DGE II

Management, LLC

and Subsidiary 

Consolidated Financial Statements as of and for the

Year Ended December 31, 2017, and
Report of Independent Auditors

DGE II Management, LLC and Subsidiary

TABLE OF CONTENTS 

REPORT OF INDEPENDENT AUDITORS

The Members
DGE II Management, LLC:

We have audited the accompanying consolidated financial statements of DGE II Management, LLC and subsidiary (the “Company”), which comprise the consolidated balance sheet as of December 31, 2017, and the related consolidated statements of operations, members’ capital, and cash flows for the year then ended, and the related notes to the consolidated financial statements (“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 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 consolidated 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 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 Company’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 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 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 DGE II Management, LLC and subsidiary as of December 31, 2017, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The Company entered into Master Services and License Agreements with related parties, in which operating services, engineering services, and other cost-sharing services are provided and allocated to each other. The accompanying consolidated financial statements have been prepared from the separate records maintained by DGE III Management, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unrelated company (see Note 5).

Other Matter

Accounting principles generally accepted in the United States of America require that the Supplemental Information on Oil and Natural Gas Operations be presented to supplement the consolidated financial statements. Such information, although not a part of the consolidated financial statements, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the consolidated 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 consolidated financial statements, and other knowledge we obtained during our audit of the consolidated financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

/s/ Deloitte & Touche LLP

March 29, 2018

DGE II MANAGEMENT, LLC AND SUBSIDIARY

CONSOLIDATED BALANCE SHEET 

FOR THE YEAR ENDED DECEMBER 31, 2017 

(In thousands)

See accompanying notes to the consolidated financial statements.

DGE II Management, LLC and Subsidiary 

Notes to Consolidated Financial Statements

As of and for the year ended December 31, 2017

Nature of Business—DGE II Management, LLC, a Delaware limited liability company, and its wholly owned subsidiary, Deep Gulf Energy II, LLC (collectively, the “Company”), were formed in 2007 to acquire, develop, operate, and manage deepwater exploitation and low-risk exploration projects located in the Gulf of Mexico and to produce and market oil, gas and natural gas liquids (NGL) from such properties. The Company has a perpetual existence unless and until dissolved and terminated.

Basis of Presentation—The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). The consolidated financial statements include all the accounts of the Company. Undivided interests in oil, gas and NGL exploration and production joint ventures are consolidated on a proportionate basis. All adjustments that are of a normal, recurring nature and are necessary to fairly present the Company’s consolidated financial position, results of operations and cash flows for the period are reflected.

Principles of Consolidation—The consolidated financial statements include the accounts of DGE II Management, LLC and its wholly owned subsidiary, Deep Gulf Energy II, LLC. All intercompany account balances and transactions have been eliminated.

Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent liabilities at the date of the consolidated financial statements and the related reported amounts of revenue and expenses. Estimates of reserves are used to determine depletion and to conduct impairment analysis. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of expenditures. Actual results could differ from those estimates. Management believes that its estimates are reasonable.

Revenue Recognition and Imbalances—Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and when collectability of the revenue is probable. The Company uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Company is entitled, based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to the Company, will not be sufficient to enable the under-produced owner to recoup its entitled share through production. No receivables are recorded for those wells where the Company has taken less than its share of production. There were no imbalances recorded at December 31, 2017.

Service Charges—The Company’s service charges are generated through standardized industry overhead charges the Company receives as operator of oil, gas and NGL

properties. The service costs associated with third-party reimbursements are recorded within other operating income in the accompanying statement of operations.

Concentration of Credit Risk—The Company extends credit in the form of uncollateralized oil, gas and NGL sales and joint interest owner receivables to various companies in the oil, gas and NGL industry. The following table lists companies that account for at least 10% of oil, gas and NGL sales for the year ended December 31, 2017:

Cash and Cash Equivalents—Cash and cash equivalents consist of all cash balances and highly liquid investments that have an original maturity of three months or less. Cash equivalents are stated at cost, which approximates fair value.

Fair Value Measurements—Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value, and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify that fair value is an exit price representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable 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 statement or quoted prices (unadjusted) for identical assets or liabilities in inactive markets.

Level 3—Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

Market Approach—Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

Cost Approach—Amount that would be required to replace the service capacity of an asset (replacement cost).

Income Approach—Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment may be required in interpreting market data to develop the estimates of fair value for Level 3 inputs to the valuation methodology. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are reported at their carrying amounts, which approximate fair value due to the short term nature of these instruments. The fair values of the Company’s commodity derivatives are discussed in Note 8. Nonrecurring fair value measurements associated with oil, gas and NGL properties are discussed below.

Accounts Receivable—Accounts receivable consist of oil and gas receivables and joint interest billing receivables on wells that the Company operates. Accounts receivable are carried at cost, net of allowance for losses. The Company recognizes an allowance or losses on accounts receivable in an amount equal to the estimated probable losses. The allowance is based on an analysis of historical bad debt experience, current receivables aging and expected future write-offs, as well as an assessment of specific identifiable customer accounts considered at risk or uncollectable. The expense associated with the allowance for doubtful accounts is recorded in our statements of operations as general and administrative expense. As of December 31, 2017 the Company does not have an allowance for doubtful accounts as all of the Company’s receivable’s have been deemed collectable.

Prepaid Expenditures—Prepaid expenditures consist of deposits, insurance and prepayments of capital expenditures on the Company’s non-operated properties. Prepaid expenditures are classified as current and are expected to be realized within twelve months.

Inventory—Inventory consists of tubular and other goods used in the exploration for, and development and production of, offshore oil, gas and NGL wells and oil used for line fill.

Tubular and other goods inventory is stated at cost with adjustments made, as appropriate, to recognize reduction in value. The cost of tubular and other goods inventory is determined by specific identification. During 2017 the Company recorded a $1.3 million noncash charge to write down inventory to the lower of cost or market value.

Oil inventory used for line fill is carried at lower of cost or market with adjustments to oil inventory being recorded in lease operating expenses. The cost of oil inventory used for linefill is determined using weighted average cost, or net realized value. During 2017 the Company recorded a $0.2 million noncash charge to write down oil inventory to the lower of cost or market value.

Property, Plant, and Equipment—The Company uses the successful efforts method of accounting for its oil, gas and NGL properties. Under the successful efforts method of accounting, the Company depletes proved oil and natural gas properties on a units-of-production basis based on production and estimates of proved reserves quantities. The Company assesses depletion on each field. The Company depletes capitalized costs of proved mineral interests over total estimated proved reserves and capitalized costs of wells and related equipment and facilities over estimated proved developed reserves.

Unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Unproved leasehold costs are assessed periodically to determine whether an impairment of the cost of significant individual properties has occurred. The cost of impairment is charged to exploration expense in the period in which it occurs.

Costs incurred for exploratory dry holes, geological and geophysical work, and delay rentals are charged to exploration expense as incurred. In 2017 the Company recognized geological and geophysical expense in the amount of $0.1 million.

The following table lists the total proved and unproved oil, gas and NGL properties at December 31, 2017 (in thousands):

The Company reviews long-lived assets for impairment at least annually and whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted future cash flows, an impairment loss is recorded through a charge to expense. The amount of impairment is based on the estimated fair value of the assets, which is determined by discounting anticipated future net cash flows. The net present value of future cash flows is based on management’s best estimate of future prices, which is determined using published forward prices, applied to projected production volumes, and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable and possible reserves, expected to be produced based on a stipulated amount of capital expenditures.

In 2017, the Company determined that it would be unable to recover the net book value of its investment in certain of its proved properties as a result of decreases to the reserves on certain legacy properties. Accordingly, the Company recorded impairment charges on proved properties of $1.8 million for the year ended December 31, 2017. The Company used an income-based approach to determine impairment that considered probability-weighted cash flows and other significant unobservable Level 3 inputs, including the Company’s estimated future oil, gas and NGL production, costs and capital expenditures, forward prices, and a discount rate believed to be consistent with those applied by market participants. Commodity prices have remained volatile subsequent to December 31, 2017. Commodity price declines and/or changes to the Company’s future capital, production rates, levels of proved reserves and development plans as a consequence of the lower price environment may result in an additional impairment of the carrying value of the Company’s proved and/or unproved properties in the future.

Costs of office furniture and equipment are depreciated on a straight-line basis over seven years. Costs of computer equipment and software are depreciated on a straight-line basis over three years. Costs of leasehold improvements are depreciated on a straight-line basis over the term of the associated lease.

Investments—The Company owns class B shares in Delta House Oil and Gas FPS, LLC. Delta House Oil and Gas FPS, LLC owns the Delta House floating production facility to which certain of the Company’s oil, gas and NGL production flows. The Company accounts for its investments in Delta House Oil and Gas FPS, LLC using the cost method since the

interests provide little influence over the investees’ operating and financial policies. The investment in Delta House Oil and Gas FPS, LLC is recorded on the consolidated balance sheet at cost minus impairment plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of Delta House Oil and Gas FPS, LLC. The Company recorded no upward or downward adjustments to the investment in Delta House Oil and Gas FPS, LLC in 2017. The Company reviews this investment for impairment at least annually and whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. The Company recorded no impairment on the investment in Delta House Oil and Gas FPS, LLC in 2017.

Other Assets—At December 31, 2017, the Company has $0.8 million in credit with the operator of one of its non-operated properties to offset future asset retirement obligations associated with one of its offshore platforms. The Company recorded the liability associated with that platform gross of this asset, in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic (ASC) 410, Asset Retirement and Environmental Obligations.

Asset Retirement Obligations—The Company is required to record a liability for its asset retirement obligations at fair value in the period such obligations are incurred with the associated asset retirement costs being capitalized as part of the carrying cost of the asset. The Company’s asset retirement obligations relate to the plugging, abandonment, dismantlement, removal, site reclamation and similar activities associated with its oil, gas and NGL properties. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. Revisions in the estimates of property lives and cost estimates are capitalized as part of the property balance. Any gain or loss upon settlement of obligations is recognized in income.

The obligation to plug wells is settled when the Company abandons wells in accordance with governmental regulations. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. The estimate of the asset retirement cost is determined, inflated to an estimated future value using a seven-year average of the Consumer Price Index and discounted to present value using the Company’s credit-adjusted risk-free rate.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Revisions in the estimate presented in the table below represent changes to the expected amount and timing of payments to settle the asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of the obligations to plug and abandon oil, gas and NGL wells and the costs to do so. If the Company incurs an amount different from the amount accrued for decommissioning obligations, it recognizes the difference as a gain or loss on settlement of asset retirement obligations on the consolidated statement of operations.

The discounted asset retirement liability is included on the consolidated balance sheet in current and long-term liabilities, and the changes in that liability for the year ended December 31, 2017, were as follows (in thousands):

The Company partially settled asset retirement obligations related to two properties during 2017. The total cash paid to partially settle those obligations was $2.7 million, of which the Company had an asset retirement obligation recorded of $2.6 million. As the result of the settlement the Company recorded a $0.1 million loss on settlement.

In 2017 the Company had upward revisions in our estimated costs to abandon wells primarily due to an increase in assumed rig days on location for blowout preventer certification.

Capitalized Interest—The Company capitalizes interest expense related to significant investments in unproved properties and costs related to wells in the exploration and development phases that are not being depleted. During 2017 the Company recognized interest expense of $58.3 million. In 2017 the Company did not incur any capital costs related to wells in the exploration and development phases, and as a result did not capitalize any interest. Interest is capitalized using the effective interest rate based on the Company’s outstanding borrowings.

Cash paid for interest amounted to $39.4 million in 2017.

Federal Income Taxes—In accordance with the provisions of the Internal Revenue Code, the Company is not subject to federal income tax. Each member includes its share of the Company’s income or loss in its own federal and state income tax returns.

The Company may be subject to state income taxes in certain jurisdictions and applicable state laws; however, currently the Company incurs no state income taxes.

Warrants—As an additional fee for amending the credit agreement, on December 30, 2015 and December 4, 2017, the Company granted certain of the lenders with warrants to purchase shares of Deep Gulf Energy II, LLC with a strike price of $0.01. These warrants are not puttable by the lenders and do not require Deep Gulf Energy II, LLC to settle the warrant with assets. The Company measures all such warrants at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted and recognizes this expense on a straight-line basis in the financial statements over the vesting period. The Company recorded a $2.2 million expense related to the warrants in 2017.

Commodity Derivatives and Price Risk Management Activities—The Company periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that the Company believes have minimal credit risks, may take the form of swaps, options, or collars. The reference prices upon which the commodity derivative contracts are based reflect various market indexes that have a high degree of historical correlation with actual prices received by the Company for its production.

The Company accounts for its commodity derivative instruments in accordance with ASC 815, Derivatives and Hedging, which requires that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company has historically not designated its derivative instruments as cash flow hedges and has recorded all changes in fair value directly on the consolidated statement of operations. See Note 8.

Employee Share Ownership Program—The Amended and Restated Operating Agreement of the Company (the “Operating Agreement”) established Common Units and Incentive Units. Incentive Units are generally intended to be used as incentives for Company employees. The Company was initially authorized to issue 50,000 Incentive Units and may be authorized to issue more under the Operating Agreement. As of December 31, 2017, the Company was authorized to issue 50,000 Incentive Units.

With the exception of annual distributions to cover the assumed tax liability of the Incentive Unit holders, Incentive Units do not participate in cash distributions prior to vesting and until the occurrence of a Liquidity Event in which Common Units have received a multiple on invested capital of at least 1.5X. After issuance, the Incentive Units fully vest (a) annually over a three year period from grant date, (a) upon occurrence of a Liquidity Event or (b) upon occurrence of a Termination Event on Accepted Terms (other than as a result of the voluntary resignation by the Incentive Unit holder without cause).

Recently Issued Accounting Standards—In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and industry-specific guidance in ASC 605 Subtopic 932, Extractive Activities—Oil and Gas, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standard in 2019 using one of two allowable methods: (1) a full retrospective method, which applies the standard to each period presented in the financial statements, or (2) the modified retrospective method, which applies the standard to only the most current period presented, with a cumulative effect adjustment recorded to retained earnings. The Company is continuing to evaluate the provisions of this ASU and has not yet decided upon the method of adoption or determined the impact this standard may have on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the consolidated financial statements are issued. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it plans to alleviate substantial doubt about the Company’s ability to continue as a going

concern. ASU 2014-15 is effective for annual periods ending after December 15, 2016. The adoption of ASU 2014-15 did not have a material impact on the consolidated financial statements and related disclosures.

In April 2015, the FASB issued Accounting Standards Update (ASU) 2015-03, Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company has early-adopted the guidance in ASU 2015-03 retrospectively. As a result of adoption, the Company reclassified unamortized deferred financing costs on the consolidated balance sheet in the amount of $12.7 million as of December 31, 2017, and reduced the carrying value of debt by the same amounts.

In July 2015, the FASB issued ASU 2015-11, Accounting for Inventory, which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as “the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation.” ASU 2015-11 is effective prospectively for annual periods beginning after December 15, 2016, and early application is permitted. The guidance in ASU 2015-11 did not have a material impact on the consolidated financial statements and related disclosures.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (Topic 825), which changes accounting for equity investments and liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on the available for sale debt securities. Entities that are not public business will no longer be required to disclose the fair value of financial instruments carried at amortized costs. ASU 2016-01 is effective fiscal periods beginning after December 15, 2017 and early application is permitted. The Company has early adopted guidance in 2016. The guidance in ASU 2016-01 did not have a material impact on the consolidated financial statements and related disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230)—Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 reduces existing diversity in practice by providing guidance on the classification of eight specific cash receipts and cash payments transactions in the statement of cash flows. The new standard is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted. The Company does not expect the adoption of the new standard to have a material impact on its consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-1, Business Combinations (Topic 805): Clarifying the definition of a Business. ASU 2017-1 reduces existing diversity in practice by providing guidance on the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill impairment, and consolidation. The new standard is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted. The Company does not expect the adoption of the new standard to have a material impact on its consolidated financial statements and related disclosures.

In December 2015, the Company amended its credit agreement (“December 2015 Credit Agreement”) to increase the term loan amount to $300 million, and drew the entire available commitment amount at closing. Amounts outstanding bear interest at the Eurodollar rate or the base prime rate plus a margin, but in no case less than 14.5% per annum. In addition, the borrower must pay an existing lender fee of 1% on the $225 million that was outstanding prior to the amendment on the earlier of September 30, 2018 or the date the Company pays off all of the outstanding debt. In addition, the Company must pay a termination fee to the lenders ranging from $3 million to $9 million on the earlier of September 30, 2018 or the date the Company pays off all of the outstanding debt. The termination fee is recorded in accrued liabilities as of December 31, 2017. The termination fee becomes due and payable according to the following schedule:

Under the December 2015 Credit Agreement, mandatory prepayments on the debt of $33.8 million were due quarterly beginning September 2017 through June 2018 with the remainder of the debt principal to be paid on or before September 30, 2018.

In December 2017, the Company further amended its credit agreement (“December 2017 Credit Agreement”) to delay repayment of the $300 million in principal payments until September 30, 2019 from September 30, 2018. Amounts outstanding under the December 2017 Credit Agreement bear interest at the Eurodollar rate or the base prime rate plus a margin, but in no case less than 15.5% per annum. The December 2017 Credit Agreement allows the Company to pay in kind (“PIK”) 9% per annum of the specified interest; any PIK interest will be added to the principal amount of the outstanding loans. PIK interest recorded in 2017 totals $6.2 million and is classified as long term interest payable. PIK interest, along with the principal amounts, is due on September 30, 2019.

Additionally, in accordance with the December 2017 Credit Agreement, the Company must pay an amendment and extension fee of $3 million due on the earlier of September 30, 2018 or the date the Company pays off all of the outstanding debt, and the Company issued certain of the lenders with warrants to purchase 103,257.19 shares of Deep Gulf Energy II, LLC with a strike price of $0.01, amounting to 20% of the total equity shares outstanding at December 31, 2017. As long as the obligations under the December 2017 Credit Agreement remain outstanding, the Company must issue additional warrants to purchase shares of Deep Gulf Energy II, LLC with the strike price of $0.01 according to the following schedule:

The Company incurred $10.7 million in costs associated with the December 2017 Credit Agreement, of which $7.8 million in lender fees were recognized as a reduction to debt, and the remaining $2.9 million in third party costs were expensed in accordance with ASC 470-50 Debt Modification. Prior to amending its credit agreement with the December 2017 Credit Agreement, the Company had $5.7 million of unamortized debt issuance costs associated with the December 2015 Credit Agreement recognized as a reduction of debt in the accompanying consolidated balance sheet. As a result of ASC 470-50 Debt Modification, at December 31, 2017, $5.5 million of the unamortized debt issuance costs remained capitalized as reduction of debt in the accompanying consolidated balance sheet, and $0.2 million was expensed in the consolidated statement of operations.

The Company’s obligations under the credit agreement are secured by liens on all of Deep Gulf Energy II, LLC’s working interests in its oil, gas and NGL properties. The credit agreement contains customary financial covenants requiring certain ratios to be met on a quarterly, semiannual and annual basis. Other covenants contained in the credit agreement restrict, among other things, capital expenditures, asset dispositions, mergers and acquisitions, dividends, additional debt, liens, investments, and affiliate transactions. The credit agreement also contains customary events of default. The Company was in compliance with these covenants at December 31, 2017.

The Company has entered into long-term notes payable with related parties, FR DGE II Holdings, LLC and DG II Holdings, LLC. Each note accrues simple interest at a rate of 6.5%.

These notes have no maturity date. Following is a summary of the notes payable at December 31, 2017 (in thousands):

Interest expense to these related parties amounted to $0.2 million in 2017 and was recorded in interest expense. No cash was paid for interest on these notes in 2017.

The Company’s controlling interest is owned by the same persons who own Deep Gulf Energy Management, LLC; Deep Gulf Energy LP; DGE III Management, LLC; and Deep Gulf Energy III, LLC. Deep Gulf Energy LP; DGE III Management, LLC; and the Company have entered into Master Services and License Agreements in which operating services, engineering services, and other cost-sharing services are provided to each other. General and administrative expenses are allocated between the parties based on time incurred. In 2015, DGE III Management, LLC, became the primary related party that allocated shared expense to the Company. Expenses allocated to the Company by related parties amounted to $9.0 million in 2017.

Included in the 2017 allocation was a one time $5.3 million charge from DGE III Management, LLC to the Company. Of the $5.3 million owed, $4.7 million is classified as a long term accounts payable and will be paid according to the following schedule:

No expenses were allocated by the Company to related parties in 2017.

These consolidated financial statements have been prepared from the separate records maintained by DGE III Management, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unrelated company.

From time to time, the Company enters into notes receivable bearing simple interest at 6.5% with management members to fund capital contributions, as allowed by the

members’ equity agreements. These notes have no maturity date. Due to the nature of the notes, they are reflected in the accompanying consolidated financial statements as a reduction of equity. As of December 31, 2017, these notes totaled $3.0 million. Interest income related to these notes amounted to $0.2 million in 2017, and was recorded in interest income (expense).

Supplementary non-cash investing and financing activities information for the years ended December 31, 2017 is as follows (in thousands):

Insurance—The Company has insurance policies to mitigate its risk of loss associated with its operations, and it maintains the coverages and amounts of insurance believed to be prudent based on reasonably estimated loss potential. However, not all of the Company’s business activities can be insured at the levels it desires because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).

The Company’s general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and cost of replacement facilities. The Company’s general liability insurance program provides a limit of $150 million (for its interest) for each occurrence and in the aggregate and includes varying deductibles, and its Offshore Pollution Act insurance is also subject to a maximum of $150 million for each occurrence and in the aggregate and includes a $100,000 (100%) retention. The Company separately maintains an operator’s extra expense policy for wells being drilled with additional coverage for an amount up to $1 billion and for producing wells with additional coverage for an amount up to $500 million that would cover costs involved in making a well safe after a blowout or getting the well under control, re-drilling a well to the depth reached prior to the well being out of control or blown out, costs for plugging and abandoning the well, costs for cleanup and containment and for damages caused by contamination and pollution.

The Company customarily has reciprocal agreements with its customers and vendors in which each contracting party is responsible for its respective personnel. Under these agreements, the Company is indemnified against third party claims related to the injury or death of its customers’ or vendors’ personnel. Although there can be no assurance that the amount of insurance the Company carries is sufficient to protect it fully in all events, the Company believes that its insurance protection is adequate for its business operations.

Performance Obligations—Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, and removal of facilities. As of December 31, 2017, the Company had secured performance bonds totaling approximately $39.7 million for its supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in its Gulf of Mexico fields. These performance bonds are uncollateralized. If the Company were to have to obtain additional performance bonds for other reasons, it cannot assure that it would be able to secure any such additional performance bonds on acceptable commercial terms or at all.

Additionally, the Company has an uncollateralized bond to a third party for the plugging and abandonment of Nancy property located at Garden Banks block 463 that the Company exited in 2017. On January 4, 2017 the Company executed an agreement withdrawing from the Nancy property located at Garden Banks block 463. The agreement has an effective date of August 19th, 2016. As part of the agreement, the Company was required to post a performance bond with the purchaser as oblige for the Company’s estimated share of certain future abandonment expenses as the Company retained financial responsibility and liability for its proportionate share of certain of the abandonment liabilities. The Company posted such performance bond on January 4, 2017 in the amount of $2.4 million.

Legal Proceedings and Other Contingencies—The Company is a party to a Deferred Amount Payment Agreement (DAPA) with Energy Resource Technology GOM, Inc. (ERT) related to the Danny Noonan project (Project). Through this DAPA, the Company is required to reimburse ERT $14.5 million from the Project’s net cash flow in monthly installments if the gross production from the Project equals or exceeds 265 BCFE. As of December 31, 2017, the Company does not expect gross production from the Project to equal or exceed 265 BCFE. As of December 31, 2017, the Company had no liability recorded for this DAPA.

The Company or its subsidiary may be named defendants in legal proceedings that arise in the ordinary course of business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation. For each of these matters, the Company evaluates the merits of the case or claim, its exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. The Company discloses matters that are reasonably possibly of negative outcome and are material to its consolidated financial statements. If the Company determines that an unfavorable outcome is probable and is reasonably estimable, the Company accrues for such reasonably estimable outcome. While the outcome of the current matters cannot be predicted with certainty and there are still uncertainties related to the costs the Company may incur, based upon its evaluation and experience, the Company will establish appropriate accruals as it believes are necessary. It is possible; however, that new information or future developments could require the Company to reassess its potential exposure related to these matters and record or adjust its accruals accordingly, and these adjustments could be material.

Objectives and Strategies—The Company is exposed to fluctuations in oil, gas and NGL prices on its production. The Company believes it is prudent to manage the variability in cash flows on a portion of its oil production. The Company utilizes various types of derivative financial instruments, including swaps, costless collars and options, to manage fluctuations in cash flows resulting from changes in commodity prices.

Commodity Derivative Instruments—As of December 31, 2017, the Company had entered into commodity contracts with the following terms:

The following table sets forth the fair values and classification of the Company’s outstanding derivatives (dollars in thousands):

The Company has entered into master netting arrangements with its counterparties. The amounts above are presented on a net basis in its balance sheet when such amounts are with the same counterparty. The Company recognized $0.7 million in realized losses related to its derivative financial instruments in 2017. The Company recognized $1.6 million in unrealized losses related to its derivative financial instruments in 2017.

The Company is subject to the risk of loss on its derivative financial instruments that it would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Company enters into International Swaps and Derivative Association agreements with counterparties to mitigate this risk, when possible. The Company also maintains credit policies with regard to its counterparties to minimize its overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of oil and natural gas counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords the Company netting or set off opportunities to mitigate exposure risk; and (v) potentially requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. The

Company’s assets or liabilities from derivatives at December 31, 2017 represent derivative financial instruments from one counterparty; which is a financial institution that has an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating and is party under the Company’s credit agreement. The Company enters into derivatives directly with this third party and, subject to the terms of the credit agreement, are not required to post collateral or other securities for credit risk in relation to the derivative financial interests.

Fair Value Measurement

The following table presents the fair value hierarchy table for the Company’s assets and liabilities that are required to be measured at fair value on a recurring basis (dollars in thousands):

The Company’s derivatives consist of over–the–counter (“OTC”) contracts which are not traded on a public exchange. As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, the Company has categorized these derivatives as Level 2. The Company values these derivatives using the income approach using inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data, such as forward LIBOR curves. The Company’s estimates of fair value have been determined at discrete points in time based on relevant market data. There were no changes in valuation techniques or related inputs in 2017.

As additional fees for amending the credit agreement in December 2015 and December 2017 (see Note 3), the Company issued certain of the lenders with warrants to purchase 11,928.52 and 103,257.19 shares, respectively, of Deep Gulf Energy II, LLC with a strike price of $0.01. The warrants are not puttable by the lenders and do not require the Company to settle the warrant with assets. The holder of the warrants may exercise the warrant ten years from the issue date of the warrant, and the warrant is not canceled upon repayment of the debt. The Company determined the warrants issued in December 2015 to have an estimated fair value of $497.54 per unit on the issuance date. The Company determined the warrants issued in December 2017 to have an estimated fair value of $46.15 per unit on the issuance date.

On issuance in 2015 and 2017, the Company recorded a discount on the debt for the total value of the warrants, with a corresponding credit to additional paid-in capital. The expense related to these warrants is recognized on a straight-line basis over the remaining term of the debt in the Company’s consolidated financial statements and is reflected as a

corresponding credit to the original issuance discount on the debt. The Company has $6.3 million discount on debt (net of amortization) related to the warrants as of December 31, 2017. The Company recognized approximately $4.4 million in amortization expense for the year ended December 31, 2017, which was recorded as interest expense in the accompanying consolidated statement of operations. No amount was capitalized during the year ended December 31, 2017. See Note 2 Accounting policies for more information on Capitalized interest.

As the warrants have a $0.01 strike price, the warrants are essentially the same as actually holding the underlying shares and are therefore valued as if they are an underlying equity contract. As such, the warrants issued were valued using an income-based approach that considered probability-weighted cash flows and other significant unobservable Level 3 inputs, including Deep Gulf Energy II, LLC’s estimated future oil, gas and NGL production, costs and capital expenditures, forward prices, and a discount rate believed to be consistent with those applied by market participants.

Subsequent events were evaluated through March 29, 2018, which is the date these consolidated financial statements were available to be issued.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities—The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization indicated are presented below as of December 31, 2017 (in thousands):

Included in the depletable basis of the Company’s proved properties is the estimate of the Company’s proportionate share of asset retirement obligations relating to these properties, which are also reflected as asset retirement obligations in the accompanying consolidated balance sheet. At December 31, 2017 the Company’s oil and gas asset retirement obligations totaled $15.2 million.

Estimated Quantities of Proved Oil and Gas Reserves—Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under

varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

A variety of deterministic methods are used to determine the Company’s proved reserve estimates. Standard engineering and geoscience methods or a combination of methods are used, including performance analysis, volumetric analysis, analogy, and reservoir modeling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, the Company’s conclusions necessarily represent only informed professional judgment.

Proved reserves are those quantities of oil and natural gas that 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. 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.

The Company engaged Ryder Scott Company, L.P. Petroleum Consultants and Netherland Sewell and Associates, Inc. to prepare reserves estimates for all of the Company’s estimated proved reserves (by volume) at December 31, 2017. All proved reserves are located in the Gulf of Mexico and all prices are held constant in accordance with SEC rules.

The following table sets forth estimates of the net proved reserves as of December 31, 2017:

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves—The standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. The Company does not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

The standardized measure of discounted future net cash flows at December 31, 2017 is as follows (in thousands):

Future cash inflows are computed by applying the appropriate average of the first-day-of-the-month price for each month within the period January through December of each year presented, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves. For oil and NGL volumes the average Texas intermediate spot price of $51.34 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.98 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 discounted future cash flow estimates do not include the effects of the Company’s derivative financial instruments.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves—The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during the year ended December 31, 2017 (in thousands):

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