Exhibit 99.3

 

 

 

 

 

 

DGE III Management, LLC and Subsidiaries   Consolidated Financial Statements as of and for the Year Ended December 31, 2017, and Independent Auditors’ Report

 

 

 

 

 

 

 

 

DGE III Management, LLC and Subsidiaries

 

TABLE OF Contents 

 

	Page
INDEPENDENT AUDITORS’ REPORT	1–2
CONSOLIDATED FINANCIAL STATEMENTS AS OF AND FOR THE
YEAR ENDED DECEMBER 31, 2017:
Balance Sheet	3
Statement of Operations	4
Statement of Members’ Capital	5
Statement of Cash Flows	6
Notes to Consolidated Financial Statements	7–25

 

 

 

INDEPENDENT AUDITORS’ REPORT

 

The Members
DGE III Management, LLC:

 

We have audited the accompanying consolidated financial statements of DGE III Management, LLC and subsidiaries (the “Company”), which comprise the consolidated balance sheet as of December 31, 2017, and the related consolidated statement 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 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.

 

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 III Management, LLC and subsidiaries as of December 31, 2017, and the results of its operations and its cash flows for the year 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 the Company 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 6).

 

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 III MANAGEMENT, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2017

(In thousands)

 

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	24,904
Accounts receivable		59,341
Accounts receivable—related party		3,545
Prepaid expenditures and other current assets		12,708
Inventory		26,903
Total current assets		127,401
PROPERTY, PLANT, AND EQUIPMENT:
Oil and gas properties, successful efforts method—net of accumulated
depletion of $71,659 at December 31, 2017		339,831
Other property, plant, and equipment—net of accumulated depreciation
of $743 at December 31, 2017		1,563
Total property, plant, and equipment		341,394
OTHER ASSETS		12,123
DEFERRED FINANCING COSTS—Net amortization of $555 at December 31, 2017		769
LONG TERM RECEIVABLE—Related-party		4,721
INTEREST RECEIVABLE—Related-party		331
TOTAL ASSETS	$	486,739
LIABILITIES AND MEMBERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	8,695
Accrued liabilities		82,884
Liability from price risk management—current		9,775
Total current liabilities		101,354
LONG-TERM LIABILITIES:
Asset retirement obligations		17,742
Long-term notes payable—related party		4,789
Liability from price risk management		3,318
Total long-term liabilities		25,849
COMMITMENTS AND CONTINGENCIES (NOTE 8)
MEMBERS’ CAPITAL		359,536
TOTAL LIABILITIES AND MEMBERS’ CAPITAL	$	486,739

 

See accompanying notes to the consolidated financial statements.

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands)

 

REVENUE:
Oil revenue	$	140,802
Gas revenue		8,009
NGL revenue		6,647
Total revenue		155,458
OPERATING COSTS AND EXPENSES:
Lease operating expenses		28,327
Workover expenses		4,482
Transportation expenses		6,945
Exploration expenses		36,346
Depreciation, depletion, and amortization		56,700
Impairment		2,870
Accretion expense		380
Inventory write-down		5,787
Gain on sale of property		(44	)
General and administrative expenses		12,332
Other operating income		(4,205	)
Total operating costs and expenses		149,920
OPERATING INCOME		5,538
INTEREST AND OTHER EXPENSE—Net		(1,006	)
LOSS FROM PRICE RISK MANAGEMENT ACTIVITIES		(12,503	)
NET LOSS	$	(7,971	)

 

See accompanying notes to the consolidated financial statements.

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands, except units)

 

							Additional
				Capital			Paid In			Retained
	Units			Contributions			Capital			Deficit			Total
BALANCE—January 1, 2017	$	473,415		$	468,575		$	9,290		$	(114,861	)	$	363,004
Equity-based compensation		—			—			4,503			—			4,503
Net loss		—			—			—			(7,971	)		(7,971	)
BALANCE—December 31, 2017		473,415		$	468,575		$	13,793		$	(122,832	)	$	359,536

 

See accompanying notes to the consolidated financial statements.

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2017

(In thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(7,971	)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depreciation, depletion and amortization		56,700
Exploratory dry hole and impairment		8,036
Amortization of deferred financing costs		518
Oil inventory write-down		91
Accretion expense		380
Inventory write-down		5,787
Gain on sale of property		(44	)
Unrealized loss from price risk management		13,093
Equity-based compensation		4,503
Net changes in assets and liabilities:
Accounts receivable		367
Accounts receivable—related party		(1,360	)
Prepaid expenditures		(2,429	)
Inventory		4,322
Interest receivable—related party		(136	)
Long term receivable		(4,721	)
Accounts payable		(11,531	)
Accrued liabilities		35,367
Interest payable on long term notes payable—related party		137
Net cash provided by operating activities		101,109
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties		(87,289	)
Proceeds from sale of property to related party		1,493
Capital expenditures for other property, plant and equipment		(1,355	)
Net cash used in investing activities		(87,151	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of debt issuance costs		(82	)
Net cash used in financing activities		(82	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		13,876
CASH AND CASH EQUIVALENTS—Beginning of year		11,028
CASH AND CASH EQUIVALENTS—End of year	$	24,904

 

See accompanying notes to the consolidated financial statements.

DGE III Management, LLC and Subsidiaries

 

Notes to Consolidated Financial Statements 

AS OF AND FOR THE YEAR ENDED December 31, 2017 

 

1.

Nature of Business and Basis of Presentation

 

Nature of Business—DGE III Management, LLC, a Delaware limited liability company, and its wholly owned subsidiary, Deep Gulf Energy III, LLC were formed and commenced operations on June 30, 2014. Additionally, during 2016 the Company acquired Deep Gulf Operating, LLC from Deep Gulf Energy LP for no consideration. Deep Gulf Operating LLC has no assets or liabilities. Collectively, DGE III Management, LLC, Deep Gulf Energy III, LLC and Deep Gulf Operating, LLC are referred to as the “Company” throughout these notes to the consolidated financial statements. The purpose of the Company is 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) produced 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 III Management, LLC and its wholly owned subsidiaries. All intercompany account balances and transactions have been eliminated.

 

2.

Accounting Policies

 

Use of Estimates—The preparation of consolidated financial statements in conformity with GAAP in the United States 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 consolidated statements 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:

 

Shell Trading (US) Company		42%
Phillips 66 Company		37

  

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. 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 and Other Current Assets—Prepaid expenditures and other current assets consist of deposits, insurance, conveyance of override and prepayments of capital expenditures. Prepaid expenditures and other current assets 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 of 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 $5.8 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 $0.1 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 impairment expense in the period in which it occurs. The Company recognized impairment expense on unproved leasehold costs in the amount of $2.9 million for the year ended December 31, 2017.

 

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 $6.9 million. In 2017 the Company recognized $29.4 million of dry hole costs related to two exploratory wells.

 

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

 

Proved properties	$	354,424
Proved properties under development		31,097
Accumulated depletion		(71,659	)
Total proved		313,862
Unproved properties		25,969
Total oil and gas properties—net of accumulated
depletion	$	339,831

 

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. The Company did not record any impairment charges for proved properties as of December 31, 2017.

 

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.

 

Conveyance of Override Interest—In 2017, the Company conveyed an oil and gas override in proved properties in exchange for future production handling costs, including access to the host platform for a twelve-year period. As a result of the transaction, the Company reduced the cost basis of the properties by $14.4 million and recorded a deferred asset that will be amortized based on units-of-production from the proved oil and gas properties. During 2017, the Company recorded amortization of $0.9 million in depreciation, depletion, and amortization. As of December 31, 2017, the estimated short-term portion of the deferred asset of $1.5 million is included in prepaid expenditures and other current assets and the remaining $12.0 million is included in other noncurrent assets.

 

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 in the consolidated statements of operations.

 

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

 

Asset retirement obligations at January 1, 2017	$	2,934
Liabilities incurred		9,277
Revisions in estimated liabilities		5,151
Accretion expense		380
Asset retirement obligations at December 31, 2017		17,742
Less current portion		—
Asset retirement obligations, long term	$	17,742

 

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

 

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.

 

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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (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 sheets 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 statements of operations. See Note 9.

 

Equity-Based Compensation—Certain of the Company’s employees participate in the equity-based compensation plan of the Company. The Company measures all employee equity-based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognizes compensation cost on a straight-line basis in the consolidated financial statements over the vesting period of each grant according to FASB ASC 718, Compensation—Stock Compensation.

 

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 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. In August 2015, the FASB issued ASU 2015-15 Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line of Credit Arrangements, which confirmed that fees related to line of credit arrangements are not addressed in ASU 2015-03. The Company early-adopted the guidance in ASU 2015-03 and ASU 2015-15 and has presented its debt issuance related to the Company’s Bank Credit Facility as an asset as was required under prior guidance (ASC 835-30, Interest—Imputation of Interest).

 

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 adoption of 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 February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for annual periods beginning after December 31, 2018 and early application is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. 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 March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures and minimum statutory tax withholdings and prescribes certain disclosures to be made in the period the new standard is adopted. ASU 2016-09 is effective for annual periods beginning after December 15, 2017, and early application is permitted. 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 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.

 

3.

Exploratory Well Costs

 

The Company’s net changes in capitalized exploratory well costs for the year ended December 31, 2017, are presented below (in thousands):

 

Balance at January 1, 2017	$	48,433
Additions pending the determination of proved reserves		28,552
Reclassifications to proved properties		(48,433	)
Costs charged to expense		—
Balance at December 31, 2017	$	28,552

 

The following table provides information about exploratory well costs capitalized pending the determination of proved reserves as of December 31, 2017 (in thousands):

 

Exploratory well costs capitalized for less than one year	$	28,552
Exploratory well costs capitalized for
greater than one year		—
Total capitalized exploratory well costs	$	28,552

 

One well, the Mississippi Canyon block 116 well (the “Rampart Deep Well”) comprised $28.6 million of exploratory well costs capitalized at December 31, 2017. The Company drilled the Rampart Deep Well in 2017. The Rampart Deep Well had two primary target sands, the M57 sand and the M58 sand. Based on the successful discovery in the M57 sand, the Company decided to drill a second well Mississippi Canyon block 72 (the “Derbio Well”) adjacent to Rampart Deep Well in 2018. In early 2018, the Company returned to location and began drilling the Derbio Well. The decision to complete the M57 and M58 sands in the Rampart Deep Well will be determined once the Derbio Well drilling is complete.

 

4.

Long-Term Notes Payable

 

The Company has entered into a long-term note payable with a related party, FR DGE III Holdings, LLC. Each individual borrowing under the note accrues simple interest at a rate of 3.1%. The note has no maturity date. Following is a summary of amounts borrowed under the note at December 31, 2017 (in thousands):

 

Notes issued in July 2014	$	206
Notes issued in August 2014		1,193
Notes issued in January 2015		525
Notes issued in June 2015		661
Notes issued in October 2015		623
Notes issued in January 2016		305
Notes issued in March 2016		305
Notes issued in June 2016		245
Notes issued in October 2016		183
Notes issued in November 2016		191
Total principal		4,437
Accrued interest		352
Total notes payable	$	4,789

 

Interest expense to these related parties amounted to $137 thousand for the year ended December 31, 2017. No cash was paid for interest on these notes during the year ended December 31, 2017.

 

5.

Debt

 

The Company has a $150 million Bank Credit Facility with an initial borrowing base of $50 million. The borrowing base is redetermined semi-annually with a maximum borrowing base of $150 million. The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 6.0% to 8.0% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 5.0% to 7.0%. In addition, the Company is obligated to pay a commitment fee rate based on the borrowing base usage of 1.0% to 2.0%. The Bank Credit Facility is secured by substantially all of the oil, gas and NGL assets of the Company. As of December 31, 2017, Company has not drawn on the Bank Credit Facility. The Bank Credit Facility is fully and unconditionally guaranteed by its wholly-owned subsidiary, Deep Gulf Energy III, LLC.

 

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, 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 all covenants at December 31, 2017.

 

The deferred financing costs on the Bank Credit Facility are being amortized on a straight-line basis over the life of the Bank Credit Facility, which amortization is not materially different than if the Company had utilized the effective interest method. Cash paid for interest on credit facility was $504 thousand in 2017.

 

6.

Related Party Transactions

 

The Company’s controlling interest is owned by the same persons who own Deep Gulf Energy Management, LLC; Deep Gulf Energy LP; DGE II Management, LLC; and Deep Gulf Energy II, LLC. Deep Gulf Energy LP; DGE II 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, the Company became the primary related party that allocated shared expense to the related parties. Expenses allocated by the Company to related parties amounted to $9.0 million in 2017. Included in the 2017 allocation was a one-time $5.3 million charge to DGE II Management, LLC. Of the $5.3 million, $4.7 million is classified as long term receivable—related-party on the accompanying consolidated balance sheet and will be paid according the following schedule:

 

	Receivable
January 2019	$	1,672
January 2020		1,630
January 2021		1,419
Long term receivable—Related-party	$	4,721

 

These consolidated financial statements have been prepared from the separate records maintained by the Company 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 3.1% 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. These notes totaled $4.4 million at December 31, 2017. Interest income related to these notes amounted to $135 thousand for the year ended December 31, 2017.

 

7.

Supplementary Cash Flow Information

 

Supplementary noncash investing activities information for the year ended December 31, 2017 consisted of the following (in thousands):

 

Capital expenditures in accounts payable	$	7,221
Accrued capital expenditures		3,280
Prepaid capital expenditures		6,184
Noncash deferred production handling costs		13,485

 

  

 

8.

Commitments and Contingencies

 

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 $1.0 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 $159 million for its supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management (BOEM) 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.

 

Legal Proceedings and Other Contingencies—The Company or its subsidiaries 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 the 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 Company’s current matters cannot be predicted with certainty and there are still uncertainties related to the costs it may incur, based upon an 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 accruals accordingly, and these adjustments could be material.

 

Future minimum lease payments under operating leases having initial or non-cancelable terms in excess of one year are $0.5 million in 2018. Rent expense totaled $0.7 million in 2017.

 

9.

PRICE RISK management ACTIVITIES

 

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:

 

				Contracted
				Volume Oil			Fixed
Commodity Contract Type	Period Covered			(MBbls)			Price
Swaps		January 2018			16.8		$	55.00
Swaps		January–March 2018			42.7			55.55
Swaps		January–March 2018			42.7			55.03
Swaps		January 2018–Dec 2019			64.2			50.05
Swaps		January 2018–Dec 2019			610.1			50.00
Swaps		January 2018–Dec 2019			305.1			50.10
Swaps		January 2018–Dec 2019			305.0			50.10

 

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

 

	Gross Amount of
	Recognized
	Asset (Liability)
	December 31,
	2017
Current derivative asset	$	—
Current derivative liability		(9,775	)
Net current derivative liability	$	(9,775	)
Long term derivative asset	$	—
Long term derivative liability		(3,318	)
Long term derivative liability	$	(3,318	)

 

The Company has entered into master netting arrangements with its counterparties. The amounts above are presented on a net basis in its balance sheets when such amounts are with the same counterparty. The Company recognized $0.6 million in realized gain and $13.1 million in unrealized losses in 2017 related to its derivative financial instruments.

 

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 two counterparties; both of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating and are party under the Company’s credit agreement. The Company enters into derivatives directly with these third parties 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 (in thousands):

 

	Fair Value			Level 1			Level 2			Level 3
At December 31, 2017:
Assets—oil, natural gas and
natural gas liquids
derivatives	$	—		$	—		$	—		$	—
Liabilities—oil, natural gas and
natural gas liquids derivatives		13,093			—			13,093			—

 

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.

 

10.

Employee Incentive Programs

 

Defined Contribution Plan—The Company has a defined contribution savings plan (the Savings Plan) that is established for the benefit of eligible employees of the Company and complies with Section 401(k) of the Internal Revenue Code. The Savings Plan allows employees to contribute up to the maximum allowable amount as dictated by the Internal Revenue Code. Under the Savings Plan, the Company makes net profit contributions in the amount up to 7.5% of each employee’s base salary annually. Participants direct the investment of their accumulated contributions into various plan investment options. The Company contributed $0.6 million to the Savings Plan for the year ended December 31, 2017.

 

Employee Share Ownership Program—The Amended and Restated Operating Agreement of DGE III Management, LLC (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 50,201 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 Common Units have received cumulative cash distributions equal to (i) 150% of the original cash contributed to the Company and (ii) a 10% return on investment, compounded annually. After issuance, the Incentive Units fully vest upon (a) occurrence of a Liquidity Event or (b) occurrence of a Termination Event, other than for Discouraged Terms, which occurs after three years from the date of employment (in which case a portion of the Incentive Units shall vest, as calculated in the Restricted Unit Agreement).

 

The Company had 48,704 Incentive Units outstanding at December 31, 2017. A summary of the Incentive Units activity for the years ended December 31, 2017, is presented below.

 

	Number of			Weighted Average
	Incentive			Estimated Fair
	Units			Value per Unit
Non-vested at January 1, 2017		32,219		$	559
Granted		133			973.40
Vested		(8,687	)		525.89
Forfeited or canceled		(914	)		642.65
Non-vested at December 31, 2017		22,751			570.52

 

Compensation expense related to these awards is recorded on a straight-line basis over the six-year service period in the Company’s consolidated financial statements and is reflected as a corresponding credit to equity. The Company has recognized approximately $4.5 million in compensation expense included in general and administrative expense for the year ended December 31, 2017. The Incentive Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the Company.

 

The fair value of the 2017 grant was estimated at the date of grant using the following weighted average assumptions (dollars in thousands):

 

	Jan-17
	Grant
Total value of equity	$	700,883
Risk-free rate of interest		1.44%
Expected time to a liquidity
event (in years)		5.17
Expected volatility of equity		76.31%
Discount for lack of marketability		40%

 

The total value of the equity is calculated in an iterative process that results in the Common Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the Incentive Units and the volatility of the Incentive Units using a Black-Scholes-Merton model as well.

 

The Company’s unrecognized compensation expense at December 31, 2017, is approximately $13.0 million, which will continue to be recognized on a straight-line basis over the remainder of the requisite service period. The weighted average period over which the unrecognized compensation expense will be recognized is 38 months. At December 31, 2017, the Company has 1,498 Incentive Units authorized but not yet issued.

 

11.

Subsequent Events

 

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

 

The Company entered into five separate commodity contracts after year end. The objective of these commodity contracts is to manage the variability of cash flows resulting from changes in commodity prices for oil production. The commodity contracts are not being designated as hedging instruments and all changes in fair value will be recognized in earnings as they occur. The commodity contracts are summarized in the table below.

 

Commodity

Contracted

Contract

Volume Oil

Fixed

Date Entered

Type

(MbblS)

Price

Period Covered

February 9, 2018

Swap

614.1

$

58.63

March–Dec 2018

February 12, 2018

Swap

272.7

54.25

Jan–June 2019

February 13, 2018

Swap

234.9

53.21

July–Dec 2019

March 9, 2018

Swap

123.1

60.07

April–Dec 2019

March 15, 2018

Swap

53.1

57.22

Jan–June 2019

March 21, 2018

Swap

44.5

57.00

July–Dec 2019

 

  

 

12.

Supplemental Oil and Gas Information (Unaudited)

 

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):

 

Proved properties	$	354,424
Proved properties under development		31,097
Accumulated depletion		(71,659	)
Total proved		313,862
Unproved properties		25,969
	$	339,831

 

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, oil and gas asset retirement obligations totaled $17.7 million.

 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities—Costs incurred in property acquisition, exploration and development activities during the period are presented below (in thousands):

 

Property acquisition costs, proved	$	—
Property acquisition costs, unproved		8,392
Exploration costs		64,617
Development costs		39,457
Total	$	112,466

 

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 the reserve 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 tables set forth estimates of the net proved reserves as of December 31, 2017:

 

	Oil			Gas			NGL			Total
	(MBbls)			(MMcf)			(MBbls)			(Mboe)(3)
Proved reserves at December 31, 2016		23,939			24,596			236			28,274
Revision of previous estimate (1)		1,374			2,303			2,219			3,976
Production		(2,794	)		(2,734	)		(259	)		(3,508	)
Purchase of reserves in place		—			—			—			—
Sales of reserves in place		—			—			—			—
Extensions and discoveries (2)		2,690			2,523			224			3,334
Proved reserves at December 31, 2017		25,209			26,688			2,420			32,076
Proved developed reserves at December 31, 2017		15,915			16,078			1,414			20,008
Proved undeveloped reserves at December 31, 2017		9,294			10,610			1,006			12,068

 

(1)

Revision of previous estimate resulted from positive performance in the following fields:

 

-

Barataria +1.1 MMBOE for performance-based increase in reservoir area

 

-

Odd Job +0.9 MMBOE as evidence of a water drive supports an increased recovery factor estimate; additionally, NGL processing performance supports an updated NGL yield

 

-

Kodiak +0.8 MMBOE as reservoir performance supports an increase in recovery factor estimate

 

-

Tornado +0.8 MMBOE as a performance-based increase in expected ultimate gas-oil-ratio and the associated NGL’s more than offsets a performance-based decrease in oil recovery factor

 

-

South Santa Cruz +0.2 MMBOE as reservoir performance supports an increase in recovery factor estimate

 

-

Big Bend +0.2 MMBOE for performance-based increase in reservoir area

 

(2)

Discoveries include an Exploration well at the Tornado Field, which discovered the B5 and B6 reservoirs in a new fault block and the deepening of a well at the Barataria Field, which discovered the H-9 reservoir

 

(3)

Natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.

 

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 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	$	1,319,487
Future production costs		(318,865	)
Future development and abandonment costs		(222,287	)
Future income tax expense		—
Future net cash flows		778,335
Discount at 10% annual rate		(222,274	)
Standardized measure of discounted future net cash flows	$	556,061

 

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):

 

Standardized measure, beginning of year	$	396,033
Changes during the year:
Sales, net of production		(115,704	)
Net change in prices and production costs		71,180
Changes in future development costs		(28,059	)
Development costs incurred		52,009
Accretion of discount		39,603
Net change in income taxes (1)		—
Purchase of reserves in place		—
Extensions and discoveries		29,153
Sales of reserves in place		—
Net change due to revision in quantity estimates		89,028
Changes in production rates (timing) and other		22,818
Total		160,028
Standardized measure, end of year	$	556,061

 

(1)

The Company’s calculation of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of the estimated future income tax expenses because the Company is not subject to federal or state income taxes on income from proved oil and gas reserves.

 

******