Exhibit 99.6

 

 

 

 

DGE III Management, LLC and Subsidiaries   Unaudited Condensed Consolidated Financial Statements as of June 30, 2018 and December 31, 2017, and for the Six Months Ended June 30, 2018 and 2017

DGE III Management, LLC and Subsidiaries

 

TABLE OF Contents 

 

Page

 

UNAUIDTED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AS OF JUNE 30, 2018 AND DECEMBER 31, 2017, AND FOR THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017:

Balance Sheets	1
Statements of Operations	2
Statement of Members’ Capital	3
Statements of Cash Flows	4
Notes to Unaudited Condensed Consolidated Financial Statements	7–17

 

 

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)

 

		June 30,				December 31,
		2018				2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	84,067			$	24,904
Accounts receivable			50,823				59,341
Accounts receivable—related party			6,127				3,545
Prepaid expenditures and other current assets			7,732				12,708
Inventory			15,879				26,903
Total current assets			164,628				127,401
PROPERTY, PLANT, AND EQUIPMENT:
Oil and gas properties, successful efforts method—net of accumulated depletion
of $109,588 and $71,659 at June 30, 2018 and December 31, 2017, respectively			286,103				339,831
Other property, plant, and equipment, net of accumulated depreciation
of $1,154 and $743 at June 30, 2018 and December 31, 2017, respectively			1,686				1,563
Total property, plant, and equipment			287,789				341,394
OTHER ASSETS			12,123				12,123
DEFERRED FINANCING COSTS—Net amortization of $811 and $555 at
June 30, 2018 and December 31, 2017, respectively			513				769
LONG TERM RECEIVABLE—Related-party			3,048				4,721
INTEREST RECEIVABLE—Related-party			398				331
TOTAL ASSETS		$	468,499			$	486,739
LIABILITIES AND MEMBERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable		$	7,607			$	8,695
Accounts payable - related party			1,052				-
Accrued liabilities			59,981				82,884
Liability from price risk management—current			27,611				9,775
Total current liabilities			96,251				101,354
LONG-TERM LIABILITIES:
Asset retirement obligations			18,537				17,742
Long-term notes payable—related party			4,857				4,789
Liability from price risk management			4,014				3,318
Total long-term liabilities			27,408				25,849
COMMITMENTS AND CONTINGENCIES (NOTE 7)
MEMBERS’ CAPITAL			344,840				359,536
TOTAL LIABILITIES AND MEMBERS’ CAPITAL		$	468,499			$	486,739
See accompanying notes to the unaudited condensed consolidated financial statements.

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017
(In thousands)
(Unaudited)

 

		2018				2017
REVENUE:
Oil revenue		$	129,447			$	62,556
Gas revenue			5,150				3,574
NGL revenue			4,688				2,828
Total revenue			139,285				68,958
OPERATING COSTS AND EXPENSES:
Lease operating expenses			22,783				12,191
Workover expenses			4,076				-
Transportation expenses			4,006				2,578
Exploration expenses			48,756				2,483
Depreciation, depletion, and amortization			39,028				25,395
Impairment			1,044				-
Accretion expense			794				187
Inventory write-down			2,490				-
General and administrative expenses			8,247				6,394
Other operating income			(4,781	)			(1,496	)
Total operating costs and expenses			126,443				47,732
OPERATING INCOME			12,842				21,226
INTEREST AND OTHER EXPENSE—Net			(502	)			(513	)
GAIN (LOSS) FROM PRICE RISK MANAGEMENT ACTIVITIES			(29,389	)			3,630
NET INCOME (LOSS)		$	(17,049	)		$	24,343
See accompanying notes to the unaduited condensed consolidated financial statements.

 

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL
(In thousands, except units)
(Unaudited)

 

										Additional
						Capital				Paid In				Retained
		Units				Contributions				Capital				Deficit				Total
BALANCE—December 31, 2017			473,415			$	468,575			$	13,793			$	(122,832	)		$	359,536
Equity-based compensation			-				-				2,353				-				2,353
Net loss			-				-				-				(17,049	)			(17,049	)
BALANCE—June 30, 2018			473,415			$	468,575			$	16,146			$	(139,881	)		$	344,840
See accompanying notes to the unaudited condensed consolidated financial statements.

 

 

 

 

DGE III MANAGEMENT, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017
(In thousands)
(Unaudited)

 

		2018				2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(17,049	)		$	24,343
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization			39,028				25,395
Exploratory dry hole and impairment			48,975				-
Amortization of deferred financing costs			256				259
Accretion expense			794				187
Inventory write-down			2,490				-
Gain on sale of property			(5	)			-
Unrealized (gain) loss from price risk management			18,532				(2,668	)
Equity-based compensation			2,353				2,355
Net changes in assets and liabilities:
Accounts receivable			8,518				22,004
Accounts receivable—related party			(909	)			2,185
Prepaid expenditures			(1,218	)			5,853
Inventory			6,083				(162	)
Interest receivable—related party			(67	)			(68	)
Accounts payable			4,752				(5,375	)
Accounts payable—related party			1,052				4,640
Accrued liabilities			(22,544	)			(12,087	)
Interest payable on long term notes payable—related party			68				68
Net cash provided by operating activities			91,109				66,929
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties			(31,412	)			(44,182	)
Capital expenditures for other property, plant and equipment			(534	)			(559	)
Net cash used in investing activities			(31,946	)			(44,741	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of debt issuance costs			-				(69	)
Net cash used in financing activities			-				(69	)
NET INCREASE IN CASH AND CASH EQUIVALENTS			59,163				22,119
CASH AND CASH EQUIVALENTS—Beginning of period			24,904				11,028
CASH AND CASH EQUIVALENTS—End of period		$	84,067			$	33,147
See accompanying notes to the unaudited condensed consolidated financial statements.

 

 

 

DGE III Management, LLC and Subsidiaries

 

Notes to Unaudited CONDENSED Consolidated Financial Statements

jUNE 30, 2018

 

 

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 condensed 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 interim-period financial information presented in the condensed consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the condensed consolidated financial position as of June 30, 2018, the changes in the condensed consolidated statement of shareholders’ equity for the six months ended June 30, 2018, the condensed consolidated results of operations for the six months ended June 30, 2018 and 2017, and the condensed consolidated cash flows for the six months ended June 30, 2018 and 2017. The December 31, 2017 condensed consolidated balance sheet was derived from the 2017 audited financial statements. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). As permitted under those rules, certain notes or other financial information that are normally required by GAAP have been condensed or omitted from these interim condensed consolidated financial statements. These condensed consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements as of and for the year ended December 31, 2017.

 

Principles of Consolidation—The condensed 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 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 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 June 30, 2018.

 

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.

 

Property, Plant and Equipment - The following table lists the total proved and unproved oil, gas and NGL properties as of June 30, 2018 and December 31, 2017 (in thousands):

 

		June 30,				December 31,
		2018				2017
Proved properties		$	350,719			$	354,424
Proved properties under development			19,137				31,097
Accumulated depletion			(109,588	)			(71,659	)
Total proved			260,268				313,862
Unproved properties			25,835				25,969
Total oil and gas properties—net of accumulated
depletion		$	286,103			$	339,831

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 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, 2019 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 determined the impact this standard may have on its consolidated financial statements and related disclosures.

 

In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements. ASU 2018-11 provide entities with an additional (and optional) transition method to adopt the new lease requirements by allowing entities to initially apply the requirements by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity’s reporting for the comparative periods presented in the financial statements in which the entity adopts the new lease requirements would continue to be in accordance with current GAAP (Topic 840). An entity electing this additional (and optional) transition method must provide the required Topic 840 disclosures for all periods that continue to be in accordance with Topic 840. The amendments do not change the existing disclosure requirements in Topic 840 (for example, they do not create interim disclosure requirements that entities previously were not required to provide. The new standard is effective for fiscal years beginning after periods beginning after December 31, 2019. Early adoption 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.

 

3.

Exploratory Well Costs

 

The Company’s net changes in capitalized exploratory well costs for the six months ended June 30, 2018 are presented below (in thousands):

 

		June 30,				December 31,
		2018				2017
Balance at January 1, 2018		$	28,552			$	48,433
Additions pending the determination of proved reserves			-				28,552
Reclassifications to proved properties			-				(48,433	)
Costs charged to expense			(28,552	)			-
Balance at June 30, 2018		$	-			$	28,552

 

The following table provides information about exploratory well costs capitalized pending the determination of proved reserves as of June 30, 2018 and December 31, 2017 (in thousands):

 

		June 30,				December 31,
		2018				2017
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 2018, the Company returned to location and drilled the Derbio Well. After evaluation of pay in the M57 sand, the Company determined the Derbio Well was a dry hole, and $16.9 million in exploratory well costs for the Derbio Well were charged to expense. Additionally, as a result of the Derbio Well results, $30.7 million in exploratory well costs, including amounts previously capitalized at December 31, 2017, for the Rampart Deep Well were charged to expense.

 

4.

Debt

 

On December 15, 2016, the Company entered into 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 June 30, 2018, the 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 June 30, 2018.

 

The Company recognized $1.2 million in debt issuance costs associated with the Bank Credit Facility in 2016, all of which were recognized as a deferred financing asset on the condensed consolidated balance sheets at June 30, 2018 and December 31, 2017 in accordance with ASU 2015-03. 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 $253 thousand and $250 thousand for the six months ended June 30, 2018 and 2017, respectively.

 

5.

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 and related parties listed above 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 $0.7 million and $2.0 million for the six months ended June 30, 2018 and 2017, respectively.

 

As of June 30, 2018, the Company has a $4.7 million receivable from a related-party associated with a one-time charge allocation by the Company to Deep Gulf Energy II, LLC, of which $3.0 million is classified as long-term receivable related-party on the accompanying condensed consolidated balance sheet and will be paid according the following schedule:

 

		Long Term
		Receivable
January 2020		$	1,630
January 2021			1,418
Long term receivable—related-party		$	3,048

These condensed 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 condensed consolidated financial statements as a reduction of equity. These notes totaled $4.4 million at June 30, 2018. Interest income related to these notes amounted to $67 thousand for both the six months ended June 30, 2018 and 2017.

 

 

6.

Supplementary Cash Flow Information

 

Supplementary noncash investing activities information for the six months ended June 30, 2018 and 2017 consisted of the following (in thousands):

 

		2018				2017
Capital expenditures in accounts payable		$	1,382			$	4,323
Accrued capital expenditures			2,919				5,021
Prepaid capital expenditures			678				1,496

7.

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 June 30, 2018, the Company had secured performance bonds totaling approximately $187 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 condensed 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.

 

8.

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 June 30, 2018, the Company had entered into commodity contracts with the following terms:

 

		Volume Oil	Fixed
Commodity Contract Type	Period Covered	(MBbls)	Price
Swaps	July 2018-Dec 2019	47.6	$  50.05
Swaps	July 2018-Dec 2019	225.9	$  50.10
Swaps	July 2018-Dec 2019	451.8	$  50.00
Swaps	July 2018-Dec 2019	225.9	$  50.10
Swaps	July 2018-Dec 2018	82.4	$  60.07
Swaps	Jan 2019-June 2019	272.7	$  54.25
Swaps	July 2019-Dec 2019	44.5	$  57.00
Swaps	July 2018-Dec 2018	395.2	$  58.63
Swaps	July 2018-Dec 2018	159.9	$  51.14
Swaps	July 2019-Dec 2019	234.9	$  53.21
Swaps	Jan 2019-June 2019	53.1	$  57.22

 

 

The following table sets forth the fair values and classification of the Company’s outstanding derivatives at June 30, 2018 and December 31, 2017 (in thousands):

 

		Gross Amount of				Gross Amount of
		Recognized				Recognized
		Asset (Liability)				Asset (Liability)
		June 30, 2018				December 31, 2017
Current derivative asset		$	-			$	-
Current derivative liability			(27,611	)			(9,775	)
Net current derivative liability		$	(27,611	)		$	(9,775	)
Long term derivative asset		$	-			$	-
Long term derivative liability			(4,014	)			(3,318	)
Long term derivative liability		$	(4,014	)		$	(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 a $10.9 million realized loss and a $0.9 million realized gain for the six months ended June 30, 2018 and 2017, respectively, related to its derivative financial instruments. The Company recorded a $18.5 million unrealized loss and a $2.7 million unrealized gain for the six months ended June 30, 2018 and 2017, respectively, 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 June 30, 2018 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 June 30, 2018:
Assets—oil, natural gas and
natural gas liquids
derivatives		$	-			$	-			$	-			$	-
Liabilities—oil, natural gas and
natural gas liquids derivatives			31,625				-				31,625				-
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 2018.

 

9.

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.

 

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 June 30, 2018, 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 has recognized approximately $2.4 million in compensation expense included in general and administrative expense for each of the six-month periods ended June 30, 2018 and 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.

 

10.

Subsequent Events

 

Subsequent events were evaluated through September 14, 2018, which is the date these consolidated financial statements were available to be issued.

 

On August 3^rd, 2018, the Company along with Deep Gulf Energy Management, LLC; Deep Gulf Energy LP; DGE II Management, LLC; and Deep Gulf Energy II, LLC entered into a securities purchase agreement with Kosmos Energy Gulf of Mexico, LLC to sell all shareholder interests in the Company; Deep Gulf Energy Management, LLC; Deep Gulf Energy LP; DGE II Management, LLC; and Deep Gulf Energy II, LLC for a total consideration of $1.225 billion, subject to certain adjustments. This transaction is expected to close during the third quarter of 2018.

 

******