earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Company, thus there are no unsatisfied performance obligations. The Company’s project operator performs joint interest billing once the performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Company’s production handling, gathering and operating services agreement with an affiliated entity and other third parties does not give rise to contract assets or liabilities. The receivables related to the Company’s proportionate share of revenue from an affiliate are included within “Due from affiliate” on the Company’s consolidated balance sheet. The receivables related to the Company’s proportionate share of revenue from third parties are presented as a reduction from “Due to operator” on the Company’s consolidated balance sheet. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Company when the operator performs the joint interest billing of the lease operating expenses due from the Company.
Prior Period Performance Obligations
The Company records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Company records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Company has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. During the year ended December 31, 2019, revenue recognized from performance obligations satisfied in previous periods was not significant.
Overriding Royalty Interest Revenue
Overriding royalty interest revenue is generated from the Company’s override interests in certain oil and natural gas properties. ORRI revenue is recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and such proceeds are generally received by the Company within two to three months after the month in which production occurs. The Company is required to estimate the amount of ORRI revenue to be received based upon the Company’s ORRI interest. The Company records the difference between its estimates and the actual amounts received in the month that the payment is received from the producer. The Company has an estimation process for revenue and related accruals, and any identified difference between its ORRI revenue estimates and actual ORRI revenue historically has not been significant. The receivables related to the Company’s ORRI revenue are included within “Production receivable” on the Company’s consolidated balance sheet. During the year ended December 31, 2019, ORRI revenue recognized from performance obligations satisfied in previous periods was not significant.
Derivative Instruments
The Company may periodically utilize derivative instruments to manage the commodity price risk inherent in its oil and natural gas production. Derivative instruments are carried on the consolidated balance sheet at fair value and recorded as either an asset or liability. Changes in the fair value of the derivative instruments are recorded in earnings unless specific hedge accounting criteria are met. At this time, the Company has elected not to use hedge accounting for its derivative instruments and, accordingly, the derivative instruments are marked-to-market each reporting period with fair value gains and losses recognized as derivative instrument gain or loss on the consolidated statement of operations. The related cash flow impact of the derivative activities is reflected as cash flows from operating activities on the consolidated statement of cash flows. See Note 7. “Derivative Instruments” for additional information.
10
Impairment of Long-Lived Assets
The Company reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of the oil and gas properties may not be recoverable. Additionally, upon classifying its assets as held for sale, the Company reviewed its oil and gas properties for impairment. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.
There were no impairments of oil and gas properties during the year ended December 31, 2019.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and gas properties and investments in ORRIs are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs, costs to construct offshore platform and associated asset retirement costs, and investments in ORRIs.
Depletion and amortization was recorded through the date at which the Company’s oil and gas properties met held for sale criteria, which was December 10, 2019. Accumulated depletion and amortization associated with the Company’s oil and gas properties that are the subject of the sale discussed in Note 3 are classified within “Current assets held for sale” on the Company’s consolidated balance sheet.
Income Taxes
No provision is made for income taxes in the consolidated financial statements. The Company is a limited liability company, and as such, the Company’s income or loss is passed through and included in the tax returns of the Company’s Members. The Company files U.S. Federal and State tax returns and the 2016 through 2018 tax returns remain open for examination by tax authorities.
Income and Expense Allocation
Profits and losses are allocated to the Members in accordance with the LLC Agreement.
Recent Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on measurement of credit losses, which introduces, among other things, a new expected loss impairment model that applies to most financial assets measured at amortized cost and certain other instruments including trade and other receivables and other financial assets. Under the new accounting guidance, entities are required to estimate expected credit loss over the life of financial assets and record an allowance against the asset’s amortized cost basis to present the financial asset at the amount expected to be collected. The estimate of expected credit losses will require entities to incorporate considerations of historical information, current information and reasonable and supportable forecasts. The accounting guidance and the most recent update issued in February 2020 are effective for the Company in the first quarter of 2023 with early adoption permitted. The Company early adopted this accounting guidance and related updates on January 1, 2020 and the adoption did not have a material impact on the Company’s consolidated financial statements.
In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the consolidated balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance is effective for the Company beginning with the fiscal year ending December 31, 2021 with early adoption permitted. Although the Company, as a non-operator, does not enter into lease agreements to support its operations, the Company completed its evaluation of existing contracts that may have
11
a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Company early adopted this accounting guidance for the fiscal year ended December 31, 2019 and determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.
2. Oil and Gas Properties
The Company as well as Ridgewood-managed entities that co-invested alongside with the Company in the Beta Project elected not to participate in the drilling of the 8th well proposed by Walter Oil and Gas Corporation. As a result, the Company was due reimbursement for a portion of the cost relating to the slot on the Beta Project platform that was utilized by the other third-party working interest owners for the 8th well. On July 17, 2019, the Company and the other third-party working interest owners in the Beta Project agreed to a reimbursement to the Company of $1.8 million, which was recorded as a reduction to the Company’s oil and gas properties and classified within “Current assets held for sale” on the consolidated balance sheet as of December 31, 2019 and presented as “Reimbursement from operator for capital expenditures” in the investing section of the Company’s consolidated statement of cash flows for the year ended December 31, 2019.
3. Assets Held for Sale
On December 10, 2019, the Company entered into a purchase and sale agreement (the “PSA”) to sell the limited liability company interests in the Company’s wholly-owned subsidiaries that hold the Company’s working interests in all of its producing oil and gas properties, primary term acreage and prospects (the “Sold Assets”) to Talos Production, Inc. (the “Buyer”) for an unadjusted purchase price of $286.0 million, subject to purchase price and customary post-closing adjustments. The unadjusted purchase price consisted of $173.3 million in cash and 4,960,000 shares of common stock of the Buyer’s parent company. Pursuant to the PSA, the sale excluded financial instruments and working capital of the Company. The PSA was amended on February 24, 2020 to replace the common stock of the Buyer’s parent company with 49,600 Series A Convertible Preferred Stock (“Preferred Stock”) convertible into the Buyer’s parent common stock immediately at a rate of one share of Preferred Stock to 100 shares of common stock. The sale closed on February 28, 2020 and the Company received $128.6 million in cash net of purchase price adjustments as well as Preferred Stock with a value of $70.4 million. The Preferred Stock automatically converted into common stock on March 30, 2020. The sale resulted in a gain to the Company of approximately $100.3 million, subject to further post-closing adjustments.
The following table presents the details of the gain on the sale as of the closing date.
| February 28, 2020 | ||||
| (in thousands) | ||||
| Cash, net of purchase price adjustments |
$ | 128,554 | ||
| Preferred stock |
70,432 | |||
|
|
|
|||
| Total purchase price |
$ | 198,986 | ||
| Oil and gas properties, net |
$ | 102,660 | ||
| Investment in Delta House |
1,974 | |||
| Less: Asset retirement obligations |
(5,920 | ) | ||
|
|
|
|||
| Assets held for sale less related liabilities |
$ | 98,714 | ||
|
|
|
|||
| Gain on Sale |
$ | 100,272 | ||
|
|
|
|||
The Company has classified the Sold Assets and related liabilities as held for sale on the Company’s consolidated balance sheet as of December 31, 2019. General and administrative expenses totaling $2.3 million consist of financial advisory and legal fees related to the transaction are included within “General and administrative expenses” on the Company’s consolidated statement of operations.
The following table presents the carrying amounts of the Sold Assets and related liabilities classified as held for sale on the Company’s consolidated balance sheet.
| December 31, 2019 | ||||
| (in thousands) | ||||
| Assets: |
||||
| Investment in Delta House |
$ | 1,974 | ||
| Oil and gas properties: |
||||
| Proved properties |
269,396 | |||
| Less: accumulated depletion and amortization |
(167,125 | ) | ||
|
|
|
|||
| Total oil and gas properties, net |
102,271 | |||
|
|
|
|||
| Total current assets held for sale |
$ | 104,245 | ||
|
|
|
|||
| Liabilities: |
||||
| Asset retirement obligations |
$ | 5,854 | ||
|
|
|
|||
| Total current liabilities held for sale |
$ | 5,854 | ||
|
|
|
|||
12
4. Related Party Transaction
On December 10, 2019, as amended on February 24, 2020, the Company entered into a PSA with the Buyer to sell the limited liability company interests in the Company’s wholly-owned subsidiaries that hold the Company’s working interests in all of its producing oil and gas properties, primary term acreage and prospects as described in Note 3. The parties to the PSA are related parties. As described in Note 1, the Company is a controlled affiliate of Riverstone Holdings, LLC. As of December 10, 2019, certain entities controlled or affiliated with Riverstone Energy Partners V, L.P., an affiliate of Riverstone Holdings, LLC, beneficially owned and possessed voting power over approximately 27.5% of the issued and outstanding common stock of the Buyer’s parent company. Further, two directors that currently serve on the board of directors of the parent of the Buyer were appointed by affiliates of Riverstone Holdings, LLC. In addition, affiliates of the Company are party to certain other agreements with the parent of the Buyer.
A wholly-owned subsidiary of the Company and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with ILX Prospect Claiborne, LLC, a wholly-owned subsidiary of ILX Holdings II, LLC (“ILX II”) and an affiliate of the Company, and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility.
During the year ended December 31, 2019, the Company earned $0.2 million, representing its proportionate share of the production handling fees earned from ILX II, which is included within “Other revenue” on the Company’s consolidated statement of operations. As of December 31, 2019, the Company’s receivable of $0.1 million, related to the Company’s proportionate share of revenue from ILX II is included within “Due from affiliate” on the Company’s consolidated balance sheet. The receivable is settled by issuance of a non-cash credit from the Beta Project operator to the Company on behalf of the Producers when the operator performs the joint interest billing of the lease operating expenses due from the Company.
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
5. Members’ Capital and Distributions
Capital Contribution
Pursuant to the LLC Agreement, the Members may make capital contributions to the Company from time to time but will not be required to make any capital contributions. Additionally, certain distributable cash may be retained by the Company and recycled as capital contributions.
As of December 31, 2019, capital contributions totaled $330.1 million, which include $15.0 million of distributions that were recycled as capital contributions during 2019. During the year ended December 31, 2019, based upon the Company’s cash position and capital commitments, the Company returned capital totaling $14.9 million, which is presented as “Return of capital” in the financing section of the Company’s consolidated statement of cash flows for the year ended December 31, 2019.
Distributions
The Management Services Agreement requires that upon final determination of the amount of available cash as of the end of each calendar month, the Manager should promptly distribute such distributable cash. In accordance with the Management Services Agreement, distributions, if any, will be paid to the Company’s Members until such Members have received a return equal to the (i) capital investment in all of the ILX Leasehold Interests, plus (ii) the total of all management fees paid, plus (iii) a preferred eight percent compounded annual return on the amounts in (i) and (ii). Once the preferred return is received, IREC I will be entitled to twenty percent of the Company’s distributions, payable monthly (see “Ridgewood Profit Participation” below). During the year ended December 31, 2019, distributions to the Company’s Members of $15.0 million were recycled as capital contributions to the Company.
13
Ridgewood Profit Participation
The Management Services Agreement provides that IREC I is entitled to a share of the Company’s distributions only after certain conditions have been met. As of December 31, 2019, such conditions have not been met. See “Distributions” above for additional information.
On March 31, 2020, pursuant to the MSA Side Letter, the Company paid $16.0 million to IREC I in complete satisfaction of the obligations of the Company under the Management Services Agreement to pay IREC I a profit participation upon the sale of the ILX Leasehold Interests on February 28, 2020 as described in Note 3, which constituted as disposition and complete exit under the terms of the Management Services Agreement. See Note 1 for additional information on the MSA Side Letter.
6. Overhead Reimbursement
The Management Services Agreement provides that the Manager render management, administrative and technical services, for which it receives an annual overhead reimbursement, payable quarterly. During the year ended December 31, 2019, overhead reimbursement was $3.4 million. Pursuant to the MSA Side Letter, the Company will no longer pay overhead reimbursement to the Manager effective July 1, 2020. See Note 1 for additional information on the MSA Side Letter.
7. Derivative Instruments
In October 2017, the Company entered into fixed price swap contracts (“Swap”) with BP Energy Company (“BP”) and Shell Trading Risk Management LLC (“Shell”), effective October 1, 2017 through December 31, 2020 and November 1, 2017 through December 31, 2020, respectively, and with Shell in April 2019, effective May 1, 2019 through December 31, 2020 (collectively, the “Counterparties”), to hedge the Company’s exposure to commodity price fluctuations on a portion of oil production from the Company’s producing projects. The Company has elected not to use hedge accounting for its Swap and consequently, the Swap is marked-to-market each reporting period with fair value gains and losses recognized as derivative instrument gain or loss on the consolidated statement of operations. The estimated fair value of the Swap is based upon closing exchange prices for Light Louisiana Sweet Crude Oil available from Argus Media Group (“Argus LLS”). The Company has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment. The Company actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.
The Swap is carried at its fair value on the consolidated balance sheet and the assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty with the same current and noncurrent classification, and where the Company has master netting arrangements. The master netting arrangements allow for set-off that may be exercised in the event of default and provides for contract termination and net settlement. The Company determines the current and noncurrent classification of the Swap based on the timing of expected settlement of individual trades. The Swap is settled based upon reported prices on Argus LLS. The Swap is settled on a monthly basis.
As of December 31, 2019, the Company had outstanding position under the Swap as detailed in the following table.
| Production Period |
Index | Volume in barrels |
Weighted Average Fixed Price Swap per barrel |
Estimated Fair Value |
||||||||||||
| (in thousands) | ||||||||||||||||
| Liabilities: |
||||||||||||||||
| January 1, 2020 to December 31, 2020 |
Argus LLS | 548,300 | $ | 57.22 | $ | 2,580 | ||||||||||
14
The following table presents the fair value and classification of the outstanding position under the Swap on the Company’s consolidated balance sheet as of December 31, 2019 on a gross basis and after same-counterparty netting:
| December 31, 2019 | ||||||||||||
| Gross Amounts Recognized |
Gross Amounts Offset |
Net Amounts Presented |
||||||||||
| (in thousands) | ||||||||||||
| Current liabilities: |
||||||||||||
| Derivative instrument liabilities |
$ | 2,580 | $ | — | $ | 2,580 | ||||||
None of the Company’s derivative instruments have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the realized and unrealized losses on derivative instruments, which are included within “Derivative instrument loss, net” on the Company’s consolidated statement of operations.
| Year Ended December 31, 2019 |
||||
| (in thousands) | ||||
| Unrealized loss on derivative instruments, net |
$ | (2,927) | ||
| Realized loss on derivative instruments, net |
(3,087 | ) | ||
|
|
|
|||
| Derivative instrument loss, net |
$ | (6,014) | ||
|
|
|
|||
On January 10, 2020, the Company terminated its Swap with BP and Shell by making payment of $2.3 million to BP and receiving payment of $10 thousand from Shell. There is no Swap outstanding as a result of these terminations.
8. Commitments and Contingencies
Capital Commitments
As a result of the Company’s asset sale on February 28, 2020, the Company no longer has any capital commitments related to its oil and gas properties. See Note 3. “Assets Held for Sale” for additional information on asset sale. Based upon its current cash position, the Company expects it will have sufficient cash to cover its obligations and ongoing operations through the 12-month period from the issuance of the consolidated financial statements.
Other Contingencies
The operator was subject to litigation with a third-party, relating to change order requests for the Beta Project platform. The Company was not a named party to the lawsuit filed and was not a party to the litigation; however, under the operating agreement (“OA”) the Company is responsible for its proportionate share of costs of the litigation as well as any settlements made or judgement imposed upon the operator if the claim is based upon or arises from operations on the Beta Project. Under the OA, the settlement required the Company’s approval. In February 2020, the Company approved its proportionate share of the proposed settlement amount. The Company determined that the approval of the proposed settlement represented the culmination of conditions existing as of December 31, 2019, and as a result, the Company recorded its proportionate share of the settlement totaling $0.6 million within “Other general expense” on its consolidated statement of operations during the year ended December 31, 2019.
Environmental and Governmental Regulations
Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. As of December 31, 2019, there were no known environmental contingencies that required adjustment to, or disclosure in, the Company’s consolidated financial statements.
Neidermeyer Project Incident
In October 2017, the Neidermeyer Project was shut-in due to a leak in a subsea flowline caused by a fracture in a jumper pipe associated with one of the project’s wells. The incident resulted in an oil spill, however through the operator’s coordinated efforts with the Bureau of Safety and Environment Enforcement (“BSEE”), it was confirmed that the oil spill was fully contained. The Company has considered its potential for liabilities related to penalties and fines under the Clean Water Act and from BSEE and has concluded that a reasonable estimate of penalties and fines cannot be made at this time. As of December 31, 2019, there were no additional liability that required adjustment to, or disclosure in, the Company’s consolidated financial statements.
15
BOEM Notice to Lessees on Supplemental Bonding
On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of the review of NTL 2016-N01. As of December 31, 2019, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01.
Insurance Coverage
The Company is subject to all risks inherent in the oil and natural gas business. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. Insurance coverage for the Company’s oil and gas properties that are the subject of the sale discussed in Note 3 was terminated on February 28, 2020.
9. Subsequent Events
The Company has assessed the impact of subsequent events through the issuance of the consolidated financial statements on April 28, 2020 and has concluded that there were no such events, other than as noted in Note 1. “Organization and Summary of Significant Accounting Policies – Company Structure” related to the MSA Side Letter, Note 3. “Assets Held for Sale”, Note 5. “Members’ Capital and Distributions – Ridgewood Profit Participation”, Note 7. “Derivative Instruments”, Note 8. “Commitment and Contingencies – Other Contingencies” and below, that require adjustment to, or disclosure in, the consolidated financial statements.
Impact from the Coronavirus
The extent of the impact of the coronavirus (“COVID-19”) outbreak on the financial performance of the Company’s investment in the common stock of the parent of the Buyer it received as consideration for the Sold Assets and that it continues to hold will depend on future developments, including the duration and spread of the outbreak and related advisories and restrictions and the impact of COVID-19 on the financial markets and the overall economy, all of which are highly uncertain and cannot be predicted. As of April 28, 2020, the price of the common stock has significantly declined since December 31, 2019. If the financial markets and/or the overall economy are impacted for an extended period, the Company’s future investment results may be further materially adversely affected. The effect of this impact has not been reflected in these consolidated financial statements.
Distributions
On April 8, 2020, the Company made a distribution to its Members totaling $137.6 million, which included proceeds from the sale of assets discussed in Note 3.
16
ILX Holdings, LLC and Subsidiaries
Supplementary Financial Information
Information about Oil and Gas Producing Activities - Unaudited
In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Company. The Company is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of the Gulf of Mexico.
Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
| December 31, 2019 | ||||
| (in thousands) | ||||
| Proved properties |
$ | 269,396 | ||
| Accumulated depletion and amortization |
(167,125 | ) | ||
|
|
|
|||
| Oil and gas properties, net |
$ | 102,271 | ||
|
|
|
|||
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
| Year Ended December 31, 2019 |
||||
| (in thousands) | ||||
| Exploration costs |
$ | (18 | ) | |
| Development costs |
9,575 | |||
|
|
|
|||
| $ | 9,557 | |||
|
|
|
|||
Table III - Reserve Quantity Information
Oil and gas reserves of the Company have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2019. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.
| Oil (MBBL) |
NGL (MBBL) |
Gas (MMCF) |
Total (MBOE) (a) |
|||||||||||||
| Total proved reserves at December 31, 2018 |
8,583.8 | 3,016.3 | 27,266.4 | 16,144.5 | ||||||||||||
| Revisions of previous estimates (b) |
262.7 | (534.2 | ) | (5,228.3 | ) | (1,142.9 | ) | |||||||||
| Production |
(1,625.8 | ) | (246.8 | ) | (2,137.9 | ) | (2,228.9 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total proved reserves at December 31, 2019 |
7,220.7 | 2,235.3 | 19,900.2 | 12,772.7 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total proved developed reserves as of: |
||||||||||||||||
| December 31, 2019 |
5,843.3 | 1,336.8 | 11,869.0 | 9,158.3 | ||||||||||||
| Total proved undeveloped reserves as of: |
||||||||||||||||
| December 31, 2019 |
1,377.4 | 898.5 | 8,031.2 | 3,614.4 | ||||||||||||
| (a) | BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency. |
| (b) | Revisions of previous estimates were attributable to well performance. |
17
Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve
Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.
| December 31, 2019 | ||||
| (in thousands) | ||||
| Future cash inflows |
$ | 487,684 | ||
| Future production costs |
(122,571 | ) | ||
| Future development costs |
(40,941 | ) | ||
|
|
|
|||
| Future net cash flows |
324,172 | |||
| 10% annual discount for estimated timing of cash flows |
(76,969 | ) | ||
|
|
|
|||
| Standardized measure of discounted future net cash flows |
$ | 247,203 | ||
|
|
|
|||
Table V - Changes in the Standardized Measure for Discounted Cash Flows
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.
| Year ended December 31, 2019 |
||||
| (in thousands) | ||||
| Net change in sales and transfer prices and in production costs related to future production |
$ | (63,569) | ||
| Sales and transfers of oil and gas produced during the period |
(84,757 | ) | ||
| Changes in estimated future development costs |
13 | |||
| Net change due to revisions in quantities estimates |
(24,911 | ) | ||
| Accretion of discount |
37,561 | |||
| Other |
7,255 | |||
|
|
|
|||
| Aggregate change in the standardized measure of discounted future net cash flows for the year |
$ | (128,408) | ||
|
|
|
|||
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.
18
Exhibit 99.2
ILX HOLDINGS II, LLC
AND SUBSIDIARIES
Independent Auditors’ Report
Consolidated Financial Statements
as of and for the Year Ended
December 31, 2019
| INDEX TO CONSOLIDATED FINANCIAL STATEMENTS |
PAGE | |||
| Independent Auditors’ Report |
1 | |||
| Consolidated Balance Sheet as of December 31, 2019 |
2 | |||
| Consolidated Statement of Operations for the year ended December 31, 2019 |
3 | |||
| Consolidated Statement of Changes in Members’ Capital for the year ended December 31, 2019 |
4 | |||
| Consolidated Statement of Cash Flows for the year ended December 31, 2019 |
5 | |||
| Notes to Consolidated Financial Statements |
6 | |||
| Supplementary Financial Information – Information about Oil and Gas Producing Activities - Unaudited |
19 | |||
Independent Auditors’ Report
INDEPENDENT AUDITORS’ REPORT
To ILX Holdings II, LLC and Subsidiaries:
We have audited the accompanying consolidated financial statements of ILX Holdings II, LLC and its subsidiaries (the “Company”), which comprise the consolidated balance sheet as of December 31, 2019, and the related consolidated statement of operations, changes in members’ capital, and cash flows for the year then ended, and the related notes to the consolidated financial statements (the “financial statements”).
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of ILX Holdings II, LLC and its subsidiaries as of December 31, 2019, and the results of their operations, changes in their members’ capital and their cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matter
As discussed in Note 3 to the financial statements, on December 10, 2019, the Company entered into a purchase and sale agreement to sell the limited liability company interests in the Company’s wholly-owned subsidiaries that hold the Company’s working interests in all of its producing oil and gas properties. and certain primary term acreage and prospects to Talos Production, Inc. in exchange for consideration comprising cash and newly issued convertible preferred stock of the parent company of Talos Production, Inc. The transaction closed on February 28, 2020. As a result, the Company classified the assets and liabilities of the subject interests as held for sale on the Company’s balance sheet as of December 31, 2019. Our opinion is not modified in respect of this matter.
Other Matter
Accounting principles generally accepted in the United States of America require that the Supplemental Oil, Natural Gas, and NGL Information be presented to supplement the financial statements. Such information, although not a part of the financial statements, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the financial statements, and other knowledge we obtained during our audits of the financial statements. We do not express an opinion or provide any assurance on the supplemental information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
/s/ Deloitte & Touche LLP
Parsippany, NJ
April 28, 2020
1
ILX HOLDINGS II, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(in thousands)
| December 31, 2019 | ||||
| Assets |
||||
| Current assets: |
||||
| Cash and cash equivalents |
$ | 57,897 | ||
| Production receivable |
11,338 | |||
| Other current assets |
2,520 | |||
| Current assets held for sale (Note 3) |
232,122 | |||
|
|
|
|||
| Total current assets |
303,877 | |||
| Other assets |
2,936 | |||
| Oil and gas properties: |
||||
| Advances to operators for working interests and expenditures |
294 | |||
| Unproved properties |
36,329 | |||
| Proved properties |
124,269 | |||
|
|
|
|||
| Total oil and gas properties |
160,892 | |||
|
|
|
|||
| Total assets |
$ | 467,705 | ||
|
|
|
|||
| Liabilities and Members’ Capital |
||||
| Current liabilities: |
||||
| Due to operator |
$ | 7,336 | ||
| Due to affiliate |
51 | |||
| Accrued expenses |
3,383 | |||
| Derivative instrument liabilities |
534 | |||
| Other current liabilities |
100 | |||
| Current liabilities held for sale (Note 3) |
15,871 | |||
|
|
|
|||
| Total current liabilities |
27,275 | |||
| Asset retirement obligations |
1,474 | |||
| Derivative instrument liabilities |
496 | |||
|
|
|
|||
| Total liabilities |
29,245 | |||
|
|
|
|||
| Commitments and contingencies (Note 10) |
||||
| Members’ capital |
||||
| Capital contributions |
970,204 | |||
| Distributions |
(343,773 | ) | ||
| Accumulated deficit |
(187,971 | ) | ||
|
|
|
|||
| Total members’ capital |
438,460 | |||
|
|
|
|||
| Total liabilities and members’ capital |
$ | 467,705 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
2
ILX HOLDINGS II, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands)
| Year ended December 31, 2019 |
||||
| Revenue |
||||
| Oil and gas revenue |
$ | 153,446 | ||
| Expenses |
||||
| Depletion and amortization |
78,091 | |||
| Impairment of oil and gas properties |
12,603 | |||
| Operating expenses |
39,679 | |||
| Overhead reimbursement (Note 7) |
3,350 | |||
| General and administrative expenses |
3,412 | |||
|
|
|
|||
| Total expenses |
137,135 | |||
|
|
|
|||
| Income from operations |
16,311 | |||
| Other income (loss) |
||||
| Derivative instrument gain, net |
1,108 | |||
| Interest expense |
(2,919 | ) | ||
|
|
|
|||
| Total other loss |
(1,811 | ) | ||
|
|
|
|||
| Net income |
$ | 14,500 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
3
ILX HOLDINGS II, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF
CHANGES IN MEMBERS’ CAPITAL
(in thousands)
| Year ended December 31, 2019 |
||||
| Balance, January 1, 2019 |
$ | 464,960 | ||
| Capital contributions |
78,588 | |||
| Distributions |
(119,588 | ) | ||
| Net income |
14,500 | |||
|
|
|
|||
| Balance, December 31, 2019 |
$ | 438,460 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
4
ILX HOLDINGS II, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
| Year ended December 31, 2019 |
||||
| Cash flows from operating activities: |
||||
| Net income |
$ | 14,500 | ||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||
| Depletion and amortization |
78,091 | |||
| Amortization of deferred financing costs |
891 | |||
| Impairment of oil and gas properties |
12,603 | |||
| Amortization of prepaid production handling fees |
2,215 | |||
| Accretion expense |
1,196 | |||
| Unrealized derivative instrument loss, net |
1,131 | |||
| Changes in assets and liabilities: |
||||
| Decrease in production receivable |
1,016 | |||
| Increase in other current assets and other assets |
(254 | ) | ||
| Increase in due to operator |
562 | |||
| Increase in due to affiliate |
40 | |||
| Increase in accrued expenses |
2,001 | |||
| Increase in other current liabilities |
40 | |||
|
|
|
|||
| Net cash provided by operating activities |
114,032 | |||
|
|
|
|||
| Cash flows from investing activities: |
||||
| Payments to operators for working interests and expenditures |
(367 | ) | ||
| Capital expenditures for oil and gas properties |
(61,387 | ) | ||
| Decrease in salvage fund |
13,065 | |||
|
|
|
|||
| Net cash used in investing activities |
(48,689 | ) | ||
|
|
|
|||
| Cash flows from financing activities: |
||||
| Distributions |
(41,000 | ) | ||
|
|
|
|||
| Net cash used in financing activities |
(41,000 | ) | ||
|
|
|
|||
| Net increase in cash and cash equivalents |
24,343 | |||
| Cash and cash equivalents, beginning of year |
33,554 | |||
|
|
|
|||
| Cash and cash equivalents, end of year |
$ | 57,897 | ||
|
|
|
|||
| Supplemental disclosure of non-cash investing activities |
||||
| Advances used for capital expenditures in oil and gas properties reclassified to proved properties |
$ | 177 | ||
|
|
|
|||
| Supplemental disclosure of non-cash financing activities |
||||
| Distributions recycled as capital contributions |
$ | 78,588 | ||
|
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
5
ILX HOLDINGS II, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Company Structure
ILX Holdings II, LLC (“ILX II” or the “Company”), a Delaware limited liability company, was formed on January 16, 2013 and operated pursuant to the amended and restated limited liability company agreement (the “LLC Agreement”) as of January 1, 2016 by and among Riverstone Global Energy and Power Fund V (RW II), L.P., a Delaware limited partnership, Riverstone Energy V Ridgewood Partnership, L.P., a Delaware limited partnership, and Riverstone Energy Coinvestment V (U.S.), L.P., a Delaware limited partnership (each a “Former Member” and collectively, the “Former Members”). On April 26, 2017, the Company amended and restated the LLC Agreement (the “Amended and Restated LLC Agreement”) whereby the Former Members entered into a contribution agreement to contribute their entire interests in the Company to a new aggregator partnership, Riverstone V Ridgewood II Partnership, L.P. (“Riverstone V” or “Member”) and the Former Members withdrew as members of the Company. Pursuant to the LLC Agreement, the managing committee (the “Managing Committee”) of the Company has the power and authority to manage, direct and control the business, affairs and properties of the Company. The members of the Managing Committee are affiliates of Riverstone Holdings, LLC.
The Company entered into a participation agreement, as amended and restated on February 10, 2016, (the “Participation Agreement”) with Ridgewood Energy Corporation (“Ridgewood” or the “Manager”) to acquire certain interests in offshore Gulf of Mexico Federal oil and gas leases (the “ILX II Leasehold Interests”) from and participate in joint exploration and development of such interests with, Ridgewood. Other than certain enumerated ILX II Leasehold Interests, the Company is not required under the Participation Agreement to acquire from or make any investments with the Manager.
Ridgewood, ILX-Ridgewood II, LLC (“IREC II”), an affiliate of the Manager, and the Company entered into a management services agreement, as amended and restated on February 10, 2016, (the “Management Services Agreement”) pursuant to which Ridgewood provides certain management, administrative and technical services to the Company in connection with the ILX II Leasehold Interests and is paid overhead reimbursement for such services. The Management Services Agreement does not require Ridgewood to provide any services to, or give it any authority to make decisions for, the Company related to the Company’s governance or management issues, including, without limitation, the Company’s distributions of cash or property, issuance or sales of membership interests, tax management, liquidations or mergers, appointment of officers or managers, compensation benefits or other employee related matters, or changes to governing documents.
With respect to the ILX II Leasehold Interests, the Manager locates potential projects, conducts due diligence, negotiates and completes the transactions subject to the approval of the Company’s Managing Committee. The Manager manages the ILX II Leasehold Interests, including exploration and development of oil and gas prospects on such ILX II Leasehold Interests and performs all customary management related responsibilities regarding the ILX II Leasehold Interests. The Manager also manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 5, 7 and 10.
On February 28, 2020, the Company and Ridgewood entered into a side letter agreement (“Ridgewood Side Letter Agreement”) pursuant to which the Management Services Agreement was terminated as it relates to the ILX II Leasehold Interests that were sold as described in Note 3 but remained in full force and effect as it relates to the Company and Ridgewood in order to assist the Company in satisfying its obligations relating to the ILX II Leasehold Interests that were sold pursuant to the sale and purchase agreement described in Note 3. On March 24, 2020, Ridgewood, IREC II and the Company entered into a side letter agreement (“MSA Side Letter”) to memorialize the Ridgewood Side Letter Agreement and pursuant to which Ridgewood will continue to provide the services and other support to the Company required under the terms and conditions of the Management Services Agreement as it relates to the remaining ILX II Leasehold Interests. The MSA Side Letter also provided for the reduction in overhead reimbursement to the Manager effective July 1, 2020. The MSA Side Letter will remain in effect until the termination of the Management Services Agreement or the mutual written agreement of the parties. See Note 3. “Assets Held for Sale” for additional information on the sale of the ILX II Leasehold Interests.
6
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company’s consolidated financial statements include the accounts of ILX II and its subsidiaries. All intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to the Company or ILX II are to ILX Holdings II, LLC and its subsidiaries.
Use of Estimates
The preparation of consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenue and expense during the reporting period. Estimates included in the Company’s consolidated financial statements include those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates.
Fair Value Measurements
The Company follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its consolidated financial statements. The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. The Company’s derivative instruments are recorded at fair value based on Level 2 inputs. See “Derivative Instruments” below and Note 8. “Derivative Instruments” for additional information. The Company also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as unamortized prepaid production handling fees, oil and gas properties and asset retirement obligations, on a non-recurring basis.
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the consolidated balance sheet. As of December 31, 2019, the Company had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2019, the Company’s bank balances exceeded federally insured limits by $57.6 million. During 2019, the Company reclassified the salvage fund to cash and cash equivalents as a result of the sale of assets discussed in Note 3.
Salvage Fund
The Company deposits cash in a separate account, or salvage fund, to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its oil and gas properties at the end of their useful lives in accordance with applicable federal and state laws and regulations. The salvage fund is expected to be funded through amounts withheld from operating income. There are no restrictions on withdrawals from the salvage fund.
Deferred Financing Costs
Deferred financing costs include lender fees and other costs of acquiring debt. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt. During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the consolidated balance sheet within “Oil and gas properties”. See Note 5. “Senior Secured Project Finance Term Loan” for additional information.
7
Oil and Gas Properties
Through its consolidated wholly-owned subsidiaries, the Company invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Company’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.
Acquisition, exploration and development costs are accounted for using the successful efforts method. Exploration costs, such as exploratory geological and geophysical costs, delay rentals, annual lease rentals and exploration overhead are expensed as incurred. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. The costs of exploratory wells are capitalized or suspended, pending determination of whether proved commercial reserves have been found. This determination may take longer than one year depending on, among other things, whether the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If proved commercial reserves are not found, suspended exploratory well costs are expensed as dry-hole costs. Costs of drilling and equipping developmental wells and related production facilities are capitalized. At times, the Company receives adjustments to certain projects from their respective operators upon review and audit of the projects’ costs. All costs related to production activity, transportation expense and workover efforts are expensed as incurred.
Once a property has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.
The Company may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to unproved properties or proved properties.
The Company’s oil and gas properties that are subject of the sale discussed in Note 3 are classified as “Current assets held for sale” on the Company’s consolidated balance sheet.
Accrued Expenses
Accrued expenses consist of the following:
| December 31, 2019 | ||||
| (in thousands) | ||||
| Accrued transaction costs |
$ | 2,124 | ||
| Accrued royalty |
696 | |||
| Accrued transportation expense |
488 | |||
| Accrued accounting and legal fees |
68 | |||
| Other accrued expenses |
7 | |||
|
|
|
|||
| $ | 3,383 | |||
|
|
|
|||
Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Company recognizes the fair value of a liability for an asset retirement obligation in the period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Company’s credit-adjusted risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the year ended December 31, 2019:
8
| December 31, 2019 | ||||
| (in thousands) | ||||
| Balance, beginning of year |
$ | 16,353 | ||
| Accretion expense |
1,196 | |||
| Revision of estimates |
(204 | ) | ||
|
|
|
|||
| Balance, end of year |
$ | 17,345 | ||
|
|
|
|||
Accretion expense is included in the consolidated statement of operations within “Operating expenses”. The asset retirement obligations as of December 31, 2019 of $15.9 million associated with the Company’s oil and gas properties that are the subject of the sale discussed in Note 3 are classified within “Current liabilities held for sale” on the Company’s consolidated balance sheet.
Revenue Recognition
The Company recognizes oil and gas revenue from contracts with customers at the point when control of oil and natural gas is transferred to the customer at an amount that reflects the consideration the Company expects to be entitled to in accordance with Accounting Standard Codification 606 Revenue from Contracts with Customers (“ASC 606”). The Company’s revenue recognition policies, performance obligations and significant judgements in applying ASC 606 are described below.
Oil and Gas Revenue
Generally, the Company sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. Natural gas liquid (“NGL”) sales are included within gas sales. The Company’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances.
In the first type of agreement, a netback agreement, the Company receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Company records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Company delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Company pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Company records the transportation expense within operating expenses in the consolidated statement of operations.
Under the Company’s natural gas processing contracts, the Company delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Company for the sale of NGLs. In this type of arrangement, the Company evaluates whether it is the principal or agent in the transaction. The Company concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Company recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded within operating expenses in the consolidated statement of operations.
In certain instances, the Company may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Company delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Company recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded within operating expenses in the consolidated statement of operations.
The Company assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Company satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Company’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery are reflected in revenue in the month payments are received.
9
Transaction Price Allocated to Remaining Performance Obligations
Under the Company’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer.
Contract Balances
The Company invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Company’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Company’s oil and gas revenue are included within “Production receivable” on the Company’s consolidated balance sheet.
Prior Period Performance Obligations
The Company records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Company records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Company has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. During the year ended December 31, 2019, revenue recognized from performance obligations satisfied in previous periods was not significant.
Derivative Instruments
The Company may periodically utilize derivative instruments to manage the commodity price risk inherent in its oil and natural gas production. Derivative instruments are carried on the consolidated balance sheet at fair value and recorded as either an asset or liability. Changes in the fair value of the derivative instruments are recorded in earnings unless specific hedge accounting criteria are met. At this time, the Company has elected not to use hedge accounting for its derivative instruments and, accordingly, the derivative instruments are marked-to-market each reporting period with fair value gains and losses recognized as derivative instrument gain or loss on the consolidated statement of operations. The related cash flow impact of the derivative activities is reflected as cash flows from operating activities on the consolidated statement of cash flows. See Note 8. “Derivative Instruments” for additional information.
Impairment of Long-Lived Assets
The Company reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Additionally, upon classifying its assets as held for sale, the Company reviewed its oil and gas properties for impairment. Unproved properties are assessed annually by considering the qualitative factors of development intent, primary lease term and whether sufficient progress is made on assessing reserves. The Company provides for impairments of unproved properties when it determines that the property will not be developed or an impairment in value has occurred. Impairments of proved properties are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.
10
In fourth quarter 2019, the new operator of a deepwater oil and gas asset known as the Otis Project determined that the project, which was shut-in since May 2019 due to severe water production, is unlikely to resume production. The new operator has not found an economic option to realize additional value from any remaining reserves on the project. As a result, during the year ended December 31, 2019, the Company recorded impairments of oil and gas properties of $12.6 million, which represented the carrying value of the Otis Project at the date of the impairment. Other than described above, there were no other impairments of the Company’s oil and gas properties.
Fluctuations in oil and natural gas commodity prices may impact the fair value of the Company’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that additional impairments of oil and gas properties will occur.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs.
Amortization of the carrying value of the overriding royalty interests recorded as prepaid production handling fees are calculated using the units-of-production method, using the sum of proved and probable reserves of the related projects as the base (See Note 4. “Overriding Royalty Interest (“ORRI”) Conveyance”).
Depletion and amortization, including amortization of prepaid production handling fees, included on the Company’s consolidated statement of operations relate to the Company’s oil and gas properties that were the subject of the sale discussed in Note 3 and represent amounts recorded through the date at which these properties met held for sale criteria, which was December 10, 2019. Accumulated depletion and amortization associated with the Company’s oil and gas properties and prepaid production handling fees that are the subject of the sale discussed in Note 3 are classified within “Current assets held for sale” on the Company’s consolidated balance sheet.
Income Taxes
No provision is made for income taxes in the consolidated financial statements. The Company is a limited liability company, and as such, the Company’s income or loss is passed through and included in the tax returns of the Company’s Members. The Company files U.S. Federal and State tax returns and the 2016 through 2018 tax returns remain open for examination by tax authorities.
Income and Expense Allocation
Profits and losses are allocated to the Members in accordance with the Amended and Restated LLC Agreement.
Recent Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on measurement of credit losses, which introduces, among other things, a new expected loss impairment model that applies to most financial assets measured at amortized cost and certain other instruments including trade and other receivables and other financial assets. Under the new accounting guidance, entities are required to estimate expected credit loss over the life of financial assets and record an allowance against the asset’s amortized cost basis to present the financial asset at the amount expected to be collected. The estimate of expected credit losses will require entities to incorporate considerations of historical information, current information and reasonable and supportable forecasts. The accounting guidance and the most recent update issued in February 2020 are effective for the Company in the first quarter of 2023 with early adoption permitted. The Company early adopted this accounting guidance and related updates on January 1, 2020 and the adoption did not have a material impact on the Company’s consolidated financial statements.
In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the consolidated balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under
11
the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance is effective for the Company beginning with the fiscal year ending December 31, 2021 with early adoption permitted. Although the Company, as a non-operator, does not enter into lease agreements to support its operations, the Company completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Company early adopted this accounting guidance for the fiscal year ended December 31, 2019 and determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.
2. Unproved Properties
Unproved properties include leasehold acquisition costs, which are initially capitalized, as well as the cost of exploratory wells pending determination of whether the well has found proved reserves. Leasehold acquisition costs are periodically assessed for impairment and are transferred to proved properties to the extent the costs are associated with successful exploration activities. As of December 31, 2019, leasehold acquisition costs capitalized as unproved properties were $5.5 million and are classified within “Current Assets Held for Sale” on the Company’s consolidated balance sheet.
Capitalized exploratory well costs include suspended exploratory well costs. Suspended exploratory well costs are costs associated with projects exhibiting sufficient quantities of hydrocarbons to justify potential development and where the Company is actively pursuing efforts to assess whether reserves can be attributed to such projects. The following table reflects the net changes in capitalized exploratory well costs during the year ended December 31, 2019 and exclude amounts that were capitalized and subsequently expensed or reclassified to proved properties in the same period:
| December 31, 2019 | ||||
| (in thousands) | ||||
| Balance, beginning of year |
$ | 83,970 | ||
| Additions to capitalized exploratory well costs pending the determination of proved reserves |
411 | |||
| Reclassifications to proved properties based on the determination of proved reserves |
— | |||
| Capitalized exploratory well costs charged to expense |
— | |||
|
|
|
|||
| Balance, end of year |
$ | 84,381 | ||
|
|
|
|||
The following table provides the status of projects with exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of December 31, 2019:
| Project |
Drilling Completed | Exploratory Well Costs |
Progress | |||||||
| (in thousands) | ||||||||||
| Katmai West |
Q2 2016 | $ | 35,879 | Katmai West encountered a high pressure zone during drilling operations in second quarter 2016. The drilling expected to recommence in May 2020 has been deferred due to market events. | ||||||
| Ourse Project |
Q3 2015 | $ | 48,090 | The Ourse Project was announced as a discovery in third quarter 2015. The Company and the project’s operator is currently evaluating tie-back options and is looking to sanction the project prior to its lease expiration in June 2020. | ||||||
Capitalized exploratory well costs as of December 31, 2019 of $48.1 million associated with the Ourse Project, are included within “Current Assets Held for Sale” on the Company’s consolidated balance sheet.
Capitalized exploratory well costs, as well as leasehold acquisition costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. At times, the Company receives adjustments to costs of certain projects from their respective operators upon review and audit of the projects’ costs.
12
The Company’s unproved properties that are the subject of the sale discussed in Note 3 are classified as “Current assets held for sale” on the Company’s consolidated balance sheet.
3. Assets Held for Sale
On December 10, 2019, the Company entered into a purchase and sale agreement (the “PSA”) to sell the limited liability company interests in the Company’s wholly-owned subsidiaries that hold the Company’s working interests in all of its producing oil and gas properties and certain primary term acreage and prospects (the “Sold Assets”) to Talos Production, Inc. (the “Buyer”) for an unadjusted purchase price of $260.5 million, subject to purchase price and customary post-closing adjustments. The unadjusted purchase price consisted of $158.0 million in cash and 4,510,000 shares of common stock of the Buyer’s parent company. Pursuant to the PSA, the sale excluded certain properties, financial instruments and working capital of the Company. The PSA was amended on February 24, 2020 to replace the common stock of the Buyer’s parent company with 45,100 Series A Convertible Preferred Stock (“Preferred Stock”) convertible into the Buyer’s parent common stock immediately at a rate of one share of Preferred Stock to 100 shares of common stock. The sale closed on February 28, 2020 and the Company received $98.3 million in cash net of purchase price adjustments, as well as Preferred Stock with a value of $64.0 million. The Preferred Stock automatically converted into common stock on March 30, 2020. The sale resulted in a loss to the Company of approximately $69.4 million, subject to further post-closing adjustments.
The following table presents the details of the loss on the sale as of the closing date.
| February 28, 2020 | ||||
| (in thousands) | ||||
| Cash, net of purchase price adjustments |
$ | 98,266 | ||
| Preferred stock |
64,042 | |||
|
|
|
|||
| Total purchase price |
$ | 162,308 | ||
| Oil and gas properties, net |
$ | 236,730 | ||
| Advance to operator |
3,275 | |||
| Prepaid production and handling |
7,740 | |||
| Less: Asset retirement obligations |
(16,059 | ) | ||
|
|
|
|||
| Assets held for sale less related liabilities |
$ | 231,686 | ||
|
|
|
|||
| Loss on Sale |
$ | (69,378 | ) | |
|
|
|
|||
The Company has classified the Sold Assets and related liabilities as held for sale on the Company’s consolidated balance sheet as of December 31, 2019. General and administrative expenses totaling $2.1 million consist of financial advisory and legal fees related to the transaction are included within “General and administrative expenses” on the Company’s consolidated statement of operations.
The following table presents the carrying amounts of the Sold Assets and related liabilities classified as held for sale on the Company’s consolidated balance sheet.
| December 31, 2019 | ||||
| (in thousands) | ||||
| Assets: |
||||
| Other current assets |
$ | 1,981 | ||
| Other assets |
5,759 | |||
| Oil and gas properties: |
||||
| Advances to operators for working interests and expenditures |
73 | |||
| Unproved properties |
53,580 | |||
| Proved properties |
473,906 | |||
| Less: accumulated depletion and amortization |
(303,177 | ) | ||
|
|
|
|||
| Total oil and gas properties, net |
224,382 | |||
|
|
|
|||
| Current assets held for sale |
$ | 232,122 | ||
|
|
|
|||
| Liabilities: |
||||
| Asset retirement obligations |
$ | 15,871 | ||
|
|
|
|||
| Current liabilities held for sale |
$ | 15,871 | ||
|
|
|
|||
4. Overriding Royalty Interest (“ORRI”) Conveyance
In 2015, the Company, through its wholly owned subsidiaries, entered into a deepwater production handling and operating services agreement (“PHA”) for the Barataria and South Santa Cruz projects with Blind Faith production system owners (the “Platform Owners”). Pursuant to the PHA, the Company agreed to convey to the Platform Owners an ORRI in the Barataria and South Santa Cruz projects of 1.6695% and 1.4175%, respectively, as compensation for processing the projects’ oil and natural gas production. On March 1, 2017, the Company assigned the Barataria and South Santa Cruz projects’ ORRIs to the Platform Owners. The Company estimated the fair value of the ORRIs to be $14.0 million and recorded the amount as a reduction to oil and gas properties and as prepaid production handling fees, which was being amortized to operating expenses using the units-of-production method.
13
As of December 31, 2019, short-term unamortized prepaid production handling fees and long-term unamortized prepaid production handling fees of $2.0 million and $5.8 million, respectively, were included in “Current assets held for sale” on the Company’s consolidated balance sheet.
5. Senior Secured Project Finance Term Loan
On June 28, 2017, the Company (the “Borrower”) entered into a Senior Secured Project Finance Term Loan (as amended on November 30, 2017, June 28, 2019 and December 20, 2019, the “Facility”) with SG Americas Securities, LLC, as the mandated lead arranger, Natixis, New York Branch and Commonwealth Bank of Australia, as co-arrangers with Societe Generale, as administrative agent (the “Administrative Agent”), SG Americas Securities LLC, as technical and modelling bank, Societe Generale, as security agent, structuring bank and issuing bank (collectively, the “Lenders”). The Facility provided for a credit facility in the maximum amount of $250.0 million with initial commitment of $100.0 million and an access to letters of credit (“LC”) of up to $20.0 million. The proceeds of the Facility and the LCs were to be used solely by the Company to fund development and pre-development capital expenditures for the Borrowing Base Assets (“BBA”) and non-BBA and upfront financing costs linked to the Facility. The Facility was secured by substantially all of the Company and its wholly owned subsidiaries’ oil and gas properties, as well as its personal property assets. The maturity of the Facility was the earlier of (i) the reserve tail date and (ii) June 27, 2023.
The Facility was amended on June 28, 2019 wherein the Lenders provided consent to a one-time distribution in an amount up to $41.0 million. The Facility was amended on December 20, 2019 allowing for an extension of the redetermination and the availability period. The scheduled redetermination in 2019 was deferred until on or before February 28, 2020 pursuant to the amendment to the Facility dated December 20, 2019. On February 28, 2020, in conjunction with the closing of the sale of the Company’s oil and gas properties, the Facility was terminated. The Company paid $0.3 million in fees to the Lenders.
As of December 31, 2019, the Company had no borrowings outstanding under the Facility and had a borrowing base of $131.0 million. Unamortized debt discounts and deferred financing costs of $0.9 million as of December 31, 2019 were included on the consolidated balance sheet within “Other current assets”. Unamortized debt discounts and deferred financing costs of $2.2 million as of December 31, 2019 were included on the consolidated balance sheet within “Other assets”.
The Facility contains various customary affirmative, negative and financial maintenance covenants. The Company was in compliance with all covenants under the Facility as of December 31, 2019.
6. Members’ Capital and Distributions
Capital Contribution
Pursuant to the Amended and Restated LLC Agreement, the Members may make capital contributions to the Company from time to time but will not be required to make any capital contributions. Additionally, certain distributable cash may be retained by the Company and recycled as capital contributions. Such amounts, as well as additional capital contributions, may be required to get the Company’s project investments online. See Note 10. “Commitments and Contingencies” for additional information.
As of December 31, 2019, capital contributions totaled $970.2 million, which include $78.6 million of distributions that were recycled as capital contributions during the year ended December 31, 2019.
Distributions
The Management Services Agreement requires that upon final determination of the amount of available cash as of the end of each calendar month, the Manager should promptly distribute such distributable cash. In accordance with the Management Services Agreement, distributions, if any, will be paid to the Company’s Member until such Member has received a return equal to the (i) capital investment in all of the ILX II Leasehold Interests, plus (ii) the total of all management fees paid, plus (iii) a preferred eight percent compounded annual return on the amounts in (i) and (ii). Once the preferred return is received, IREC II will be entitled to twenty percent of the Company’s distributions, payable monthly (see “Ridgewood Profit Participation” below). During the year ended December 31, 2019, distributions to the Company’s Member were $119.6 million, of which $78.6 million was recycled as capital contributions to the Company.
14
Ridgewood Profit Participation
The Management Services Agreement provides that IREC II is entitled to a share of the Company’s distributions only after certain conditions have been met. As of December 31, 2019, such conditions have not been met. See Distributions above for additional information.
7. Overhead Reimbursement
The Management Services Agreement provides that the Manager render management, administrative and technical services, for which it receives an annual overhead reimbursement, payable quarterly. During the year ended December 31, 2019, overhead reimbursement was $3.4 million. Pursuant to the MSA Side Letter, the Company’s overhead reimbursement to the Manager is reduced effective July 1, 2020. See Note 1 for additional information on the MSA Side Letter.
8. Derivative Instruments
The Company entered into fixed price swap contracts (“Swap”) with Commonwealth Bank (“CB”) and Societe Generale (“SG”) on September 29, 2017, effective October 1, 2017 through September 30, 2021, and with Natixis on October 2, 2017, effective October 1, 2017 through September 30, 2021 and with CB and Natixis on April 25, 2019, effective May 1, 2019 through November 30, 2020 and May 1, 2019 through December 31, 2019, respectively, (collectively, the “Counterparties”), to hedge the Company’s exposure to commodity price fluctuations on a portion of oil production from the Company’s producing projects. On November 19, 2019, Societe Generale had novated its Swap to Natixis. The Company has elected not to use hedge accounting for its Swap and consequently, the Swap is marked-to-market each reporting period with fair value gains and losses recognized as derivative instrument gain or loss on the consolidated statement of operations. The estimated fair value of the Swap is based upon closing exchange prices for Light Louisiana Light Sweet Crude Oil available from Argus Media Group (“Argus LLS”). The Company has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment. The Company has entered into the Swap only with Counterparties that are also lenders in the Facility and have been deemed acceptable credit risk (see Note 5. “Senior Secured Project Finance Term Loan”).
The Swap is carried at its fair value on the consolidated balance sheet and the assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty with the same current and noncurrent classification, and where the Company has master netting arrangements. The master netting arrangements allow for set-off that may be exercised in the event of default and provides for contract termination and net settlement. The Company determines the current and noncurrent classification of the Swap based on the timing of expected settlement of individual trades. The Swap is settled based upon reported prices on Argus LLS. The Swap is settled on a monthly basis.
As of December 31, 2019, the Company had outstanding positions under the Swap as detailed in the following table.
| Production Period |
Index | Volume in Bbls |
Weighted Average Fixed Price Swap per Bbl |
Estimated Fair Value |
||||||||||||
| (in thousands) | ||||||||||||||||
| Liabilities: |
||||||||||||||||
| January 1, 2020 to December 31, 2020 |
Argus LLS | 655,900 | $ | 61.23 | $ | 534 | ||||||||||
| January 1, 2021 to September 30, 2021 |
Argus LLS | 92,400 | $ | 51.98 | 496 | |||||||||||
|
|
|
|||||||||||||||
| $ | 1,030 | |||||||||||||||
|
|
|
|||||||||||||||
15
The following table presents the fair value and classification of the outstanding positions under the Swap on the Company’s consolidated balance sheet as of December 31, 2019 on a gross basis and after same-counterparty netting:
| December 31, 2019 | ||||||||||||
| Gross Amounts Recognized |
Gross Amounts Offset |
Net Amounts Presented |
||||||||||
| (in thousands) | ||||||||||||
| Current liabilities: |
||||||||||||
| Derivative instrument liabilities |
$ | 534 | $ | — | $ | 534 | ||||||
| Non-current liabilities: |
||||||||||||
| Derivative instrument liabilities |
$ | 496 | $ | — | $ | 496 | ||||||
None of the Company’s derivative instruments have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the realized and unrealized gains and losses on derivative instruments, which are included on the Company’s consolidated statement of operations under the caption “Derivative instrument gain, net”.
| Year ended December 31, 2019 |
||||
| (in thousands) | ||||
| Unrealized loss on derivative instruments, net |
$ | (1,131 | ) | |
| Realized gain on derivative instruments, net |
2,239 | |||
|
|
|
|||
| Derivative instrument gain, net |
$ | 1,108 | ||
|
|
|
|||
On January 15, 2020, the Company terminated its Swap with CB by making payment of $166 thousand to CB. On January 24, 2020, the Company terminated its Swap with Natixis by receiving payment of $106 thousand from Natixis. There is no Swap outstanding as a result of these terminations.
9. Related Party Transaction
On December 10, 2019, as amended on February 24, 2020, the Company entered into a PSA with the Buyer to sell its limited liability company interests in the Company’s wholly-owned subsidiaries that hold the Company’s working interests in all of its producing oil and gas properties and certain primary term acreage and prospects as described in Note 3. The parties to the PSA are related parties. As described in Note 1, the Company is a controlled affiliate of Riverstone Holdings, LLC. As of December 10, 2019, certain entities controlled or affiliated with Riverstone Energy Partners V, L.P., an affiliate of Riverstone Holdings, LLC, beneficially owned and possessed voting power over approximately 27.5% of the issued and outstanding common stock of the Buyer’s parent company. Further, two directors that currently serve on the board of directors of the parent of the Buyer were appointed by affiliates of Riverstone Holdings, LLC. In addition, affiliates of the Company are party to certain other agreements with the parent of the Buyer.
A wholly-owned subsidiary of the Company, ILX Prospect Claiborne, LLC, and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”) are parties to a production handling, gathering and operating services agreement (“PHA”) with ILX Prospect Beta, a wholly-owned subsidiary of ILX Holdings, LLC, (“ILX I”) and an affiliate of the Company, and other entities that own the Beta Project production facility (collectively, the “Beta Project Owners”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility.
During the year ended December 31, 2019, the Company incurred $0.2 million representing its proportionate share of the production handling fees incurred with ILX I, which is included within operating expenses on the Company’s consolidated statement of operations. As of December 31, 2019, the Company owed $0.1 million to ILX I representing its proportionate share of the production handling fees incurred for the production handling services, which is included within “Due to affiliate” on the Company’s consolidated balance sheet.
16
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
10. Commitments and Contingencies
Funding Commitment
Pursuant to the Participation Agreement, the Company has provided for funding commitments to meet the funding requirements for the initial exploration, development and completion of ILX II Leasehold Interests. The funding requirements that are necessary for the development and completion of the ILX II Leasehold Interests will be based on an annual budget, which is subject to the approval of the Company’s Managing Committee. As of December 31, 2019, the Company had unfunded funding commitments of $129.3 million.
Capital Commitments
As of December 31, 2019, the Company’s estimated capital commitments related to its oil and gas properties were $126.0 million (which include asset retirement obligations for the Company’s projects of $16.5 million), of which $73.2 million is expected to be spent during the year ending December 31, 2020. Capital expenditures, other than for asset retirement obligations, are expected to be funded with unfunded funding commitments and cash flows from operations. Asset retirement obligations are expected to be funded through amounts withheld from operating income from the related project.
Based upon its current cash position and its current reserve estimates, the Company expects cash flows from operations and unfunded funding commitment to be sufficient to cover its commitments and ongoing operations. Future operating income and cash flows are dependent on the continued successful development of the Company’s oil and gas properties and the related production and sale of oil and gas reserves from the Company’s properties under development. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.
Environmental and Governmental Regulations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Company’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Company in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2019, there were no known environmental contingencies that required adjustment to, or disclosure in, the Company’s consolidated financial statements.
Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Company’s operating results and cash flows. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Company’s business.
BOEM Notice to Lessees on Supplemental Bonding
On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of the review of NTL 2016-N01. As of December 31, 2019, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01. The impact of NTL 2016-N01, if enforced without change or amendment, may require the Company to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so. Potentially this could increase costs to the Company if the Company is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.
17
Insurance Coverage
The Company is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the entities managed by the Manager. Depending on the extent, nature and payment of claims made by the Company or other entities managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Company in a given year.
11. Subsequent Events
The Company has assessed the impact of subsequent events through the issuance of the consolidated financial statements on April 28, 2020 and has concluded that there were no such events, other than as noted in Note 1. “Organization and Summary of Significant Accounting Policies – Company Structure” related to the MSA Side Letter, Note 3. “Assets Held for Sale”, Note 5. “Senior Secured Project Finance Term Loan”, Note 8. “Derivative Instruments” and below, that require adjustment to, or disclosure in, the consolidated financial statements.
Impact from the Coronavirus
The extent of the impact of the coronavirus (“COVID-19”) outbreak on the financial performance of the Company’s investment in common stock of the parent of the Buyer it received as consideration for the Sold Assets and that it continues to hold as well as the Company’s remaining oil and gas properties will depend on future developments, including the duration and spread of the outbreak and related advisories and restrictions and the impact of COVID-19 on the oil and gas prices, financial markets and the overall economy, all of which are highly uncertain and cannot be predicted. As of April 28, 2020, the price of the common stock has significantly declined since December 31, 2019. If the financial markets and/or the overall economy are impacted for an extended period, the Company and its future investment results, its operators and other working interest partners’ financial performance results may be further materially adversely affected, which could significantly affect the Company’s liquidity and expected operating results. In addition, the significant decline in oil prices due to COVID-19 will not only reduce revenues and profits but could also reduce the quantities of reserves that are commercially recoverable and result in non-cash charges to earnings due to impairment. The effect of this impact has not been reflected in these consolidated financial statements.
Distributions
On April 8, 2020, the Company made a distribution to its Members totaling $58.2 million, which included proceeds from the sale of assets discussed in Note 3.
18
ILX Holdings II, LLC and Subsidiaries
Supplementary Financial Information
Information about Oil and Gas Producing Activities - Unaudited
In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Company. The Company is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of the Gulf of Mexico.
Table I – Capitalized Costs Relating to Oil and Gas Producing Activities
| December 31, 2019 | ||||
| (in thousands) | ||||
| Advances to operators for working interests and expenditures |
$ | 367 | ||
| Unproved properties |
89,909 | |||
| Proved properties |
598,175 | |||
|
|
|
|||
| Total oil and gas properties |
688,451 | |||
| Accumulated depletion and amortization |
(303,177 | ) | ||
|
|
|
|||
| Oil and gas properties, net |
$ | 385,274 | ||
|
|
|
|||
Table II – Costs Incurred in Oil and Gas Property Acquisition, Exploration
| Year ended December 31, 2019 |
||||
| (in thousands) | ||||
| Exploration costs |
$ | 585 | ||
| Development costs |
59,008 | |||
|
|
|
|||
| $ | 59,593 | |||
|
|
|
|||
Table III – Reserve Quantity Information
Oil and gas reserves of the Company have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2019. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.
| Oil (MBBL) | NGL (MBBL) | Gas (MMCF) | Total (MBOE) (a) | |||||||||||||
| Total proved reserves at December 31, 2018 |
16,259.1 | 931.2 | 24,749.3 | 21,315.2 | ||||||||||||
| Revisions of previous estimates (b) |
653.9 | 192.1 | (1,344.8 | ) | 621.9 | |||||||||||
| Production |
(2,373.3 | ) | (250.3 | ) | (2,505.9 | ) | (3,041.3 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total proved reserves at December 31, 2019 |
14,539.7 | 873.0 | 20,898.6 | 18,895.8 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total proved developed reserves as of: |
||||||||||||||||
| December 31, 2019 |
6,143.4 | 481.6 | 4,735.1 | 7,414.2 | ||||||||||||
| Total proved undeveloped reserves as of: |
||||||||||||||||
| December 31, 2019 |
8,396.3 | 391.4 | 16,163.5 | 11,481.6 | ||||||||||||
| (a) | BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency. |
| (b) | Revisions of previous estimates were attributable to well performance. |
19
Table IV – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.
| December 31, 2019 | ||||
| (in thousands) | ||||
| Future cash inflows |
$ | 883,756 | ||
| Future production costs |
(228,196 | ) | ||
| Future development costs |
(163,451 | ) | ||
|
|
|
|||
| Future net cash flows |
492,109 | |||
| 10% annual discount for estimated timing of cash flows |
(130,040 | ) | ||
|
|
|
|||
| Standardized measure of discounted future net cash flows |
$ | 362,069 | ||
|
|
|
|||
Table V – Changes in the Standardized Measure for Discounted Cash Flows
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.
| Year ended December 31, 2019 |
||||
| (in thousands) | ||||
| Net change in sales and transfer prices and in production costs related to future production |
$ | (136,534 | ) | |
| Sales and transfers of oil and gas produced during the period |
(115,403 | ) | ||
| Changes in estimated future development costs |
(111,373 | ) | ||
| Net change due to revisions in quantities estimates |
15,873 | |||
| Accretion of discount |
52,222 | |||
| Other |
135,069 | |||
|
|
|
|||
| Aggregate change in the standardized measure of discounted future net cash flows for the year |
$ | (160,146 | ) | |
|
|
|
|||
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.
20
Exhibit 99.3
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Consolidated Financial Statements
As of and For the Years Ended
December 31, 2019 and 2018
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Contents
| Page | ||||
| Independent Auditor’s Report |
3 | |||
| Consolidated Financial Statements |
||||
| Consolidated Balance Sheets as of December 31, 2019 and 2018 |
5 | |||
| Consolidated Statements of Operations for the Years Ended December 31, 2019 and 2018 |
6 | |||
| Consolidated Statements of Members’ Equity for the Years Ended December 31, 2019 and 2018 |
7 | |||
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2019 and 2018 |
8 | |||
| Notes to Consolidated Financial Statements |
9 - 22 | |||
2
Independent Auditor’s Report
To the Members of
Castex Energy 2014, LLC
Houston, Texas
We have audited the accompanying consolidated financial statements of Castex Energy 2014, LLC and Subsidiaries, which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Castex Energy 2014, LLC and Subsidiaries as of December 31, 2019 and 2018, and the results of their operations and their cash flows for the years then ended, in accordance with accounting principles generally accepted in the United States of America.
/s/ BDO USA, LLP
August 24, 2020
Houston, Texas
3
Consolidated Financial Statements
4
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Consolidated Balance Sheets
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Assets |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 4,369,102 | $ | 4,466,138 | ||||
| Accounts receivable |
990,010 | 792,542 | ||||||
| Accounts receivable - related party |
542,134 | 1,240,779 | ||||||
| Derivative Financial Instruments |
— | 947,172 | ||||||
| Prepaid expenses and other current assets |
722,289 | 153,046 | ||||||
|
|
|
|
|
|||||
| Total Current Assets |
6,623,535 | 7,599,677 | ||||||
| Property and Equipment |
||||||||
| Oil and natural gas properties, full cost method |
294,201,143 | 268,999,117 | ||||||
| Less: accumulated depreciation, depletion, amortization and impairment |
149,360,548 | 64,213,014 | ||||||
|
|
|
|
|
|||||
| Net Property and Equipment |
144,840,595 | 204,786,103 | ||||||
| Debt Issue Costs, net |
310,722 | 407,316 | ||||||
| Investments in Unconsolidated Entities |
228,338 | 228,338 | ||||||
|
|
|
|
|
|||||
| Total Assets |
$ | 152,003,190 | $ | 213,021,434 | ||||
|
|
|
|
|
|||||
| Liabilities and Members’ Equity |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 414,773 | $ | 2,269,741 | ||||
| Accounts payable - related party |
1,175,554 | 3,418,964 | ||||||
| Derivative Financial Instruments |
252,421 | — | ||||||
| Asset retirement obligations - current portion |
3,623,213 | 2,788,151 | ||||||
|
|
|
|
|
|||||
| Total Current Liabilities |
5,465,961 | 8,476,856 | ||||||
| Long-Term Debt |
21,000,000 | 22,000,000 | ||||||
| Asset Retirement Obligations, net of current portion |
37,444,580 | 37,753,230 | ||||||
|
|
|
|
|
|||||
| Total Liabilities |
63,910,541 | 68,230,086 | ||||||
| Commitments and Contingencies (Note 11) |
||||||||
| Members’ Equity |
88,092,649 | 144,791,348 | ||||||
|
|
|
|
|
|||||
| Total Liabilities and Members’ Equity |
$ | 152,003,190 | $ | 213,021,434 | ||||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
5
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Consolidated Statements of Operations
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Revenue and Derivative Income (Loss) |
||||||||
| Oil and natural gas sales |
$ | 48,655,687 | $ | 31,308,655 | ||||
| (Gain) loss on derivative financial instruments |
464,420 | (594,569 | ) | |||||
|
|
|
|
|
|||||
| Total Revenue and Derivative Income (Loss) |
49,120,107 | 30,714,086 | ||||||
| Operating Expenses |
||||||||
| Operating costs and severance taxes |
23,576,334 | 8,291,238 | ||||||
| Transportation |
2,720,000 | 1,347,081 | ||||||
| Depreciation, depletion and amortization |
27,220,403 | 14,198,446 | ||||||
| General and administrative |
5,950,014 | 2,382,773 | ||||||
| Accretion of asset retirement obligations |
3,060,181 | 954,802 | ||||||
| Impairment of oil and natural gas properties |
57,927,131 | — | ||||||
|
|
|
|
|
|||||
| Total Operating Expenses |
120,454,063 | 27,174,340 | ||||||
|
|
|
|
|
|||||
| (Loss) Income from Operations |
(71,333,956 | ) | 3,539,746 | |||||
| Other Income (Expense) |
||||||||
| Interest expense |
(1,364,746 | ) | (1,272,710 | ) | ||||
|
|
|
|
|
|||||
| Total Other Expense |
(1,364,746 | ) | (1,272,710 | ) | ||||
|
|
|
|
|
|||||
| Net (Loss) Income |
$ | (72,698,702 | ) | $ | 2,267,036 | |||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
6
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Consolidated Statements of Members’ Equity
| Series A | Series B | Total Members’ Equity |
||||||||||||||||||
| Units | Amount | Units | Amount | |||||||||||||||||
| Balance at January 1, 2018 |
174,041,774 | $ | 127,524,312 | 100 | $ | — | $ | 127,524,312 | ||||||||||||
| Contributions |
15,000,000 | 15,000,000 | — | — | 15,000,000 | |||||||||||||||
| Net Income |
— | 2,267,036 | — | — | 2,267,036 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Balance at December 31, 2018 |
189,041,774 | 144,791,348 | 100 | — | 144,791,348 | |||||||||||||||
| Contributions |
16,000,003 | 16,000,003 | — | — | 16,000,003 | |||||||||||||||
| Net Loss |
— | (72,698,702 | ) | — | — | (72,698,702 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Balance at December 31, 2019 |
205,041,777 | $ | 88,092,649 | 100 | $ | — | $ | 88,092,649 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
See accompanying notes to consolidated financial statements.
7
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Consolidated Statements of Cash Flows
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Cash Flows from Operating Activities |
||||||||
| Net (loss) Income |
$ | (72,698,702 | ) | $ | 2,267,036 | |||
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: |
||||||||
| Depreciation, depletion and amortization |
27,220,403 | 14,198,446 | ||||||
| Accretion of asset retirement obligations |
3,060,181 | 954,802 | ||||||
| Impairment of oil and natural gas properties |
57,927,131 | — | ||||||
| Amortization of debt issue costs |
140,174 | 321,347 | ||||||
| (Gain) Loss on derivative financial instruments |
(464,420 | ) | 594,569 | |||||
| Settlements on derivative financial instruments |
1,664,013 | (1,534,263 | ) | |||||
| Changes in operating assets and liabilities: |
||||||||
| Accounts receivable |
(197,468 | ) | (214,953 | ) | ||||
| Accounts receivable - related party |
698,645 | (243,602 | ) | |||||
| Prepaid expenses and other current assets |
(569,243 | ) | (121,033 | ) | ||||
| Accounts payable |
(1,854,968 | ) | 1,668,181 | |||||
| Accounts payable - related party |
(264,797 | ) | (174,207 | ) | ||||
| Settlements of asset retirement obligations |
(1,376,615 | ) | (357,057 | ) | ||||
|
|
|
|
|
|||||
| Net Cash Provided By Operating Activities |
13,284,334 | 17,359,266 | ||||||
| Cash Flows from Investing Activities |
||||||||
| Additions to oil and natural gas properties |
(28,135,702 | ) | (41,152,142 | ) | ||||
| Acquisition of oil and natural gas properties |
490,769 | 2,933,505 | ||||||
| Divestiture of oil and natural gas properties |
(692,860 | ) | — | |||||
|
|
|
|
|
|||||
| Net Cash Used In Investing Activities |
(28,337,793 | ) | (38,218,637 | ) | ||||
| Cash Flows from Financing Activities |
||||||||
| Borrowings under revolving credit facility |
— | 22,000,000 | ||||||
| Repayment of balance under credit facility |
(1,000,000 | ) | (22,000,000 | ) | ||||
| Contributions from members |
16,000,003 | 15,000,000 | ||||||
| Debt issue costs |
(43,580 | ) | (448,460 | ) | ||||
|
|
|
|
|
|||||
| Net Cash Provided By Financing Activities |
14,956,423 | 14,551,540 | ||||||
|
|
|
|
|
|||||
| Net Decrease in Cash and Cash Equivalents |
(97,036 | ) | (6,307,831 | ) | ||||
| Cash and Cash Equivalents, beginning of year |
4,466,138 | 10,773,969 | ||||||
|
|
|
|
|
|||||
| Cash and Cash Equivalents, end of year |
$ | 4,369,102 | $ | 4,466,138 | ||||
|
|
|
|
|
|||||
| Supplemental Cash Flow Information |
||||||||
| Cash paid for interest |
$ | 1,210,376 | $ | 1,059,525 | ||||
|
|
|
|
|
|||||
| Non-Cash Investing and Financing Activities |
||||||||
| Asset retirement obligations incurred (sold) |
$ | (2,320,470 | ) | $ | 30,524,398 | |||
| Revisions to asset retirement obligations |
$ | 1,163,316 | $ | 629,997 | ||||
| Capital expenditures in accounts payable-related party |
$ | (1,978,613 | ) | $ | 3,387,096 | |||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
8
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
| 1. | Organization, Affiliations and Nature of Operations |
Castex Energy 2014, LLC (the “Company”) was formed on April 10, 2014, as a Delaware limited liability company and is engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids. GOME 1271 LLC (“GOME”) and Castex Energy Development Fund II, LLC (“CEDF II”) are wholly- owned subsidiaries of Castex Energy 2014, LLC. The majority of the exploration efforts are concentrated in southern Louisiana and within the Outer Continental Shelf of the United States in the Gulf of Mexico.
The ownership interests in Castex Energy 2014, LLC are held by the Series A members specified in the Amended and Restated Limited Liability Company Agreement of Castex Energy 2014, LLC dated September 3, 2014 (“the LLCA”) and Castex Energy 2005, L.P., the sole Series B member and holder of 100 Series B units.
| 2. | Summary of Significant Accounting Policies |
Principles of Consolidation
The consolidated financial statements include the accounts of Castex Energy 2014, LLC and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depreciation, depletion and amortization of oil and natural gas properties, ceiling test, future net revenues, abandonment obligations, the collectability of outstanding accounts receivable and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depreciation, depletion and amortization, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are sensitive to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
Cash and Cash Equivalents
Cash and cash equivalents include deposits at banks and short term highly liquid investments with original maturities of ninety days or less.
Accounts Receivable
Accounts receivable primarily represent revenues for November and December. The Company’s accounts receivable are generally not collateralized. There was no allowance for doubtful accounts for either of the years presented.
9
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Revenue Recognition
The Company follows the sales method of accounting for revenues whereby it recognizes revenues on production as it is taken and delivered to its purchasers, and if collectability of the revenue is probable. At times, owners may take more or less gas production from a property than they are entitled based on their ownership percentages in the property, which results in a production imbalance. As the Company follows the sales method of accounting, amounts are recorded as gas imbalances when the amounts owed exceed the Company’s share of the cumulative recoverable reserves from that property. As of December 31, 2019 and 2018, the Company has not recorded any gas imbalances.
Property and Equipment
The Company accounts for its investment in oil and natural gas producing activities using the full-cost method of accounting. Under this method of accounting, all costs, including indirect costs related to exploration and development activities, are capitalized as oil and natural gas property costs. These costs, and estimated future development costs, are accumulated and are amortized on an equivalent unit-of-production basis using total estimated proved oil and natural gas reserves. The Company accounts for workovers based on the nature of the work performed. Workover costs incurred for the purpose of restoring production in the same producing horizon are expensed as incurred. Workover costs incurred to explore shallower or deeper horizons to produce reserves from a new formation are capitalized. No gains or losses are recognized on the sale or disposition of oil and natural gas properties, except for sales which include a significant portion of the total proved reserves, and significantly alter the depletion rate. The cost of unevaluated properties are excluded from the full-cost amortization base until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.
Ceiling Test
Under the full-cost method of accounting, a ceiling test is performed quarterly. The test establishes a limit (ceiling) on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated depreciation, depletion and amortization and previously recognized impairment may not exceed this “ceiling.” The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the consolidated balance sheets. The Company uses a twelve-month unweighted average price in the reserve report utilized for ceiling test purposes. If capitalized costs exceed this limit, the excess is charged to impairment expense. The Company recorded impairment expense of $57,927,131 during the year ended December 31, 2019. No impairment expense was recognized for the year ended December 31, 2018.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, derivative financial instruments, and long-term debt. The carrying amounts of these accounts are representative of their respective fair values due to the short-term maturity of these instruments or their interest rate reflective of current market rates except for the derivative financial instruments which are adjusted to fair value at each period end (see Notes 6 and 10).
10
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Debt Issue Costs
Debt issue costs consist of costs associated with obtaining credit with financial institutions. These costs are capitalized and amortized on a straight-line basis over the life of the credit agreement, which approximates the effective interest method. Amortization expense was $140,174 and $321,347 for the years ended December 31, 2019 and 2018, respectively, and is included in interest expense in the consolidated statements of operations. In September 2018, the Company expensed the remaining unamortized debt issuance costs of $119,829, and recorded $448,460 of issuance costs associated with its new credit facility (See Note 7).
Investments in Unconsolidated Entities
The Company’s investments consist of an investment in CTS-Castex, LLC (“CTS-Castex”) of 33.38% and Castex LaFourche, L.P. (“Castex LaFourche”) of 4.73%.
The investment in CTS-Castex is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, and the investment in Castex LaFourche is accounted for under the cost method. No equity income for the investment in CTS-Castex was recorded for the years ended December 31, 2019 and 2018, as the Company has not commenced business operations.
Income Taxes
As a limited liability company, the Company is not subject to federal or state income taxes as such income taxes accrue directly to the members.
The Company has adopted guidance issued by the FASB regarding accounting for uncertainty in income taxes. The guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. If management believes that an income tax position meets the more likely than not threshold, then the tax benefits of this income tax position would be recognized. There were none recognized for the years ended December 31, 2019 and 2018.
The Company has elected to record income tax related interest and penalties as a component of the provision for income tax expense. There was no interest or penalties recognized in the consolidated statements of operations for the years ended December 31, 2019 and 2018.
The Company believes that there are no income tax positions taken or expected to be taken that would significantly increase or decrease unrecognized income tax benefits within 12 months of the reporting date.
None of the Company’s federal or state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. However, fiscal years 2015 and later remain subject to examination by the IRS or state tax authorities.
11
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Asset Retirement Obligations
The Company follows FASB Accounting Standards Codification (“FASB ASC”) 410-20, Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirements costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.
FASB ASC 410-20 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depleted over the life of the asset. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time. If the obligation is settled for other than the carrying amount of the liability, the Company will record an adjustment to the full-cost pool. A credit-adjusted risk-free interest rate is used in our calculation of asset retirement obligations.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk include cash and cash equivalents and accounts receivable.
The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Company monitors the financial condition of the institutions and has not experienced any losses associated with its accounts.
The Company’s customer concentration may impact its overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and gas industry. However, the risk is low due to the industry and access to other purchasers.
The Company enters into joint operating agreements with related parties for the exploration and development of on-shore and off-shore properties. These transactions expose the Company to potential credit risk arising from the operator’s failure to adequately manage its operations.
Subsequent Events
The Company evaluated subsequent events through August 24, 2020, which is the date these financial statements were available for issuance.
On February 28, 2020, the Company closed on the Purchase and Sale Agreement with Talos Production Inc., a wholly owned subsidiary of Talos Energy Inc., whereas Talos Production Inc. purchased all of the issued and outstanding membership interests of GOME.
| 3. | The Limited Liability Company Agreement (“LLCA”) |
The Company was formed by Series A and Series B members. Series A units have a par value of $1.00 per unit. Series A members have one voting right for each Series A membership interest held while the Series B member has no voting rights. None of the members in his, her or its capacities as a Member, have any power or authority to manage the business or affairs of the Company or to bind any Members or enter into any agreements on behalf of the Company. The power and authority to manage the business or affairs of the Company is vested in the Board of Directors. The LLCA includes provisions for the purchase of additional interests and limitations on the ability of the members to transfer their interests. The LLCA also sets forth the manner of allocating income, deductions and credits for tax purposes and specifies the order for the allocation of proceeds upon dissolution.
12
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
In March 2018, a change in control of Castex Energy 2005, L.P. occurred and ownership of the Series B units transferred to Castex Energy 2005, LLC.
Cash distributions are allocated as follows:
| • | First, 100% to the holders of outstanding Series A Units with positive Unreturned Series A Capital Contributions in proportion to their relative number of such outstanding Series A Units, until the Unreturned Series A Capital Contributions attributable to each such outstanding Series A Unit have been reduced to zero dollars; |
| • | Second, 100% to the holders of outstanding Series A units in proportion to the relative Unpaid Series A Preference Amount attributable to each outstanding Series A Unit, until there has been distributed in respect of each outstanding Series A Unit in aggregate amount under the first distribution and this second distribution sufficient to achieve an 8% IRR with respect of such Series A Unit; and |
| • | Third, 100% to the Series B Member until there has been distributed in an aggregate amount under this distribution equal to 20% of the aggregate distributions made under the second distribution and third distribution; |
| • | Fourth, 80% to the holders of outstanding Series A Units pro rata in proportion to the relative number of outstanding Series A Units held by them and 20% to the Series B Member; until there has been distributed in respect to each outstanding Series A Unit an aggregate amount under the first, second, and fourth distributions equal to the Series A Return Threshold; and |
| • | Thereafter, 70% to the holders of outstanding Series A Units pro rata in proportion to the relative number of outstanding Series A Units held by them and 30% to the Series B Member. |
There were no distributions to members for the years ended December 31, 2019 and 2018.
As of December 31, 2019 and 2018, there were 100 Series B units outstanding. It is intended that Series B Units will constitute Profits Interests only. As such, the Profits Interests will be considered a liability when the Company has reached the minimum internal rate of return required by the LLCA. As of December 31, 2019 and 2018, no amounts were recorded related to the Series B units as payments were not considered probable.
| 4. | Acquisitions |
On November 14, 2018, the Company, through its wholly-owned subsidiary GOME, acquired a group of oil and gas properties in the Gulf of Mexico from McMoran Oil & Gas LLC in exchange for GOME assuming the i) lease abandonment obligations, ii) providing performance and umbrella bonds, and iii) assuming a contingent payment in the sum of $2,500,000, due no later than January 31, 2020, if the WTI Crude averages $72 per barrel for the trading days during calendar year 2019. As of December 31, 2018, no liability has been recorded for the contingent payment as it was not considered probable. The Company received cash of $4,578,600 and incurred $519,333 in acquisition costs, which have been recorded in the full cost pool.
During 2018, the Company also acquired interest in certain properties from third parties for a total of $1,125,762, recorded in the full cost pool.
13
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
| 5. | Oil and Natural Gas Properties |
Capitalized costs related to the Company’s oil and natural gas producing activities and the related amounts of accumulated depreciation, depletion, amortization and impairment are as follows:
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Proved properties |
$ | 262,125,358 | $ | 233,869,174 | ||||
| Less: accumulated depreciation, depletion amortization and impairment |
149,360,548 | 64,213,014 | ||||||
|
|
|
|
|
|||||
| Proved properties – net |
112,764,810 | 169,656,160 | ||||||
| Unproved properties |
32,075,785 | 35,129,943 | ||||||
|
|
|
|
|
|||||
| Oil and natural gas properties – net |
$ | 144,840,595 | $ | 204,786,103 | ||||
|
|
|
|
|
|||||
| 6. | Derivative Financial Instruments |
All derivative instruments are measured periodically and at year end and are recorded on the consolidated balance sheets at fair value. Derivative contracts that are not designated as part of a valid qualifying hedge or fail to meet the requirements of the pronouncement as a highly effective hedge, are accounted for by recording the changes in the fair value from period to period, through earnings. The amounts paid or received upon each monthly settlement, are recorded as derivative gain (loss) with the offset recorded to cash. These monthly settlements are recorded to the Company’s consolidated statements of operations as “(Gain) loss on derivative financial instruments.” Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets.
As of December 31, 2019, the Company had the following contracts outstanding (Asset (Liability) and fair value gain (loss)):
| Crude Oil | Natural Gas | Total | ||||||||||||||||||||||||||||||||||||||
| Period |
Average (Bbls/Day) |
Contract Price |
Asset (Liability) |
Fair Value Gain (Loss) |
Average (MMBtu/Day) |
Contract Price |
Asset (Liability) |
Fair Value Gain (Loss) |
Asset (Liability) |
Fair Value Gain (Loss) |
||||||||||||||||||||||||||||||
| Swaps |
||||||||||||||||||||||||||||||||||||||||
| 1/1/20-12/31/20 |
200 | 55.00 | (252,421 | ) | (252,421 | ) | — | — | — | — | (252,421 | ) | (252,421 | ) | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||
| $ | (252,421 | ) | $ | (252,421 | ) | $ | $ | $ | (252,421 | ) | $ | (252,421 | ) | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||
14
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The following table summarizes the fair value and classification of the Company’s derivative instruments as of December 31, 2019 and 2018, all of which have not been designated as hedging instruments under FASB ASC 815:
| December 31, 2019 | ||||||||||||
| Location on Balance Sheet |
Gross FV of Asset/(Liabilities) |
Gross Amounts of Assets/(Liabilities) Offset on Balance Sheet |
Net FV of Assets/(Liabilities) Presented in the Balance Sheet |
|||||||||
| Current assets |
$ | — | $ | — | $ | — | ||||||
| Long-term assets |
— | — | — | |||||||||
| Current liabilities |
(252,421 | ) | — | (252,421 | ) | |||||||
| Long-term liabilities |
— | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
$ | (252,421 | ) | $ | — | $ | (252,421 | ) | ||||
|
|
|
|
|
|
|
|||||||
| December 31, 2018 | ||||||||||||
| Location on Balance Sheet |
Gross FV of Asset/(Liabilities) |
Gross Amounts of Assets/(Liabilities) Offset on Balance Sheet |
Net FV of Assets/(Liabilities) Presented in the Balance Sheet |
|||||||||
| Current assets |
$ | 1,116,314 | $ | (169,142 | ) | $ | 947,172 | |||||
| Long-term assets |
— | — | — | |||||||||
| Current liabilities |
— | — | — | |||||||||
| Long-term liabilities |
— | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
$ | 1,116,314 | $ | (169,142 | ) | $ | 947,172 | |||||
|
|
|
|
|
|
|
|||||||
The following table summarizes the effect of the Company’s derivative instruments in the consolidated statements of operations:
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Derivatives Not Designated as Hedging Instruments |
||||||||
| Beginning fair value of derivative financial instruments |
$ | 947,172 | $ | 7,478 | ||||
| Gain (Loss) on derivative financial instruments |
464,420 | (594,569 | ) | |||||
| Settlements on derivative financial instruments |
(1,664,013 | ) | 1,534,263 | |||||
|
|
|
|
|
|||||
| Net change in fair value of derivative financial instruments |
(1,199,593 | ) | 939,694 | |||||
|
|
|
|
|
|||||
| Ending fair value of derivative financial instruments |
$ | (252,421 | ) | $ | 947,172 | |||
|
|
|
|
|
|||||
| 7. | Long-Term Debt |
In February 2016, the Company’s wholly owned subsidiary, GOME, entered into a credit facility with a borrowing base of $27,000,000, and subsequently borrowed $22,000,000 to finance the acquisition of on-shore and off-shore oil and natural gas interests acquired from Castex Energy Partners, LP (“CEP”), a related party.
In September 2018, the Company refinanced its credit facility with First Tennessee Bank National Association with a borrowing base of $25,000,000 and maturity of March 18, 2022. Interest on the amount draw is based on LIBOR plus an applicable margin. The interest rate at September 30, 2019 was 5.43% and December 31, 2018 was 4.70%. The credit facility is also subject to a commitment fee of .50% based on the unused commitment amount. The borrowings are collateralized by proved property of the Company. The borrowing base is also re- determined semi-annually on or around May 1st and November 1st of each year and may be reduced discretionarily by the lenders, which may require significant principal repayments. The borrowing base was re- determined and increased to $30,000,000 in November 2018.
In July 2019, the Company’s borrowing base was re-determined to $25,000,000 with availability stepping down to $21,000,000 on November 1, 2019.
15
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
As of December 31, 2019, the outstanding balance was $21,000,000. The Company is also subject to certain affirmative and negative covenants associated with the credit facility and was in compliance with all financial covenants as of December 31, 2019.
Future maturities of long-term debt are as follows:
| Year Ending December 31, |
||||
| 2020 |
$ | — | ||
| 2021 |
— | |||
| 2022 |
21,000,000 | |||
| Thereafter |
— | |||
|
|
|
|||
| $ | 21,000,000 | |||
|
|
|
|||
| 8. | Asset Retirement Obligations |
The details of asset retirement obligations are as follows:
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Asset retirement obligations, beginning of period |
$ | 40,541,381 | $ | 8,789,241 | ||||
| Liabilities incurred |
168,196 | 30,524,398 | ||||||
| Liabilities sold |
(2,488,666 | ) | — | |||||
| Liabilities settled |
(1,376,615 | ) | (357,057 | ) | ||||
| Change in estimates |
1,163,316 | 629,997 | ||||||
| Accretion |
3,060,181 | 954,802 | ||||||
|
|
|
|
|
|||||
| Asset retirement obligations, end of period |
$ | 41,067,793 | $ | 40,541,381 | ||||
|
|
|
|
|
|||||
| 9. | Related Party Transactions |
The Company pays management fees to Castex Energy, Inc. (“CEI”), a related party, pursuant to a Shared Services Agreement. For the years ended December 31, 2019 and 2018, the management fees were $7,000,000 and $2,300,000, respectively. The Company capitalized $1,620,000 and $600,000 of this overhead to unproved properties during the years ended December 31, 2019 and 2018, respectively. Management fees net of capitalized amounts are included in general and administrative expenses in the consolidated statements of operations.
At December 31, 2019 the Company was due $542,134 which comprises of $2,883,310 revenues receivable and $2,341,176 joint interest billings. At December 31, 2018, the Company was due $1,240,779 from CEI which comprises of $4,035,481 revenues receivable and $2,794,702 joint interest billings.
At December 31, 2019 Castex Offshore Inc., (“COI”), a related party, was due $1,175,554 which comprises of $2,470,659 revenues receivable and $3,646,213 joint interest billings. At December 31, 2018, the COI was due $3,418,964 which comprises of $4,233,040 revenues receivable and $7,652,004 joint interest billings.
Balances with CEI and COI are presented net in accounts receivable - related party or accounts payable - related party, as applicable for the period, in the consolidated financial statements as rights of setoff exist.
In January 2019, the Company closed on the sale of certain interests in oil and gas properties to Castex Energy 2016, LP, a related party, and paid $692,860 in connection with the abandonment obligations assumed by the purchaser.
16
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
| 10. | Fair Value Disclosure |
The Company follows FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.
FASB ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.
The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:
| December 31, 2019 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| Assets / (Liabilities) |
||||||||||||||||
| Oil and Gas Commodity Contracts |
$ | — | $ | (252,421 | ) | $ | — | $ | (252,421 | ) | ||||||
| December 31, 2018 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| Assets / (Liabilities) |
||||||||||||||||
| Oil and Gas Commodity Contracts |
$ | — | $ | 947,172 | $ | — | $ | 947,172 | ||||||||
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize Company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. For the years ended December 31, 2019 and 2018, we recorded a total of $168,196 and $30,524,398, respectively, in additions to asset retirement obligations measured at fair value.
The Company determines the fair value of the assets acquired and liabilities assumed in business acquisitions using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped, probable and possible reserves are deduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements included significant unobservable inputs, making these a Level 3.
17
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The fair value of assets or liabilities associated with acquisitions of businesses are on a non-recurring basis and is not measured in periods after initial recognition.
| 11. | Commitments and Contingencies |
The Company may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. The Company regularly analyzes current information and as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, at December 31, 2019, there were no threatened or pending legal matters that would have a material impact on the Company’s consolidated financial statements.
12. Supplemental Oil and Gas Information (Unaudited)
Capitalized Costs
Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, see below.
18
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Costs Incurred for Property Acquisition, Exploration, and Development Activities
The following table reflects the costs incurred for oil and natural gas property acquisition, exploration, and development activities during the year ended December 31, 2019 and 2018. Costs incurred also include new asset retirement obligations established in the current year, as well as increased or decreases to the asset retirement obligations resulting from changes to cost estimates during the year:
| December 31, 2019 |
December 31, 2018 |
|||||||
| Acquisition of properties |
$ | (490,769 | ) | $ | (2,933,505 | ) | ||
| Exploration costs |
16,030,538 | 16,484,507 | ||||||
| Development costs |
9,662,257 | 59,209,126 | ||||||
|
|
|
|
|
|||||
| Total costs incurred |
$ | 25,202,026 | $ | 72,760,128 | ||||
|
|
|
|
|
|||||
Estimated Quantities of Proved Oil and Natural Gas Reserves
The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with Securities and Exchange Commission (“SEC”) guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. The Company’s VP of Reservoir Engineering, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil and natural gas reserves are located in the United States primarily southern Louisiana and offshore Gulf of Mexico.
Proved oil and natural gas reserves are the estimated quantities of oil natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, material balance, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all our fields.
Reserve estimates are often different from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Estimating quantities of proved oil, natural gas and NGL reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil, natural gas and NGL prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise.
19
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The following table sets forth information for the period ended December 31, 2019 and 2018 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:
| Crude Oil | Natural Gas | Total | ||||||||||
| (Mbbl) | (MMcf) | (Mboe) | ||||||||||
| January 1, 2018 |
2,939 | 60,112 | 12,958 | |||||||||
| Extensions, discoveries and other additions |
284 | 8,739 | 1,741 | |||||||||
| Acquisitions |
1,646 | 22,277 | 5,359 | |||||||||
| Revisions |
(989 | ) | (19,508 | ) | (4,240 | ) | ||||||
| Production |
(208 | ) | (4,807 | ) | (1,009 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| December 31, 2018 |
3,673 | 66,814 | 14,808 | |||||||||
| Extensions, discoveries and other additions |
— | — | — | |||||||||
| Acquisitions |
— | — | — | |||||||||
| Revisions |
(118 | ) | (5,956 | ) | (1,111 | ) | ||||||
| Production |
(505 | ) | (6,753 | ) | (1,631 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| December 31, 2019 |
3,049 | 54,106 | 12,067 | |||||||||
|
|
|
|
|
|
|
|||||||
| Proved Developed Reserves, included above |
||||||||||||
| December 31, 2018 |
3,141 | 58,167 | 12,836 | |||||||||
| December 31, 2019 |
2,691 | 46,734 | 10,480 | |||||||||
|
|
|
|
|
|
|
|||||||
| Proved Undeveloped Reserves, included above |
||||||||||||
| December 31, 2018 |
531 | 8,646 | 1,972 | |||||||||
| December 31, 2019 |
358 | 7,371 | 1,587 | |||||||||
|
|
|
|
|
|
|
|||||||
For the year ended December 31, 2019, the Company had downward revisions of previous estimates of 1,111 Mboe. These revisions are primarily a result of well performance. No extensions or acquisitions were reported during the period in 2019.
For the year ended December 31, 2018, the Company had downward revisions of previous estimates of 4,240 Mboe. These revisions are primarily a result of well performance. As a result of ongoing drilling and completion activities during the period in 2018, the Company reported extensions, discoveries, and other additions of 1,741 Mboe. Additionally, during the period in 2018, the Company purchased reserves of 5,359 Mboe.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The Company follows the guidelines prescribed in ASC Topic 932, Extractive Activities—Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year.
20
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves; (3) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (4) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (5) future net cash flows are discounted to present value by applying a discount rate of 10%.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following table shows the base prices used in determining the standardized measure:
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Oil price per Bbl |
$ | 53.95 | $ | 65.56 | ||||
| Natural gas price per Mcf |
$ | 2.50 | $ | 3.10 | ||||
These prices were based on the 12-month arithmetic average first-of-month price for January 1, 2018 through December 31, 2018, and January 1, 2019 through December 31, 2019. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price and the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.
21
CASTEX ENERGY 2014, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932:
| December 31, 2019 |
December 31, 2018 |
|||||||
| Future crude oil, natural gas and NGLs sales |
$ | 291,857,100 | $ | 437,896,300 | ||||
| Future production costs |
(108,424,600 | ) | (116,477,200 | ) | ||||
| Future development costs |
(80,664,600 | ) | (92,360,600 | ) | ||||
| Future income tax expense* |
— | — | ||||||
|
|
|
|
|
|||||
| Future net cash flows |
102,767,900 | 229,058,500 | ||||||
| 10% annual discount |
(26,272,700 | ) | (76,877,700 | ) | ||||
|
|
|
|
|
|||||
| Standardized measure of discounted future net cash flows |
$ | 76,495,200 | $ | 152,180,800 | ||||
|
|
|
|
|
|||||
| * | The Company’s calculations of the standardized measure of discounted future net cash flows as of December 31, 2019 and 2018 includes the Company’s obligation for Texas Margin Tax, but excludes the effect of estimated future income tax expenses as the Company is a limited liability company and not subject to income taxes. |
The following are the principal sources of change in the Standardized Measure:
| Year Ended December 31, 2019 |
Year Ended December 31, 2018 |
|||||||
| Balance at beginning of period |
$ | 152,180,800 | $ | 101,327,700 | ||||
| Sales of crude oil, natural gas and NGLs |
(22,505,658 | ) | (21,670,336 | ) | ||||
| Net change in prices and production costs |
(65,125,106 | ) | 27,044,480 | |||||
| Net changes in future development costs |
3,652,832 | (4,231,518 | ) | |||||
| Extensions, discoveries and other additions |
— | 23,026,820 | ||||||
| Acquisition of reserves |
— | 55,068,193 | ||||||
| Revisions of previous quantity estimates |
(13,480,002 | ) | (31,303,725 | ) | ||||
| Previously estimated development costs incurred |
4,052,463 | 5,012,577 | ||||||
| Net change in income taxes |
— | — | ||||||
| Accretion of discount |
15,218,080 | 10,132,770 | ||||||
| Other |
2,501,791 | (12,226,161 | ) | |||||
|
|
|
|
|
|||||
| Balance at end of period |
$ | 76,495,200 | $ | 152,180,800 | ||||
|
|
|
|
|
|||||
22
Exhibit 99.4
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Consolidated Financial Statements
As of and For the Years Ended
December 31, 2019 and 2018
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Contents
| Page | ||||
| Independent Auditor’s Report |
3 | |||
| Consolidated Financial Statements |
||||
| Consolidated Balance Sheets as of December 31, 2019 and 2018 |
5 | |||
| Consolidated Statements of Operations for the Years Ended December 31, 2019 and 2018 |
6 | |||
| Consolidated Statements of Changes in Partners’ Capital for the Years Ended December 31, 2019 and 2018 |
7 | |||
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2019 and 2018 |
8 | |||
| Notes to Consolidated Financial Statements |
9 - 18 | |||
2
Independent Auditor’s Report
To the Partners of
Castex Energy 2016, LP
Houston, Texas
We have audited the accompanying consolidated financial statements of Castex Energy 2016, LP and Subsidiary, which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, changes in partners’ capital, and cash flows for the years then ended, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Castex Energy 2016, LP and Subsidiary as of December 31, 2019 and 2018, and the results of their operations and their cash flows for the years then ended, in accordance with accounting principles generally accepted in the United States of America.
/s/ BDO USA, LLP
August 24, 2020
Houston, Texas
3
Consolidated Financial Statements
4
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Consolidated Balance Sheets
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Assets |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 471,877 | $ | 156,883 | ||||
| Accounts receivable |
101,637 | 37,413 | ||||||
| Prepaid expenses and other current assets |
85,932 | 14,765 | ||||||
|
|
|
|
|
|||||
| Total Current Assets |
659,446 | 209,061 | ||||||
| Property and Equipment |
||||||||
| Oil and natural gas properties, full cost method |
16,601,963 | 11,045,425 | ||||||
| Less: accumulated depreciation, depletion, and amortization |
3,867,095 | 1,753,064 | ||||||
|
|
|
|
|
|||||
| Net Property and Equipment |
12,734,868 | 9,292,361 | ||||||
| Investment in Unconsolidated Entity |
23,542 | 23,542 | ||||||
|
|
|
|
|
|||||
| Total Assets |
$ | 13,417,856 | $ | 9,524,964 | ||||
|
|
|
|
|
|||||
| Liabilities and Partners’ Capital |
||||||||
| Current Liabilities |
||||||||
| Accounts payable and accrued liabilities |
$ | 73,320 | $ | 224,651 | ||||
| Accounts payable – affiliate |
1,240,732 | 1,183,112 | ||||||
| Asset retirement obligations - current portion |
293,387 | 70,029 | ||||||
|
|
|
|
|
|||||
| Total Current Liabilities |
1,607,439 | 1,477,792 | ||||||
| Long-Term Debt-Affiliate |
979,451 | 929,631 | ||||||
| Asset Retirement Obligations, net of current portion |
4,647,652 | 749,620 | ||||||
|
|
|
|
|
|||||
| Total Liabilities |
7,234,542 | 3,157,043 | ||||||
| Commitments and Contingencies (Note 9) |
||||||||
| Partners’ Capital |
6,183,314 | 6,367,921 | ||||||
|
|
|
|
|
|||||
| Total Liabilities and Partners’ Capital |
$ | 13,417,856 | $ | 9,524,964 | ||||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
5
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Consolidated Statements of Operations
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Oil and Gas Natural Revenues |
$ | 5,549,865 | $ | 2,618,186 | ||||
| Operating Expenses |
||||||||
| Operating costs and severance taxes |
2,614,574 | 682,632 | ||||||
| Transportation |
277,329 | 80,280 | ||||||
| Depreciation, depletion and amortization |
2,114,031 | 955,835 | ||||||
| General and administrative |
384,999 | 375,624 | ||||||
| Accretion of asset retirement obligations |
276,336 | 48,927 | ||||||
|
|
|
|
|
|||||
| Total Operating Expenses |
5,667,269 | 2,143,298 | ||||||
|
|
|
|
|
|||||
| (Loss) Income from Operations |
(117,404 | ) | 474,888 | |||||
| Other Income (Expense) |
||||||||
| Interest expense |
(67,203 | ) | (29,631 | ) | ||||
|
|
|
|
|
|||||
| Total Other Expense |
(67,203 | ) | (29,631 | ) | ||||
|
|
|
|
|
|||||
| Net (Loss) Income |
$ | (184,607 | ) | $ | 445,257 | |||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
6
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Consolidated Statements of Changes in Partners’ Capital
| Balance at January 1, 2018 |
$ | 5,922,664 | ||
| Net Income |
445,257 | |||
|
|
|
|||
| Balance at December 31, 2018 |
6,367,921 | |||
| Net Loss |
(184,607 | ) | ||
|
|
|
|||
| Balance at December 31, 2019 |
$ | 6,183,314 | ||
|
|
|
See accompanying notes to consolidated financial statements.
7
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Consolidated Statements of Cash Flows
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Cash Flows from Operating Activities |
||||||||
| Net (Loss) Income |
$ | (184,607 | ) | $ | 445,257 | |||
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: |
||||||||
| Depreciation, depletion and amortization |
2,114,031 | 955,835 | ||||||
| Accretion of asset retirement obligations |
276,336 | 48,927 | ||||||
| Changes in operating assets and liabilities: |
||||||||
| Accounts receivable |
(64,224 | ) | 6,509 | |||||
| Accounts receivable – affiliates |
— | 7,837 | ||||||
| Prepaid expenses and other current assets |
(71,167 | ) | (14,175 | ) | ||||
| Accounts payable |
(101,511 | ) | 176,651 | |||||
| Accounts payable – affiliates |
(22,233 | ) | 1,007,706 | |||||
| Settlements of asset retirement obligations |
(131,527 | ) | (29,998 | ) | ||||
|
|
|
|
|
|||||
| Net Cash Provided by Operating Activities |
1,815,098 | 2,604,549 | ||||||
| Cash Flows from Investing Activities |
||||||||
| Additions to oil and natural gas properties |
(2,192,964 | ) | (3,551,406 | ) | ||||
| Acquisition of oil and natural gas properties |
692,860 | (122,151 | ) | |||||
|
|
|
|
|
|||||
| Net Cash Used In Investing Activities |
(1,500,104 | ) | (3,673,557 | ) | ||||
| Cash Flows from Financing Activities |
||||||||
| Proceeds from note payable – Affiliate |
— | 900,000 | ||||||
|
|
|
|
|
|||||
| Net Cash Provided By Financing Activities |
— | 900,000 | ||||||
|
|
|
|
|
|||||
| Net Increase (Decrease) in Cash and Cash Equivalents |
314,994 | (169,008 | ) | |||||
| Cash and Cash Equivalents, beginning of year |
156,883 | 325,891 | ||||||
|
|
|
|
|
|||||
| Cash and Cash Equivalents, end of year |
$ | 471,877 | $ | 156,883 | ||||
|
|
|
|
|
|||||
| Non-Cash Investing and Financing Activities |
||||||||
| Revisions to asset retirement obligations |
116,730 | (14,849 | ) | |||||
| Capital expenditures in accounts payable |
79,853 | 157,391 | ||||||
| Asset retirement obligations incurred |
$ | 3,859,851 | $ | 35,506 | ||||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
8
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
| 1. | Organization, Affiliations and Nature of Operations |
Castex Energy 2016, LP was formed on March 22, 2016 (date of inception), as a Texas limited partnership and is engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids. The majority of the exploration efforts are concentrated in southern Louisiana and within the Outer Continental Shelf of the United States in the Gulf of Mexico. The general partner of Castex Energy 2016, LP is Castex Energy 2016 GP, LLC, a Delaware limited liability company.
On May 2, 2017, Castex Energy, Inc. assigned 100% equity interest in Dorado Deep GP, LLC (“Dorado Deep”), a Delaware limited liability company, to Castex Energy 2016, LP. Dorado Deep is an entity qualified to hold offshore leases. Castex Energy 2016, LP is the sole member of Dorado Deep and, as such, Dorado Deep is considered a wholly-owned subsidiary of Castex Energy 2016, LP (Dorado Deep and Castex Energy 2016, LP are hereinafter collectively referred to as the “Partnership”).
| 2. | Summary of Significant Accounting Policies |
Principles of Consolidation
The consolidated financial statements include the accounts of Castex Energy 2016, LP and its wholly-owned subsidiary. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of oil and natural gas properties, ceiling test, future net revenues, abandonment obligations, the collectability of outstanding accounts receivable and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and annual ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are sensitive to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and are expected to be volatile in the future.
Cash and Cash Equivalents
Cash and cash equivalents include deposits at banks and short term highly liquid investments with original maturities of ninety days or less.
Accounts Receivable
Accounts receivable primarily represent estimated revenues of oil and natural gas for the prior two months. The Partnership’s accounts receivable are generally not collateralized. There was no allowance for doubtful accounts for either of the years presented.
9
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
Revenue Recognition
The Partnership follows the sales method of accounting for revenues whereby it recognizes revenues on production as it is taken and delivered to its purchasers, and if collectability of the revenue is probable. At times, owners of an oil and natural gas property may take more or less production from a property than they are entitled based on their ownership percentages in the property, which results in a production imbalance. As the Partnership follows the sales method of accounting, amounts are recorded as natural gas imbalances when the amounts owed exceed the Partnership’s share of the cumulative recoverable reserves from that property. As of December 31, 2019 and 2018, the Partnership has not recorded any natural gas imbalances.
Property and Equipment
The Partnership accounts for its investment in oil and natural gas producing activities using the full-cost method of accounting. Under this method of accounting, all costs, including indirect costs related to exploration and development activities, are capitalized as oil and natural gas property costs. These costs, and estimated future development costs, are accumulated and are amortized on an equivalent unit-of-production basis using total estimated proved oil and natural gas reserves. The Partnership accounts for workovers based on the nature of the work performed. Workover costs incurred for the purpose of restoring production in the same producing horizon are expensed as incurred. Workover costs incurred to explore shallower or deeper horizons to produce reserves from a new formation are capitalized. No gains or losses are typically recognized on the sale or disposition of oil and natural gas properties, except for sales which include a significant portion of the total proved reserves, and significantly alter the depletion rate. The cost of unevaluated properties are excluded from the full-cost amortization base until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.
Ceiling Test
Under the full-cost method of accounting, a ceiling test is performed quarterly. The test establishes a limit (ceiling), on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated depreciation, depletion and amortization may not exceed this “ceiling.” The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet. The Partnership uses a twelve month unweighted average price in the reserve report utilized for ceiling test purposes. If capitalized costs exceed this limit, the excess is charged to impairment expense. No impairment expense was recognized for the years ended December 31, 2019 and 2018.
Fair Value of Financial Instruments
The Partnership’s consolidated financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities. The carrying amounts of these accounts are representative of their respective fair values due to the short-term nature of these instruments. The fair value of the Partnership’s debt with affiliate can’t be reasonably estimated due to the related party nature.
Investment in Unconsolidated Entity
The Partnership’s investment consists of an investment in Castex LaFourche, LP (“Castex LaFourche”), an affiliated entity, of 0.525%. The investment is accounted for under the cost method as the Partnership has no influence.
10
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
Income Taxes
The Partnership is not a taxpaying entity. No provision for federal income taxes has been made for the Partnership as these taxes are the responsibility of the individual partners.
A margin tax applies to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on the Partnership’s Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base rate that considers both revenue and expenses and therefore has the characteristics of an income tax. As the Partnership has its primary operations in Southern Louisiana and in Federal waters, the impact of the Texas margin tax is immaterial to the consolidated financial statements.
The Partnership follows FASB Accounting Standards Codification (“ASC”) 740, Income Taxes, for accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than fifty percent likely to be realized upon its ultimate settlement. The Partnership had no uncertain tax positions as of December 31, 2019 nor any of the periods presented.
The Partnership records income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2019 and 2018.
None of the Partnership’s federal or state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. However, all periods since inception (March 22, 2016) remain subject to examination by the IRS or the State of Texas.
The Partnership also files a state tax return in Louisiana; however, the resulting income flows through to the partners’ individual state tax return.
Asset Retirement Obligations
The Partnership follows FASB Accounting Standards Codification (“FASB ASC”) 410-20, Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirements costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.
FASB ASC 410-20 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depleted over the life of the asset. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time. If the obligation is settled for other than the carrying amount of the liability, the Partnership will record an adjustment to the full-cost pool.
11
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
Concentration of Credit Risk
Financial instruments which potentially subject the Partnership to concentrations of credit risk include cash and cash equivalents and accounts receivable.
The Partnership maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Partnership monitors the financial condition of the institutions and has not experienced any losses associated with its accounts.
The Partnership’s customer concentration may impact its overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.
The Partnership enters into joint operating agreements with related parties for the exploration and development of on-shore and off-shore properties. These transactions expose the Partnership to potential credit risk arising from the operator’s failure to adequately manage its operations.
Subsequent Events
The Partnership evaluated subsequent events through August 24, 2020, which is the date these consolidated financial statements were available for issuance.
On February 28, 2020, the Partnership closed on the Purchase and Sale Agreement with Talos Production Inc., a wholly owned subsidiary of Talos Energy Inc., whereas Talos Production Inc. purchased all of the issued and outstanding membership interests of Dorado Deep.
| 3. | Acquisitions |
On January 30, 2019, the Partnership, through its wholly-owned subsidiary Dorado Deep, acquired a group of oil and natural gas properties in the Gulf of Mexico from Castex Energy 2014, LLC, a related party, in exchange for Dorado Deep assuming the i) lease abandonment obligations, ii) providing performance and umbrella bonds, and iii) assuming a contingent payment in the sum of $250,000, due no later than January 31, 2020, if the WTI Crude averages $72 per barrel for the trading days during calendar year 2019. As of December 31, 2019 no liability has been recorded for the contingent payment as it was not considered probable. The Partnership received cash of $692,860, which was recorded as a reduction in the full cost pool as it was treated as an asset acquisition.
| 4. | Oil and Natural Gas Properties |
Capitalized costs related to the Partnership’s oil and natural gas producing activities and the related amounts of accumulated depreciation, depletion, and amortization as of December 31, 2019 and 2018 are as follows:
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Proved properties |
$ | 16,208,872 | $ | 10,725,232 | ||||
| Less: accumulated depreciation, depletion and amortization |
3,867,095 | 1,753,064 | ||||||
|
|
|
|
|
|||||
| Proved properties – net |
12,341,777 | 8,972,168 | ||||||
| Unproved properties |
393,091 | 320,193 | ||||||
|
|
|
|
|
|||||
| Oil and natural gas properties – net |
$ | 12,734,868 | $ | 9,292,361 | ||||
|
|
|
|
|
|||||
12
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
| 5. | Long-Term Debt - Affiliate |
On June 1, 2018, the Partnership entered into a promissory note with Castex Management Partners, LP (“CMP”), an affiliated party, in the amount of $500,000. The note bears interest at a rate of 7% based on a 365 day year, to be paid monthly no later than the first day of the month. Principal, along with interest accrued, is due on or before June 1, 2020.
On August 1, 2018, the Partnership entered into a second promissory note with CMP in the amount of $400,000. The note carries the same interest terms as the first promissory note, but matures on August 1, 2020. Interest expense of $67,203 and $29,631 is recorded in the consolidated statements of operations in 2019 and 2018, respectively.
| 6. | Asset Retirement Obligations |
The details of asset retirement obligations are as follows:
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Asset retirement obligations, beginning of period |
$ | 819,649 | $ | 780,063 | ||||
| Liabilities incurred |
3,859,851 | 35,506 | ||||||
| Liabilities settled |
(131,527 | ) | (29,998 | ) | ||||
| Change in estimates |
116,730 | (14,849 | ) | |||||
| Accretion |
276,336 | 48,927 | ||||||
|
|
|
|
|
|||||
| Asset retirement obligations, end of year |
$ | 4,941,039 | $ | 819,649 | ||||
|
|
|
|
|
|||||
| 7. | Related Party Transactions |
The Partnership pays management fees to Castex Energy, Inc. (“CEI”), an affiliate. For the years ended December 31, 2019 and 2018, the management fees were $250,000 and $250,000, respectively. The Partnership capitalized $57,600 during the twelve months ended December 31, 2019 of this overhead to unproved properties. No overhead was capitalized during the year ended December 31, 2018. Management fees net of capitalized amounts are included in general and administrative expenses on the consolidated statements of operations.
At December 31, 2019 CEI was due $995,413 which comprises of $353.335 revenues receivable and $1,348,748 joint interest billings associated with prior two months. At December 31, 2018, CEI was due $1,008,582 from the Partnership which comprises of $461,904 revenues receivable and $1,470,486 joint interest billings for November and December.
At December 31, 2019, Castex Offshore Inc. (“COI”), a related party, was due $245,319 which comprises of $287,697 in revenues receivable and $533,016 of joint interest billings associated with prior two months. At December 31, 2018, COI was due $174,530 which comprises of $35,477 in revenues receivable and $210,007 joint interest billings for November and December.
Balances between CEI and COI are presented net in accounts receivable – related party or accounts payable – related party, as applicable, in the consolidated financial statements as rights of setoff exist.
The Partnership also has a note payable with CMP, an affiliated party, and interest expense related to this note. See Note 5.
13
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
| 8. | Fair Value Disclosure |
The Partnership follows FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.
FASB ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize Partnership-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. For the years ended December 31, 2019 and 2018, the Partnership recorded a total of $3,859,851 and $35,506, respectively, in additions to asset retirement obligations measured at fair value.
The Partnership determines the fair value of the assets acquired and liabilities assumed in business acquisitions using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped, probable and possible reserves are deduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements included significant unobservable inputs, making these a Level 3.
The fair value of assets or liabilities associated with acquisitions of businesses are on a non-recurring basis and is not measured in periods after initial recognition.
| 9. | Commitments and Contingencies |
The Partnership may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. The Partnership regularly analyzes current information and as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, at December 31, 2019, there were no threatened or pending legal matters that would have a material impact on the Partnership’s consolidated financial statements.
14
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
| 10. | Supplemental Oil and Natural Gas Information (Unaudited) |
Capitalized Costs
Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, see below.
Costs Incurred for Property Acquisition, Exploration, and Development Activities
The following table reflects the costs incurred for oil and natural gas property acquisition, exploration, and development activities during the year ended December 31, 2019 and 2018. Costs incurred also include new asset retirement obligations established in the current year, as well as increased or decreases to the asset retirement obligations resulting from changes to cost estimates during the year:
| December 31, 2019 |
December 31, 2018 |
|||||||
| Acquisition of properties |
$ | (692,860 | ) | $ | 122,151 | |||
| Exploration costs |
1,137,404 | 1,137,741 | ||||||
| Development costs |
5,111,994 | 2,591,713 | ||||||
| Total costs incurred |
$ | 5,556,538 | $ | 3,851,605 | ||||
Estimated Quantities of Proved Oil and Natural Gas Reserves
The Partnership employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with Securities and Exchange Commission (“SEC”) guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. The Partnership’s VP of Reservoir Engineering, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Partnership’s proved oil and natural gas reserves are located in the United States primarily southern Louisiana and offshore Gulf of Mexico.
Proved oil and natural gas reserves are the estimated quantities of oil natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, material balance, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
15
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
Reserve estimates are often different from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Estimating quantities of proved oil, natural gas and NGL reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil, natural gas and NGL prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Partnership’s reserve estimates are inherently imprecise.
The following table sets forth information for the period ended December 31, 2019 and 2018 with respect to changes in the Partnership’s proved (i.e. proved developed and undeveloped) reserves:
| Crude Oil | Natural Gas | Total | ||||||||||
| (Mbbl) | (MMcf) | (Mboe) | ||||||||||
| January 1, 2018 |
181 | 4,577 | 944 | |||||||||
| Extensions, discoveries and other additions |
29 | 857 | 172 | |||||||||
| Acquisitions |
26 | 255 | 68 | |||||||||
| Revisions |
15 | (3 | ) | 14 | ||||||||
| Production |
(15 | ) | (428 | ) | (87 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| December 31, 2018 |
235 | 5,258 | 1,111 | |||||||||
| Extensions, discoveries and other additions |
— | — | — | |||||||||
| Acquisitions |
117 | 953 | 276 | |||||||||
| Revisions |
42 | 913 | 194 | |||||||||
| Production |
(58 | ) | (765 | ) | (186 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| December 31, 2019 |
336 | 6,359 | 1,396 | |||||||||
|
|
|
|
|
|
|
|||||||
| Proved Developed Reserves, included above |
||||||||||||
| December 31, 2018 |
170 | 4,078 | 849 | |||||||||
| December 31, 2019 |
289 | 5,252 | 1,164 | |||||||||
|
|
|
|
|
|
|
|||||||
| Proved Undeveloped Reserves, included above |
||||||||||||
| December 31, 2018 |
65 | 1,180 | 262 | |||||||||
| December 31, 2019 |
48 | 1,107 | 232 | |||||||||
|
|
|
|
|
|
|
|||||||
For the year ended December 31, 2019, the Partnership had upward revisions of previous estimates of 194 Mboe. These revisions are primarily the result of better well performance from new wells that exceeded previous estimates. During the period in 2019, the Partnership purchased reserves of 276 Mboe.
For the year ended December 31, 2018, the Partnership had upward revisions of previous estimates of 14 Mboe. These revisions are primarily the result of better well performance from new wells that exceeded previous estimates. As a result of ongoing drilling and completion activities during the period in 2018, the Partnership reported extensions, discoveries, and other additions of 172 Mboe. Additionally, during the period in 2018, the Partnership purchased reserves of 68 Mboe.
16
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The Partnership follows the guidelines prescribed in ASC Topic 932, Extractive Activities—Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Partnership’s proved reserves to the year-end quantities of those reserves for reserves; (3) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Partnership overhead incurred; (4) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Partnership’s proved oil and natural gas reserves; and, (5) future net cash flows are discounted to present value by applying a discount rate of 10%.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Partnership’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Partnership emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Partnership’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following table shows the base prices used in determining the standardized measure:
| Year Ended December 31, | ||||||||
| 2019 | 2018 | |||||||
| Oil price per Bbl |
$ | 53.95 | $ | 65.56 | ||||
| Natural gas price per Mcf |
$ | 2.50 | $ | 3.10 | ||||
These prices were based on the 12-month arithmetic average first-of-month price for January 1, 2018 through December 31, 2018, and January 1, 2019 through December 31, 2019. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price and the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.
17
CASTEX ENERGY 2016, LP AND SUBSIDIARY
Notes to Consolidated Financial Statements
The following summary sets forth the Partnership’s future net cash flows relating to proved oil, and natural gas reserves based on the standardized measure prescribed in ASC Topic 932:
| December 31, 2019 |
December 31, 2018 |
|||||||
| Future crude oil, natural gas and NGLs sales |
$ | 33,149,900 | $ | 30,338,412 | ||||
| Future production costs |
(12,450,000 | ) | (5,749,831 | ) | ||||
| Future development costs |
(9,393,700 | ) | (4,384,916 | ) | ||||
| Future income tax expense* |
— | — | ||||||
|
|
|
|
|
|||||
| Future net cash flows |
11,306,200 | 20,203,665 | ||||||
| 10% annual discount |
(2,693,000 | ) | (7,187,450 | ) | ||||
|
|
|
|
|
|||||
| Standardized measure of discounted future net cash flows |
$ | 8,613,200 | $ | 13,016,215 | ||||
|
|
|
|
|
|||||
| * | The Partnership’s calculations of the standardized measure of discounted future net cash flows as of December 31, 2019 and 2018 includes the Partnership’s obligation for Texas Margin Tax but excludes the effect of estimated future income tax expenses as the Partnership is a limited liability Partnership and not subject to income taxes. |
The following are the principal sources of change in the Standardized Measure:
| Year Ended December 31, 2019 |
Year Ended December 31, 2018 |
|||||||
| Balance at beginning of period |
$ | 13,016,215 | $ | 5,869,700 | ||||
| Sales of crude oil, natural gas and NGLs |
(2,673,790 | ) | (1,855,274 | ) | ||||
| Net change in prices and production costs |
(6,875,393 | ) | 3,791,411 | |||||
| Net changes in future development costs |
(2,967,204 | ) | (454,948 | ) | ||||
| Extensions, discoveries and other additions |
— | 2,234,137 | ||||||
| Acquisition of reserves |
4,793,375 | 978,591 | ||||||
| Revisions of previous quantity estimates |
688,414 | 855,597 | ||||||
| Previously estimated development costs incurred |
281,003 | 635,056 | ||||||
| Net change in income taxes |
— | — | ||||||
| Accretion of discount |
1,301,621 | 586,970 | ||||||
| Other |
1,048,959 | 374,975 | ||||||
|
|
|
|
|
|||||
| Balance at end of period |
$ | 8,613,200 | $ | 13,016,215 | ||||
|
|
|
|
|
|||||
18
Exhibit 99.5
TALOS ENERGY INC.
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
The following unaudited pro forma combined financial statements present the combination of the historical financial information of Talos Energy Inc., a Delaware corporation (the “Company” or “Talos”), ILX Holdings, LLC, a Delaware limited liability company (“ILX Holdings”), ILX Holdings II, LLC, a Delaware limited liability company (“ILX Holdings II”), Castex Energy 2014, LLC, a Delaware limited liability company (“Castex 2014”) and Castex Energy 2016, LP, a Delaware limited partnership (“Castex 2016” and, together with Castex 2014, the “Castex Sellers”), adjusted to give effect to the Transactions (as defined below) and related financing consisting of borrowings under the Company’s revolving bank credit facility. In addition, while the Company acquired substantially all of the key operating assets of ILX Holdings, ILX Holdings II and the Castex Sellers, the historical financial information was adjusted to eliminate specified assets and liabilities, and the associated income affect, not in certain of the wholly-owned subsidiaries of ILX Holdings and ILX Holdings II (collectively, the “ILX Target Entities”) and certain wholly-owned subsidiaries of the Castex Sellers (the “Castex Target Entities”), or were considered Excluded Assets in the Purchase Agreements (as defined below).
The unaudited pro forma combined statement of operations for the year ended December 31, 2019 combines the historical consolidated statements of operations of Talos, ILX Holdings, ILX Holdings II and the Castex Sellers giving effect to the Transactions and related financing as if they had been consummated on January 1, 2019. The unaudited pro forma combined balance sheet combines the historical consolidated balance sheets of Talos, ILX Holdings, ILX Holdings II and the Castex Sellers as of December 31, 2019, giving effect to the Transactions and related financing as if closing had occurred on December 31, 2019.
The following unaudited pro forma combined financial statements are based on, and should be read in conjunction with:
| • | The historical audited consolidated financial statements of the Company and the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on March 12, 2020; |
| • | The historical audited consolidated financial statements of ILX Holdings and the related notes included as Exhibit 99.1 in the Company’s Current Report on Form 8-K filed with the SEC on September 11, 2020; |
| • | The historical audited consolidated financial statements of ILX Holdings II and the related notes included as Exhibit 99.2 in the Company’s Current Report on Form 8-K filed with the SEC on September 11, 2020; |
| • | The historical audited consolidated financial statements of Castex 2014 and the related notes included as Exhibit 99.3 in the Company’s Current Report on Form 8-K filed with the SEC on September 11, 2020; and |
| • | The historical audited consolidated financial statements of Castex 2016 and the related notes included as Exhibit 99.4 in the Company’s Current Report on Form 8-K filed with the SEC on September 11, 2020. |
On February 28, 2020 (the “Closing Date”), the Company acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, ILX Holdings II, ILX Holdings III, LLC, a Delaware limited liability company (“ILX Holdings III”) and Castex 2014, each a related party and an affiliate of certain entities controlled or affiliated with Riverstone Energy Partners V, L.P. (collectively, the “Riverstone Sellers”), and Castex 2016 (together with the Riverstone Sellers, the “Sellers”) with an effective date of July 1, 2019 (collectively, the “ILX and Castex Acquisition”). The ILX and Castex Acquisition was consummated pursuant to separate Purchase and Sale Agreements, dated December 10, 2019 (as amended from time to time, the “Purchase Agreements”) for aggregate consideration consisting of (i) $385.0 million in cash subject to customary closing adjustments and (ii) an aggregate 110,000 shares (the “Preferred Shares”) of a series of the Company’s preferred stock, par value $0.01 per
1
share, designated as “Series A Convertible Preferred Stock” were issued to the Riverstone Sellers (such issuance, the “Preferred Stock Issuance”) on the terms and subject to the conditions set forth in that certain Certificate of Designation of Preferences, Rights and Limitations relating to the Series A Convertible Preferred Stock (the “Certificate of Designation”) which subsequently converted to 11.0 million shares of the Company’s common stock, par value $0.01 per share (the “Common Stock”) on March 30, 2020 (the “Conversion” and such Common Stock, the “Conversion Stock”). The Preferred Stock Issuance, the ILX and Castex Acquisition, the Conversion and the other transactions contemplated by the Purchase Agreements are referred to herein collectively as the “Transactions”. The cash payment and escrow deposit were funded with borrowings under the revolving bank credit facility.
The accompanying unaudited pro forma combined financial statements were derived by making certain adjustments to the historical financial statements listed above that are (i) directly attributable to the Transactions and related financing, (ii) factually supportable and (iii) with respect to the unaudited pro forma combined statement of operations, expected to have a continuing impact on the combined results. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the Transactions and related financing and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.
The unaudited pro forma combined financial statements and related notes are presented for illustrative purposes only and should not be relied upon as an indication of operating results that Talos would have achieved if the Transactions and related financing had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma combined financial statements and should not be relied on as an indication of the future results of Talos.
2
TALOS ENERGY INC.
UNAUDITED PRO FORMA COMBINED BALANCE SHEETS
AS OF DECEMBER 31, 2019
(In thousands, except per share data)
| Talos Historical |
Target Assets Historical |
Pro Forma Adjustments |
Pro Forma Combined |
|||||||||||||||||
| Note 2 | Note 4 | |||||||||||||||||||
| ASSETS |
||||||||||||||||||||
| Current assets: |
||||||||||||||||||||
| Cash and cash equivalents |
$ | 87,022 | $ | 4,841 | $ | — | $ | 91,863 | ||||||||||||
| Accounts receivable, net |
||||||||||||||||||||
| Trade |
107,842 | 7,087 | — | 114,929 | ||||||||||||||||
| Joint Interest |
16,552 | — | — | 16,552 | ||||||||||||||||
| Other |
6,346 | — | — | 6,346 | ||||||||||||||||
| Assets from price risk management activities |
8,393 | — | — | 8,393 | ||||||||||||||||
| Prepaid assets |
65,877 | 660 | — | 66,537 | ||||||||||||||||
| Income tax receivable |
116 | — | — | 116 | ||||||||||||||||
| Other current assets |
1,836 | 146 | — | 1,982 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total current assets |
293,984 | 12,734 | — | 306,718 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Property and equipment: |
||||||||||||||||||||
| Proved properties |
4,066,260 | 1,029,376 | (627,246 | ) | (a | ) | 4,468,390 | |||||||||||||
| Unproved properties, not subject to amortization |
194,532 | 86,049 | 1,522 | (a | ) | 282,103 | ||||||||||||||
| Other property and equipment |
29,843 | — | — | 29,843 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total property and equipment |
4,290,635 | 1,115,425 | (625,724 | ) | 4,780,336 | |||||||||||||||
| Accumulated depreciation, depletion and amortization |
(2,065,023 | ) | (623,530 | ) | 623,530 | (a | ) | (2,065,023 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total property and equipment, net |
2,225,612 | 491,895 | (2,194 | ) | 2,715,313 | |||||||||||||||
| Other long-term assets: |
||||||||||||||||||||
| Other well equipment inventory |
7,732 | — | — | 7,732 | ||||||||||||||||
| Operating lease assets |
7,779 | — | — | 7,779 | ||||||||||||||||
| Other assets |
54,375 | 2,226 | (1,974 | ) | (b | ) | 54,627 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total assets |
$ | 2,589,482 | $ | 506,855 | $ | (4,168 | ) | $ | 3,092,169 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY |
||||||||||||||||||||
| Current liabilities: |
||||||||||||||||||||
| Accounts payable |
$ | 71,357 | $ | 8,131 | $ | 10,094 | (c | ) | $ | 89,582 | ||||||||||
| Accrued liabilities |
154,816 | 224 | — | 155,040 | ||||||||||||||||
| Accrued royalties |
31,729 | — | — | 31,729 | ||||||||||||||||
| Current portion of asset retirement obligations |
61,051 | 3,916 | (3,916 | ) | (d | ) | 61,051 | |||||||||||||
| Liabilities from price risk management activities |
19,476 | — | — | 19,476 | ||||||||||||||||
| Accrued interest payable |
10,249 | — | — | 10,249 | ||||||||||||||||
| Current portion of operating lease liabilities |
1,594 | — | — | 1,594 | ||||||||||||||||
| Other current liabilities |
20,180 | — | — | 20,180 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total current liabilities |
370,452 | 12,271 | 6,178 | 388,901 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Long-term liabilities: |
||||||||||||||||||||
| Long-term debt, net of discount and deferred financing costs |
732,981 | — | 296,966 | (e | ) | 1,029,947 | ||||||||||||||
| Asset retirement obligations |
308,427 | 63,818 | (22,652 | ) | (d | ) | 349,593 | |||||||||||||
| Liabilities from price risk management activities |
511 | — | — | 511 | ||||||||||||||||
| Operating lease liabilities |
17,239 | — | — | 17,239 | ||||||||||||||||
| Other long-term liabilities |
81,595 | — | — | (f | ) | 81,595 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total liabilities |
1,511,205 | 76,089 | 280,492 | 1,867,786 | ||||||||||||||||
| Members’ equity |
— | 430,766 | (430,766 | ) | (g | ) | — | |||||||||||||
| Stockholders’ equity: |
||||||||||||||||||||
| Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2019 |
— | — | — | — | ||||||||||||||||
| Common stock, $0.01 par value; 270,000,000 shares authorized; 54,197,004 shares issued and outstanding as of December 31, 2019 |
542 | — | 110 | (h | ) | 652 | ||||||||||||||
| Additional paid-in capital |
1,346,142 | — | 156,090 | (h | ) | 1,502,232 | ||||||||||||||
| Accumulated deficit |
(268,407 | ) | — | (10,094 | ) | (c | ) | (278,501 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total stockholders’ equity |
1,078,277 | 430,766 | (284,660 | ) | 1,224,383 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total liabilities and stockholders’ equity |
$ | 2,589,482 | $ | 506,855 | $ | (4,168 | ) | $ | 3,092,169 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
3
TALOS ENERGY INC.
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2019
(In thousands, except per share data)
| Talos Historical |
Target Assets Historical |
Pro Forma Adjustments |
Pro Forma Combined |
|||||||||||||||||
| Note 2 | Note 4 | |||||||||||||||||||
| Revenues: |
||||||||||||||||||||
| Oil revenue |
$ | 833,118 | $ | 276,829 | $ | — | $ | 1,109,947 | ||||||||||||
| Natural gas revenue |
55,278 | 30,774 | — | 86,052 | ||||||||||||||||
| NGL revenue |
19,668 | 11,168 | — | 30,836 | ||||||||||||||||
| Other |
19,556 | — | — | 19,556 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total revenue |
927,620 | 318,771 | — | 1,246,391 | ||||||||||||||||
| Operating expenses: |
||||||||||||||||||||
| Lease operating expense |
243,427 | 101,590 | (156 | ) | (i | ) | 344,861 | |||||||||||||
| Production taxes |
1,349 | 1,535 | — | 2,884 | ||||||||||||||||
| Depreciation, depletion and amortization |
345,931 | 133,707 | (72,946 | ) | (j | ) | 406,692 | |||||||||||||
| Write-down of oil and natural gas properties |
12,221 | 70,530 | (70,530 | ) | (k | ) | 12,221 | |||||||||||||
| Accretion expense |
34,389 | 4,745 | — | 39,134 | ||||||||||||||||
| General and administrative expense |
77,209 | 19,620 | (4,375 | ) | (l | ) | 92,454 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total operating expenses |
714,526 | 331,727 | (148,007 | ) | 898,246 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Operating income (loss) |
213,094 | (12,956 | ) | 148,007 | 348,145 | |||||||||||||||
| Interest expense |
(97,847 | ) | — | (14,441 | ) | (m | ) | (112,288 | ) | |||||||||||
| Price risk management activities income (expense) |
(95,337 | ) | — | — | (95,337 | ) | ||||||||||||||
| Other income |
2,678 | 599 | — | 3,277 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net income (loss) before income taxes |
22,588 | (12,357 | ) | 133,566 | 143,797 | |||||||||||||||
| Income tax benefit (expense) |
36,141 | — | (32,139 | ) | (n | ) | 4,002 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net income (loss) |
$ | 58,729 | $ | (12,357 | ) | $ | 101,427 | $ | 147,799 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net income per common share: |
||||||||||||||||||||
| Basic |
$ | 1.08 | $ | 2.27 | ||||||||||||||||
| Diluted |
$ | 1.08 | $ | 2.26 | ||||||||||||||||
| Weighted average common shares outstanding: |
||||||||||||||||||||
| Basic |
54,185 | 65,185 | (o) | |||||||||||||||||
| Diluted |
54,413 | 65,413 | (o) | |||||||||||||||||
4
TALOS ENERGY INC.
NOTES TO THE UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
| Note 1. | Basis of Presentation |
The unaudited pro forma combined financial statements present the combination of the historical financial information of Talos, ILX Holdings, ILX Holdings II and the Castex Sellers, adjusted to give effect to the Transactions and additional borrowings under the revolving bank credit facility. In addition, while the Company acquired substantially all of the key operating assets of ILX Holdings, ILX Holdings II and the Castex Sellers, the historical financial information was adjusted to eliminate specified assets and liabilities not acquired by Talos as part of the Transactions. See Note 2 — Consolidation of Acquired Entities, for additional information.
The unaudited pro forma combined statement of operations for the fiscal year ended December 31, 2019 combines the historical consolidated statements of operations of Talos, ILX Holdings, ILX Holdings II and the Castex Sellers, giving effect to the Transactions and related financing as if they had been consummated on January 1, 2019. The unaudited pro forma combined balance sheet combines the historical consolidated balance sheets of Talos, ILX Holdings, ILX Holdings II and the Castex Sellers as of December 31, 2019, giving effect to the Transactions and related financing as if the closing had occurred on December 31, 2019. The Transactions and other adjustments are described in Note 4 — Pro Forma Adjustments to these unaudited pro forma combined financial statements.
Certain reclassifications have been made to the historical financial statements of ILX Holdings, ILX Holdings II and the Castex Sellers to reflect the comparability of financial information. However, the pro forma combined financial statements may not reflect all adjustments necessary to conform the accounting policies of ILX Holdings, ILX Holdings II and the Castex Sellers to those of Talos due to the limitations on the availability of information.
The pro forma adjustments represent management’s estimates based on information available as of the date hereof and are subject to change as additional information becomes available and additional analyses are performed. The pro forma financial statements do not reflect the impact of possible revenue or earnings enhancements, cost savings from operating efficiencies or synergies, or asset dispositions. Also, the pro forma financial statements do not reflect possible adjustments related to restructuring or integration activities or transaction or other costs following the Transactions that are not expected to have a continuing impact. Further, one-time transaction-related expenses anticipated to be incurred prior to, or concurrent with, closing of the Transactions are not included in the pro forma statements of operations. However, the impact of such transaction expenses is reflected in the pro forma balance sheet as an increase to accounts payable and accumulated deficit.
The unaudited pro forma combined financial information has been prepared using the acquisition method of accounting with Talos as the accounting acquirer of the assets acquired from the ILX Target Entities and the Castex Target Entities (the “Target Assets”). Under the acquisition method of accounting, the purchase price is allocated to the identifiable tangible and intangible assets acquired and liabilities assumed based on their respective fair values, with any excess in purchase price allocated to goodwill. The fair value of identifiable assets acquired and liabilities assumed from the Transactions are based on a preliminary estimate of fair value using assumptions described in the accompanying notes to the unaudited pro forma combined financial information that the Company believes is reasonable. See Note 3 — Preliminary Purchase Price Allocation, for additional information.
5
| Note 2. | Consolidation of Acquired Entities |
The following table illustrates the historical balances sheets of ILX Holdings, ILX Holdings II and the Castex Sellers, including the elimination of specific assets and liabilities not acquired by Talos, that form the Target Assets Historical column on the unaudited combined balance sheets as of December 31, 2019. Certain reclassifications have been made to the historical financial statements of ILX Holdings, ILX Holdings II and the Castex Sellers to reflect the comparability of financial information.
| ILX Holdings Historical |
ILX Holdings II Historical |
Castex 2014 Historical |
Castex 2016 Historical |
Excluded Assets |
Total Target Assets Historical |
|||||||||||||||||||||||
| ASSETS |
||||||||||||||||||||||||||||
| Current assets: |
||||||||||||||||||||||||||||
| Cash and cash equivalents |
$ | 25,589 | $ | 57,897 | $ | 4,369 | $ | 472 | $ | (83,486 | ) | (a | ) | $ | 4,841 | |||||||||||||
| Accounts receivable, net |
||||||||||||||||||||||||||||
| Trade |
10,671 | 11,338 | 6,344 | 743 | (22,009 | ) | (b | ) | 7,087 | |||||||||||||||||||
| Other |
1,332 | 741 | — | — | (2,073 | ) | (b | ),(d) | — | |||||||||||||||||||
| Prepaid assets |
430 | 888 | 589 | 71 | (1,318 | ) | (b | ) | 660 | |||||||||||||||||||
| Other current assets |
— | 891 | 133 | 13 | (891 | ) | (b | ) | 146 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total current assets |
38,022 | 71,755 | 11,435 | 1,299 | (109,777 | ) | 12,734 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Property and equipment: |
||||||||||||||||||||||||||||
| Proved properties |
269,396 | 605,915 | 262,125 | 16,209 | (124,269 | ) | (e | ) | 1,029,376 | |||||||||||||||||||
| Unproved properties, not subject to amortization |
— | 89,909 | 32,076 | 393 | (36,329 | ) | (e | ) | 86,049 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total property and equipment |
269,396 | 695,824 | 294,201 | 16,602 | (160,598 | ) | 1,115,425 | |||||||||||||||||||||
| Accumulated depreciation, depletion and amortization |
(167,125 | ) | (303,177 | ) | (149,361 | ) | (3,867 | ) | — | (623,530 | ) | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total property and equipment, net |
102,271 | 392,647 | 144,840 | 12,735 | (160,598 | ) | 491,895 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Other long-term assets: |
||||||||||||||||||||||||||||
| Other assets |
2,255 | 3,303 | 228 | 24 | (3,584 | ) | (b | ) | 2,226 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total assets |
$ | 142,548 | $ | 467,705 | $ | 156,503 | $ | 14,058 | $ | (273,959 | ) | $ | 506,855 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| LIABILITIES AND EQUITY |
||||||||||||||||||||||||||||
| Current liabilities: |
||||||||||||||||||||||||||||
| Accounts payable |
$ | 7,398 | $ | 7,387 | $ | 6,208 | $ | 1,923 | $ | (14,785 | ) | (b | ) | $ | 8,131 | |||||||||||||
| Accrued liabilities |
3,869 | 3,383 | 192 | 32 | (7,252 | ) | (b | ) | 224 | |||||||||||||||||||
| Current portion of asset retirement obligations |
— | — | 3,623 | 293 | — | 3,916 | ||||||||||||||||||||||
| Liabilities from price risk management activities |
2,580 | 534 | 252 | — | (3,366 | ) | (c | ) | — | |||||||||||||||||||
| Other current liabilities |
271 | 100 | — | — | (371 | ) | (b | ) | — | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total current liabilities |
14,118 | 11,404 | 10,275 | 2,248 | (25,774 | ) | 12,271 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Long-term liabilities |
||||||||||||||||||||||||||||
| Long-term debt |
— | — | 20,690 | 979 | (21,669 | ) | (f | ) | — | |||||||||||||||||||
| Asset retirement obligations |
5,854 | 17,345 | 37,445 | 4,648 | (1,474 | ) | (e | ) | 63,818 | |||||||||||||||||||
| Liabilities from price risk management activities |
— | 496 | — | — | (496 | ) | (c | ) | — | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total liabilities |
19,972 | 29,245 | 68,410 | 7,875 | (49,413 | ) | 76,089 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total members’ equity |
122,576 | 438,460 | 88,093 | 6,183 | (224,546 | ) | (g | ) | 430,766 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total liabilities and members’ equity |
$ | 142,548 | $ | 467,705 | $ | 156,503 | $ | 14,058 | $ | (273,959 | ) | $ | 506,855 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| (a) | Reflects the exclusion of cash and cash equivalents from ILX Holdings and ILX Holdings II as such assets are considered Excluded Assets under the Purchase Agreements and are not included in the Transactions. |
6
| (b) | Reflects the exclusion of working capital and other long term assets of ILX Holdings and ILX Holdings II, as such assets and liabilities are considered Excluded Assets under the applicable Purchase Agreements and are not included in the Transactions. |
| (c) | Reflects the exclusion of assets and liabilities associated with price risk management activities of ILX Holdings, ILX Holdings II and the Castex Sellers as these financial instruments are considered Excluded Assets under the Purchase Agreements and are not included in the Transactions. |
| (d) | Reflects the exclusion of joint interest partner credits associated with the Katmai Field which is considered an Excluded Asset for ILX Holdings II under the applicable Purchase Agreement and are not included in the Transactions of $0.1 million. |
| (e) | Reflects the exclusion of capitalized oil and natural gas expenditures associated with the discovery of the Katmai Field, which is considered an Excluded Asset under the Purchase Agreements and are not included in the Transactions. |
| (f) | Reflects the exclusion of long-term debt of the Castex Sellers as the long-term debt is considered Excluded Assets under the Purchase Agreements and are not included in the Transactions. |
| (g) | Reflects the elimination of members’ equity for Excluded Assets under the Purchase Agreements. |
The following table illustrates the historical income statements of ILX Holdings, ILX Holdings II and the Castex Sellers, including the elimination of expenses associated with specific assets and liabilities not acquired by Talos, that form the Target Assets Historical column on the unaudited combined income statement for the year ended December 31, 2019. Certain reclassifications have been made to the ILX Holdings, ILX Holdings II and the Castex Sellers’ historical financial statements to reflect the comparability of financial information.
| ILX Holdings Historical |
ILX Holdings II Historical |
Castex 2014 Historical |
Castex 2016 Historical |
Excluded Assets |
Total Target Assets Historical |
|||||||||||||||||||||||
| Revenues: |
||||||||||||||||||||||||||||
| Oil revenue |
$ | 101,394 | $ | 142,459 | $ | 29,578 | $ | 3,398 | — | $ | 276,829 | |||||||||||||||||
| Natural gas revenue |
6,381 | 6,671 | 15,910 | 1,812 | — | 30,774 | ||||||||||||||||||||||
| NGL revenue |
3,345 | 4,316 | 3,168 | 339 | — | 11,168 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total revenue |
111,120 | 153,446 | 48,656 | 5,549 | — | 318,771 | ||||||||||||||||||||||
| Operating expenses: |
||||||||||||||||||||||||||||
| Lease operating expense |
35,549 | 38,483 | 24,954 | 2,699 | (95 | ) | (a | ) | 101,590 | |||||||||||||||||||
| Production taxes |
— | — | 1,342 | 193 | — | 1,535 | ||||||||||||||||||||||
| Depreciation, depletion and amortization |
26,282 | 78,091 | 27,220 | 2,114 | — | 133,707 | ||||||||||||||||||||||
| Write-down on oil and natural gas properties |
— | 12,603 | 57,927 | — | — | 70,530 | ||||||||||||||||||||||
| Accretion expense |
357 | 1,196 | 3,060 | 276 | (144 | ) | (a | ) | 4,745 | |||||||||||||||||||
| General and administrative expense |
7,148 | 6,762 | 5,950 | 385 | (625 | ) | (b | ) | 19,620 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total operating expenses |
69,336 | 137,135 | 120,453 | 5,667 | (864 | ) | 331,727 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Operating income (loss) |
41,784 | 16,311 | (71,797 | ) | (118 | ) | 864 | (12,956 | ) | |||||||||||||||||||
| Interest expense |
— | (2,919 | ) | (1,367 | ) | (67 | ) | 4,353 | (c | ) | — | |||||||||||||||||
| Price risk management activities (expense) income |
(6,014 | ) | 1,108 | 464 | — | 4,442 | (d | ) | — | |||||||||||||||||||
| Other income |
597 | — | 2 | — | — | 599 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net income (loss) |
$ | 36,367 | $ | 14,500 | $ | (72,698 | ) | $ | (185 | ) | 9,659 | $ | (12,357 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| (a) | Reflects the removal of direct lease operating expense associated with the Katmai Field which is considered an Excluded Asset for ILX Holdings II from the Transactions under the applicable Purchase Agreement. |
| (b) | Reflects the elimination of a certain settlement recorded in the ILX Target Entities’ consolidated statements of operations during the year ended December 31, 2019, which pertains to Excluded Assets under the Purchase Agreement. |
| (c) | Reflects the exclusion of interest expense associated with debt instruments held by ILX Holdings II and the Castex Sellers as the interest expense associated with debt instruments which are not included in the Transactions. |
| (d) | Reflects the elimination of price risk management income (expense) associated with derivatives held by ILX Holdings, ILX Holdings II and the Castex Sellers, which are considered Excluded Assets under the Purchase Agreements. |
| Note 3. | Preliminary Purchase Price Allocation |
Preliminary Estimated Purchase Price
The unaudited pro forma combined financial statements were prepared using the acquisition method of accounting with Talos as the accounting acquirer of the Target Assets. Under the acquisition method of accounting, the purchase price is allocated to the identifiable tangible and intangible assets acquired and liabilities assumed based on their respective fair values, with any excess purchase price allocated to goodwill.
7
The ILX and Castex Acquisition was consummated pursuant to separate Purchase Agreements for aggregate consideration consisting of (i) $385.0 million in cash subject to customary closing adjustments and (ii) an aggregate 110,000 Preferred Shares which subsequently converted to 11.0 million shares of Conversion Stock on March 30, 2020.
The following table summarizes the purchase price, subject to customary post-closing adjustments (in thousands, except per share data):
| Talos Conversion Stock |
11,000 | |||
| Talos Common Stock price per share(1) |
$ | 14.20 | ||
|
|
|
|||
| Conversion Stock value |
$ | 156,200 | ||
| Cash consideration |
$ | 385,000 | ||
| Customary closing adjustments |
(88,034 | ) | ||
|
|
|
|||
| Net cash consideration paid at closing |
$ | 296,966 | ||
|
|
|
|||
| Total purchase price |
$ | 453,166 | ||
|
|
|
| (1) | Represents the closing price of the Company’s Common Stock on February 28, 2020, the date of the closing of the ILX and Castex Acquisition. The purchase price was based on the value of the Conversion Stock as the value approximates the value of the Preferred Shares as a result of the automatic conversion and dividend rights described in that certain Certificate of Designation, Preferences, Rights and Limitations. |
While the Company has substantially completed the determination of the fair values of the assets acquired and liabilities assumed, the Company is still finalizing the fair value analysis related to the oil and natural gas properties acquired and asset retirement obligations assumed. The Company anticipates finalizing the determination of fair values by December 31, 2020.
The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, (in thousands):
| Current assets(1) |
$ | 12,734 | ||
| Property and equipment |
489,701 | |||
| Other long-term assets |
252 | |||
| Current liabilities |
(8,355 | ) | ||
| Other long term liabilities |
(41,166 | ) | ||
|
|
|
|||
| Allocated purchase price |
$ | 453,166 | ||
|
|
|
| (1) | Includes trade and other receivables of $7.1 million, which the Company expects all to be realizable. |
| Note 4. | Pro Forma Adjustments |
The following adjustments and assumptions were made in the preparation of the unaudited pro forma combined consolidated balance sheets:
| (a) | Represents adjustments to reflect the preliminary purchase price allocation to proved and unproved oil and natural gas properties estimated at their fair values as discussed in Note 3 — Preliminary Purchase Price Allocation. |
| (b) | Reflects an adjustment to fair value of an investment in two limited liability companies which own interests in a deepwater floating production system. |
| (c) | Reflects adjustments to accounts payable to include estimated transaction costs totaling $10.1 million, which are offset as an increase to accumulated deficit. These costs represent direct, incremental costs of the Transactions, which are not yet reflected in the historical financial statements of Talos, ILX Holdings, ILX Holdings II and the Castex Sellers. The adjustment does not reflect possible expenditures related to restructuring or integration activities that have yet to be determined. |
8
| (d) | Reflects adjustments to the asset retirement obligations assumed using the Company’s estimates and credit-adjusted risk-free interest rate. |
| (e) | Reflects an increase of $297.0 million in long-term debt attributable to additional borrowings under the revolving bank credit facility to fund the cash portion of the purchase price for the acquisition of the Target Assets as discussed in Note 3 — Preliminary Purchase Price Allocation. Of the additional borrowings, $31.8 million was paid in escrow by the Company contemporaneously with the execution of the Purchase Agreements. |
| (f) | Reflects the pro forma adjustments associated with the Transactions, based on a blended federal and state statutory tax rate of 24.1%. The Transactions are treated as a purchase of assets or interest for income tax purposes. There is no difference between book and tax basis of the Target Assets, thus no pro forma adjustment is needed to reflect an adjustment to deferred taxes. |
| (g) | Reflects the elimination of the historical members’ equity of ILX Holdings, ILX Holdings II and the Castex Sellers in conjunction with the closing of the Transactions. |
| (h) | Reflects an increase to the Company’s common stock and additional paid-in capital to reflect the conversion of 11 million shares of the Conversion Stock as part of the purchase price consideration based on the share price of $14.20 representing the closing price of Talos’ common stock on the Closing Date. |
The following adjustments and assumptions were made in the preparation of the unaudited pro forma combined statement of operations:
| (i) | Reflects the elimination of dry hole and geological costs recognized by ILX Holdings and ILX Holdings II, which was based on their accounting policies which followed the successful method of accounting for oil and natural gas properties. |
| (j) | Reflects the change in depletion that would have been recorded with respect to the fair value attributable to proved oil and natural gas properties acquired as a result of the application of the full cost method of accounting for oil and natural gas activities following the ILX and Castex Acquisition. The pro forma depletion rate for the year ended December 31, 2019 was estimated using the proved property amounts based on the preliminary purchase price allocation and estimates of reserves as of the Closing Date, adjusted for actual production. |
| (k) | Reflects the elimination of the write-down of oil and natural gas properties recognized by ILX Holdings II and Castex 2014 as a result of a pro forma ceiling test calculation. ILX Holdings II’s impairment was based on its accounting policies which followed the successful efforts method of accounting for oil and natural gas properties. Castex 2014’s impairment was based on its accounting policies which followed the full cost method of accounting for oil and natural gas properties. The pro forma ceiling test calculation was performed using the pro forma combined present value of future net revenues from proved reserves discounted at 10%, plus the estimated fair value of combined unproved oil and natural gas properties based on the preliminary purchase price allocation. For the year ended December 31, 2019, there would have been no ceiling test write-down on oil and natural gas properties recognized when considering the combined proved oil and natural gas properties. |
| (l) | Reflects the elimination of direct, incremental costs of the ILX and Castex Acquisition reflected in the Company’s, ILX Holdings, ILX Holdings II and the Castex Sellers’ historical consolidated statements of operations during the year ended December 31, 2019. |
| (m) | Reflects an increase in interest expense associated with $297.0 million of additional borrowings under the revolving bank credit facility to fund the ILX and Castex Acquisition. |
Interest on borrowings under the revolving bank credit facility is based on a current rate of LIBOR plus 3.25%. These borrowings bear interest at variable rates and are subject to interest rate risk. A 1/8% change to the interest rate would result in a change in interest expense related to variable rate financing of $0.4 million for the year ended December 31, 2019.
9
| (n) | Reflects the impact of the change in tax status of the Target Assets from being treated as a partnership for U.S. federal and state income tax purposes to an entity subject to federal and state income taxes. As of December 31, 2019, the Company’s valuation allowance primarily relates to various state operating loss, carry forwards and foreign deferred tax assets. |
| (0) | The weighted average basic and diluted shares of common stock outstanding was calculated assuming that the 11 million shares of Conversion Stock issued to the Sellers were outstanding as of January 1, 2019. |
| Note 5. | Pro Forma Supplemental Oil and Natural Gas Reserve Information |
The following schedules reflect Talos, ILX Holdings, ILX Holdings II and the Castex Sellers combined supplemental information regarding oil and natural gas producing activities, giving effect to the Transactions as if closing had occurred on January 1, 2019. The following estimates of proved oil and natural gas reserves, both developed and undeveloped, represent combined estimated quantities of crude oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively minor expenditures are required for completion.
There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production, the amount and timing of development expenditures and underlying future cash flows, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil, natural gas and NGLs sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.
Pro Forma Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves
The following table presents pro forma estimated proved reserves at the net ownership interests.
| Talos Historical | Target Assets | Pro Forma Combined Company | ||||||||||||||||||||||||||||||||||||||||||||||
| Oil | Natural Gas |
NGL | Total | Oil | Natural Gas |
NGL | Total | Oil | Natural Gas |
NGL | Total | |||||||||||||||||||||||||||||||||||||
| (MMBbl) | (MMcf) | (MMBoe) | (MMBoe) | (MMBbl) | (MMcf) | (MMBoe) | (MMBoe) | (MMBbl) | (MMcf) | (MMBoe) | (MMBoe) | |||||||||||||||||||||||||||||||||||||
| Total proved reserves as of December 31, 2018 |
112,539 | 171,024 | 10,696 | 151,739 | 23,558 | 111,998 | 3,948 | 46,172 | 136,097 | 283,022 | 14,644 | 197,911 | ||||||||||||||||||||||||||||||||||||
| Extensions and discoveries |
11,518 | 21,552 | 620 | 15,730 | — | — | — | — | 11,518 | 21,552 | 620 | 15,730 | ||||||||||||||||||||||||||||||||||||
| Production |
(13,844 | ) | (23,306 | ) | (1,228 | ) | (18,956 | ) | (4,564 | ) | (12,162 | ) | (497 | ) | (7,088 | ) | (18,408 | ) | (35,468 | ) | (1,725 | ) | (26,044 | ) | ||||||||||||||||||||||||
| Revision in estimate |
(5,553 | ) | (15,898 | ) | (1,237 | ) | (9,440 | ) | 859 | (11,570 | ) | (343 | ) | (1,412 | ) | (4,694 | ) | (27,468 | ) | (1,580 | ) | (10,852 | ) | |||||||||||||||||||||||||
| Purchases of reserves |
2,094 | 2,626 | 130 | 2,662 | 117 | 953 | — | 276 | 2,211 | 3,579 | 130 | 2,938 | ||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
| Total proved reserves as of December 31, 2019 |
106,754 | 155,998 | 8,981 | 141,735 | 19,970 | 89,219 | 3,108 | 37,948 | 126,724 | 245,217 | 12,089 | 179,683 | ||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
| Proved developed reserves December 31, 2019 |
72,016 | 115,381 | 6,733 | 97,979 | 14,965 | 68,590 | 1,819 | 28,216 | 86,981 | 183,971 | 8,552 | 126,195 | ||||||||||||||||||||||||||||||||||||
| Proved undeveloped reserves December 31, 2019 |
34,738 | 40,617 | 2,248 | 43,756 | 5,005 | 20,629 | 1,289 | 9,732 | 39,743 | 61,246 | 3,537 | 53,488 | ||||||||||||||||||||||||||||||||||||
10
During 2019 the pro forma proved reserves of the combined company decreased by 18.2 MMBoe of proved reserves, primarily attributable to 26.0 MMBoe of production and a revision of previous estimates of 10.9 MMBoe primarily due to the Phoenix and Ram Powell Fields. The decrease was partially offset by the addition of 15.7 MMBoe of estimated proved reserves from and extensions and discoveries primarily from an evaluation of Green Canyon 21, Pompano and Ewing Bank 305 as well as 3.0 MMBoe added through purchases from the Gunflint Field located in the Mississippi Canyon area.
Pro Forma Standardized Measure of Discounted Future Net Cash Flows
The following table reflects the pro forma standardized measure of discounted future net cash flows at the net ownership interest in proved oil, natural gas and NGL reserves (in thousands)
| At December 31, 2019 | Talos Historical |
Target Assets |
Pro Forma Combined |
|||||||||
| Future cash inflows |
$ | 7,151,875 | $ | 1,378,783 | $ | 8,530,658 | ||||||
| Future costs: |
||||||||||||
| Production |
(1,633,432 | ) | (423,031 | ) | (2,056,463 | ) | ||||||
| Development and abandonment |
(1,464,270 | ) | (223,775 | ) | (1,688,045 | ) | ||||||
| Future income tax expense |
(662,317 | ) | — | (662,317 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Future net cash flows after income taxes |
3,391,856 | 731,977 | 4,123,833 | |||||||||
| Discount at 10% annual rate |
(854,261 | ) | (172,445 | ) | (1,026,706 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Standardized measure of discounted future net cash flows |
$ | 2,537,595 | $ | 559,532 | $ | 3,097,127 | ||||||
|
|
|
|
|
|
|
|||||||
In the foregoing determination of future cash inflows, sales prices used for gas and oil for December 31, 2019 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. See the following table for commodity prices used in determining the standardized measure:
| Talos | ILX Holdings |
ILX Holdings II |
Castex 2014 |
Castex 2016 |
||||||||||||||||
| Oil price per Bbl |
$ | 61.01 | $ | 58.11 | $ | 57.25 | $ | 53.95 | $ | 53.95 | ||||||||||
| Natural gas price per Mcf |
$ | 2.59 | $ | 2.10 | $ | 2.07 | $ | 2.50 | $ | 2.50 | ||||||||||
| NGL price per Bbl |
$ | 26.17 | $ | 14.18 | $ | 13.44 | — | — | ||||||||||||
It is not intended that the standardized measure of discounted future net cash flows represents the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
Pro Forma Changes in Standardized Measure of Discounted Future Net Cash Flows
Pro Forma changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
| Talos Historical |
Target Assets |
Pro Forma Combined |
||||||||||
| Standardized measure, beginning of year |
$ | 3,340,246 | $ | 943,291 | $ | 4,283,537 | ||||||
| Sales and transfers of oil, net gas and NGLs produced during the period |
(665,226 | ) | (225,340 | ) | (890,566 | ) | ||||||
| Net change in prices and production costs |
(849,696 | ) | (213,372 | ) | (1,063,068 | ) | ||||||
| Changes in estimated future development costs |
(75,564 | ) | (39,998 | ) | (115,562 | ) | ||||||
| Previously estimated development costs incurred |
117,049 | 4,333 | 121,382 | |||||||||
| Accretion of discount |
392,526 | 94,329 | 486,855 | |||||||||
| Net changes in income taxes |
129,590 | — | 129,590 | |||||||||
| Purchase of reserves |
75,009 | 4,793 | 79,802 | |||||||||
| Extensions and discoveries |
306,515 | — | 306,515 | |||||||||
| Net change due to revision in quantity estimates |
(199,576 | ) | (21,188 | ) | (220,764 | ) | ||||||
| Changes in production rates (timing) and other |
(33,278 | ) | 12,684 | (20,594 | ) | |||||||
| Standardized measure, end of year |
$ | 2,537,595 | $ | 559,532 | $ | 3,097,127 | ||||||
|
|
|
|
|
|
|
|||||||
11
Exhibit 99.6
September 10, 2020
Mr. W. Kent Webb
Ridgewood Energy Corporation
1254 Enclave Parkway, Suite 600
Houston, Texas 77077
Dear Mr. Webb:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2019, to the ILX Holdings, LLC (ILX) interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. We completed our evaluation on or about February 20, 2020. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by ILX. The estimates in this report have been 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 Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for ILX’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the ILX interest in these properties, as of December 31, 2019, to be:
| Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||
| Oil | NGL | Gas | Present Worth |
|||||||||||||||||
| Category |
(MBBL) | (MBBL) | (MMCF) | Total | at 10% | |||||||||||||||
| Proved Developed Producing |
4,402.5 | 878.4 | 7,849.8 | 201,848.3 | 175,854.1 | |||||||||||||||
| Proved Developed Non-Producing |
1,440.8 | 458.4 | 4,019.2 | 56,092.1 | 38,211.1 | |||||||||||||||
| Proved Undeveloped |
1,377.4 | 898.5 | 8,031.2 | 66,231.4 | 33,137.6 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Proved |
7,220.7 | 2,235.3 | 19,900.2 | 324,171.8 | 247,202.9 | |||||||||||||||
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Gross revenue is ILX’s share of the gross (100 percent) revenue from the properties after deductions for the fixed portion of Delta House’s pipeline fees. Future net revenue is after deductions for ILX’s share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2019. For oil and NGL volumes, the average Light Louisiana Sweet spot price of $61.17 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.578 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $58.11 per barrel of oil, $14.18 per barrel of NGL, and $2.103 per MCF of gas.
Operating costs used in this report are based on operating expense records of Ridgewood Energy Corporation (Ridgewood), the manager of ILX, and our knowledge of similar offshore operations. These costs include production handling agreement fees and the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses are not included. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Ridgewood and are based on authorizations for expenditure, internal planning budgets, and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Ridgewood’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the ILX interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on ILX receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Ridgewood, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Ridgewood, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. John R. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
| Sincerely, | ||||||||
| NETHERLAND, SEWELL & ASSOCIATES, INC. | ||||||||
| Texas Registered Engineering Firm F-2699 | ||||||||
| By: | /s/ C.H. (Scott) Rees III | |||||||
| C.H. (Scott) Rees III, P.E. | ||||||||
| Chairman and Chief Executive Officer | ||||||||
| By: | /s/ John R. Cliver |
By: | /s/ Shane M. Howell | |||||
| John R. Cliver, P.E. 107216 | Shane M. Howell, P.G. 11276 | |||||||
| Vice President | Vice President | |||||||
| Date Signed: September 10, 2020 | Date Signed: September 10, 2020 | |||||||
JRC:PNH
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
| (i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
| (ii) | Same environment of deposition; |
| (iii) | Similar geological structure; and |
| (iv) | Same drive mechanism. |
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
| (i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
| (ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
| (i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
| (ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
| (iv) | Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
| (i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
| (ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
| (iii) | Dry hole contributions and bottom hole contributions. |
| (iv) | Costs of drilling and equipping exploratory wells. |
| (v) | Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
| (i) | Oil and gas producing activities include: |
| (A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; |
| (B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
| (C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
| (1) | Lifting the oil and gas to the surface; and |
| (2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
| a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
| b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
| (ii) | Oil and gas producing activities do not include: |
| (A) | Transporting, refining, or marketing oil and gas; |
| (B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
| (C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
| (D) | Production of geothermal steam. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
| (i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
| (ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
| (iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
| (iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
| (v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
| (vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
| (i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
| (iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
| (iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
| (i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
| (A) | Costs of labor to operate the wells and related equipment and facilities. |
| (B) | Repairs and maintenance. |
| (C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
| (D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
| (E) | Severance taxes. |
| (ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
| (i) | The area of the reservoir considered as proved includes: |
| (A) | The area identified by drilling and limited by fluid contacts, if any, and |
| (B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
| (ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
| (iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
| (iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
| (A) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
| (v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
| a. | Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) |
| b. | Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). |
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
| a. | Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. |
| b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. |
| c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves. |
| d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. |
| e. | Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. |
| f. | Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. |
Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
| (i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
| (ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
| • | The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); |
| • | The company’s historical record at completing development of comparable long-term projects; |
| • | The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; |
| • | The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and |
| • | The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). |
| (iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 6 of 6
Exhibit 99.7
September 10, 2020
Mr. W. Kent Webb
Ridgewood Energy Corporation
1254 Enclave Parkway, Suite 600
Houston, Texas 77077
Dear Mr. Webb:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2019, to the ILX Holdings II, LLC (ILX II) interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. We completed our evaluation on or about February 20, 2020. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by ILX II. The estimates in this report have been 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 Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for ILX II’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the ILX II interest in these properties, as of December 31, 2019, to be:
| Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||
| Category |
Oil (MBBL) |
NGL (MBBL) |
Gas (MMCF) |
Total | Present Worth at 10% |
|||||||||||||||
| Proved Developed Producing |
4,999.6 | 420.1 | 4,125.6 | 175,294.2 | 161,408.2 | |||||||||||||||
| Proved Developed Non-Producing |
1,143.8 | 61.5 | 609.5 | 41,541.2 | 18,123.4 | |||||||||||||||
| Proved Undeveloped |
8,396.3 | 391.4 | 16,163.5 | 275,273.1 | 182,537.0 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Proved |
14,539.7 | 873.0 | 20,898.6 | 492,108.6 | 362,068.6 | |||||||||||||||
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Gross revenue is ILX II’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for ILX II’s share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2019. For oil and NGL volumes, the average Light Louisiana Sweet spot price of $61.17 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.578 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $56.31 per barrel of oil, $13.44 per barrel of NGL, and $2.550 per MCF of gas.
Operating costs used in this report are based on operating expense records of Ridgewood Energy Corporation (Ridgewood), the manager of ILX II, and our knowledge of similar offshore operations. These costs include production handling agreement fees and the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses are not included. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Ridgewood and are based on authorizations for expenditure, internal planning budgets, and actual costs from recent activity. Capital costs are included as required for facilities, new well completions, workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Ridgewood’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the ILX II interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on ILX II receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Ridgewood, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Ridgewood, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. John R. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
| Sincerely, | ||||||||
| NETHERLAND, SEWELL & ASSOCIATES, INC. | ||||||||
| Texas Registered Engineering Firm F-2699 | ||||||||
| By: | /s/ C.H. (Scott) Rees III | |||||||
| C.H. (Scott) Rees III, P.E. | ||||||||
| Chairman and Chief Executive Officer | ||||||||
| By: | /s/ John R. Cliver |
By: | /s/ Shane M. Howell | |||||
| John R. Cliver, P.E. 107216 | Shane M. Howell, P.G. 11276 | |||||||
| Vice President | Vice President | |||||||
| Date Signed: September 10, 2020 | Date Signed: September 10, 2020 | |||||||
JRC:PNH
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
| (i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
| (ii) | Same environment of deposition; |
| (iii) | Similar geological structure; and |
| (iv) | Same drive mechanism. |
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
| (i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
| (ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
| (i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
| (ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
| (iv) | Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
| (i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
| (ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
| (iii) | Dry hole contributions and bottom hole contributions. |
| (iv) | Costs of drilling and equipping exploratory wells. |
| (v) | Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
| (i) | Oil and gas producing activities include: |
| (A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; |
| (B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
| (C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
| (1) | Lifting the oil and gas to the surface; and |
| (2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
| a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
| b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
| (ii) | Oil and gas producing activities do not include: |
| (A) | Transporting, refining, or marketing oil and gas; |
| (B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
| (C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
| (D) | Production of geothermal steam. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
| (i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
| (ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
| (iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
| (iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
| (v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
| (vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
| (i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
| (iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
| (iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
| (i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
| (A) | Costs of labor to operate the wells and related equipment and facilities. |
| (B) | Repairs and maintenance. |
| (C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
| (D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
| (E) | Severance taxes. |
| (ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
| (i) | The area of the reservoir considered as proved includes: |
| (A) | The area identified by drilling and limited by fluid contacts, if any, and |
| (B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
| (ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
| (iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
| (iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
| (A) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
| (v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
| a. | Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) |
| b. | Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). |
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
| a. | Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. |
| b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. |
| c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves. |
| d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. |
| e. | Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. |
| f. | Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. |
Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
| (i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
| (ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
| • | The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); |
| • | The company’s historical record at completing development of comparable long-term projects; |
| • | The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; |
| • | The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and |
| • | The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). |
| (iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 6 of 6