Talos Energy (TALO) 8-K Other Events

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