Exhibit 99.5

 

 

 

 

DGE II Management, LLC and Subsidiary   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 II Management, LLC and Subsidiary

 

TABLE OF CONTENTS 

 

Page

 

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:

 

Balance Sheets	1
Statements of Operations	2
Statement of Members’ Capital	3
Statements of Cash Flows	4
Notes to Unaudited Condensed Consolidated Financial Statements	7–16

 

 

 

 

DGE II MANAGEMENT, LLC AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)

 

		June 30,				December 31,
		2018				2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	85,989			$	51,524
Accounts receivable			18,855				15,351
Accounts receivable—related party			6				43
Current asset from price risk management activities			49				735
Prepaid expenditures			3,570				4,766
Inventory			1,816				2,684
Total current assets			110,285				75,103
PROPERTY, PLANT, AND EQUIPMENT:
Oil and gas properties, successful efforts method—net of accumulated
depletion of $314,275 and $284,352 at June 30, 2018 and December 31, 2017, respectively			216,393				232,047
Other property, plant, and equipment—net of accumulated depreciation
of $2,183 and $2,084  at June 30, 2018 and December 31, 2017, respectively			216				315
Total property, plant, and equipment			216,609				232,362
INVESTMENTS			3,819				3,819
OTHER ASSETS			800				800
INTEREST RECEIVABLE—related party			1,688				1,591
TOTAL ASSETS		$	333,201			$	313,675
LIABILITIES AND MEMBERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable		$	987			$	269
Accounts payable—related party			6,069				4,258
Accrued liabilities			28,680				20,769
Liability from price risk management activities			12,890				4,200
Current portion of asset retirement obligations			777				330
Interest payable			357				856
Total current liabilities			49,760				30,682
LONG-TERM LIABILITIES:
Asset retirement obligations			13,015				15,227
Long-term accounts payable—related party			3,048				4,721
Long-term notes payable—related party			4,661				4,564
Liability from price risk management activities			1,918				1,477
Long term interest payable			20,310				6,201
Long-term debt—net of original issuance discount and
issuance costs of $9,126 and $12,676 at June 30, 2018 and December 31, 2017, respectively			290,874				287,324
Total long-term liabilities			333,826				319,514
COMMITMENTS AND CONTINGENCIES (NOTE 6)
MEMBERS’ DEFICIT			(50,385	)			(36,521	)
TOTAL LIABILITIES AND MEMBERS’ CAPITAL		$	333,201			$	313,675

 

See accompanying notes to the unaudited condensed consolidated financial statements.

 

 

 

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

 

		2018				2017
REVENUE:
Oil revenue		$	81,893			$	67,543
Gas revenue			3,430				4,900
NGL revenue			3,429				3,283
Total revenue			88,752				75,726
OPERATING COSTS AND EXPENSES:
Lease operating expenses			15,433				15,779
Workover expenses			7,904				2,369
Transportation expenses			1,730				3,830
Exploration expenses			45				14
Depreciation, depletion, and amortization			30,022				38,488
Inventory write-down			511				-
Accretion expense			1,114				740
General and administrative expenses			665				110
Other operating income			(71	)			(1,537	)
Total operating costs and expenses			57,353				59,793
OPERATING INCOME			31,399				15,933
OTHER EXPENSE			-				(1,794	)
INTEREST EXPENSE, NET			(29,885	)			(27,398	)
INCOME (LOSS) FROM PRICE RISK MANAGEMENT ACTIVITIES			(15,378	)			6,829
NET LOSS		$	(13,864	)		$	(6,430	)
See accompanying notes to the unaudited condensed consolidated financial statements.

 

 

 

DGE II MANAGEMENT, LLC AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL (DEFICIT)
(In thousands, except units)
(Unaudited)

 

										Additional
						Capital				Paid-In				Retained
		Units				Contributions				Capital				Deficit				Total
BALANCE—December 31, 2017			382,695			$	382,695			$	10,700			$	(429,916	)		$	(36,521	)
Net loss			-				-				-				(13,864	)			(13,864	)
BALANCE—June 30, 2018			382,695			$	382,695			$	10,700			$	(443,780	)		$	(50,385	)
See accompanying notes to the unaudited condensed consolidated financial statements.

 

 

 

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

 

		2018				2017
OPERATING ACTIVITIES:
Net loss		$	(13,864	)		$	(6,430	)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation, depletion, and amortization			30,022				38,488
Amortization of deferred financing costs			3,576				3,398
Non-cash fees on long-term debt			1,500				1,500
Non-cash loss on price risk management activities			9,328				(7,519	)
Accretion expense			1,114				740
Inventory write-down			511				-
Settlement of asset retirement obligations			(2,879	)			(369	)
Long term interest payable			14,109				-
Net changes in assets and liabilities:
Accounts receivable			(3,504	)			7,367
Accounts receivable—related party			37				(4,021	)
Prepaid expenditures			(801	)			1
Inventory			357				944
Interest receivable—related party			(97	)			(97	)
Accounts payable			718				(12,973	)
Accounts payable—related party			(4,784	)			(1,720	)
Accrued liabilities			6,900				(1,128	)
Interest payable			(499	)			(148	)
Interest payable—related party			97				96
Net cash provided by operating activities			41,841				18,129
INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties			(7,350	)			(9,921	)
Proceeds from sale of property to related party							905
Net cash used in investing activities			(7,350	)			(9,016	)
FINANCING ACTIVITIES:
Payment of debt issuance costs			(26	)			(34	)
Net cash used in financing activities			(26	)			(34	)
NET INCREASE IN CASH AND CASH EQUIVALENTS			34,465				9,079
CASH AND CASH EQUIVALENTS—Beginning of year			51,524				31,921
CASH AND CASH EQUIVALENTS—End of year		$	85,989			$	41,000
See accompanying notes to the unaudited condensed consolidated financial statements.

 

DGE II Management, LLC and Subsidiary

 

Notes to Unaudited CONDENSED Consolidated Financial Statements

(In Thousands)

 

 

1.

Nature of Business and Basis of Presentation

 

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

 

Basis of Presentation— The interim 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. These 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 II Management, LLC and its wholly owned subsidiary, Deep Gulf Energy II, LLC. All intercompany account balances and transactions have been eliminated.

 

2.

Accounting Policies

 

Use of Estimates—The preparation of condensed consolidated 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 condensed 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 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 7. 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, 2018				December 31, 2017
Proved properties		$	505,193			$	509,197
Proved properties under development			24,912				-6,639
Accumulated depletion			(314,275	)			(284,352	)
Total proved			215,830				231,484
Unproved properties			563				563
Total oil and gas properties - net of accumulated depletion		$	216,393			$	232,047

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.

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 III Management, LLC; and Deep Gulf Energy III, LLC. Deep Gulf Energy LP; DGE III Management, LLC; and the Company have entered into Master Services and License Agreements in which operating services, engineering services, and other cost-sharing services are provided to each other. General and administrative expenses are allocated between the parties based on time incurred. In 2015, DGE III Management, LLC, became the primary related party that allocated shared expense to the Company. Expenses allocated to the Company by related parties amounted to $0.7 million and $2.0 million for six the months ended June 30, 2018 and 2017, respectively.

 

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

 

		Long Term
		Payable
January 2020			1,630
January 2021			1,418
Long term accounts payable—related party		$	3,048

No expenses were allocated by the Company to related parties for the six months ended June 30, 2018 and 2017.

 

 

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

 

From time to time, the Company enters into notes receivable bearing simple interest at 6.5% with management members to fund capital contributions, as allowed by the members’ equity agreements. These notes have no maturity date. Due to the nature of the notes, they are reflected in the accompanying condensed consolidated financial statements as a reduction of equity. As of June 30, 2018, these notes totaled $3.0 million. Interest income related to these notes amounted to $97 thousand for both the six months ended June 30, 2018 and 2017.

 

4.

Debt

 

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

 

			Fee
Date			(in thousands)
December 30, 2015 through December 31, 2016			$	3,000
January 1, 2017 through June 30, 2017				4,500
July 1, 2017 through December 31, 2017				6,000
January 1, 2018 through June 30, 2018				7,500
July 1, 2018 through September 30, 2018				9,000

In December 2017, the Company further amended its credit agreement (“December 2017 Credit Agreement”) to delay repayment of the $300 million in principal payments until September 30, 2019 from September 30, 2018. Amounts outstanding under the December 2017 Credit Agreement bear interest at the Eurodollar rate or the base prime rate plus a margin, but in no case less than 15.5% per annum. The December 2017 Credit Agreement allows the Company to pay in kind (“PIK”) 9% per annum of the specified interest; any PIK interest will be added to the principal amount of the outstanding loans. PIK interest recorded at June 30, 2018 and December 31, 2017 totaled $20.3 million and $6.2 million, respectively, and is classified as long term interest payable. PIK interest, along with the principal amounts, is due on September 30, 2019.

 

As part of the December 2017 Credit Agreement there have been no changes to the termination fees that were included in the December 2015 Credit agreement.

 

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

 

			Additional				Percentage
Date			Warrants				Ownership
September 30, 2018				34,784.33				5	%
December 31, 2018				39,976.02				5
March 31, 2019				46,423.77				5
June 30, 2019				119,630.49				10
				240,814.61				25	%

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

 

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

 

 

The credit agreement also contains customary events of default. The Company was in compliance with these covenants at June 30, 2018.

 

5.

Supplementary Cash Flow Information

 

Supplementary non-cash investing and financing activities information for the six months ended June 30, 2018 and 2017 is as follows (in thousands):

 

		2018				2017
Capital expenditures in accounts payable		$	-			$	5,428
Capital expenditures in accounts payable related party			(4,922	)			-
Accrued capital expenditures			-				743
Non-cash deferred financing costs			1,500				1,500

6.

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 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 $28.9 million for its supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in its Gulf of Mexico fields. These performance bonds are uncollateralized. If the Company were to have to obtain additional

 

 

performance bonds for other reasons, it cannot assure that it would be able to secure any such additional performance bonds on acceptable commercial terms or at all.

 

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

 

Legal Proceedings and Other Contingencies—The Company is a party to a Deferred Amount Payment Agreement (DAPA) with Energy Resource Technology GOM, Inc. (ERT) related to the Danny Noonan project (Project). Through this DAPA, the Company is required to reimburse ERT $14.5 million from the Project’s net cash flow in monthly installments if the gross production from the Project equals or exceeds 265 BCFE. As of June 30, 2018, the Company does not expect gross production from the Project to equal or exceed 265 BCFE. As of June 30, 2018, the Company had no liability recorded for this DAPA.

 

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

 

7.

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:

 

		Contracted
Commodity		Volume Oil	Fixed	Floor	Ceiling
Contract Type	Period Covered	(MBbls)	Price	Price	Price
Puts	Jul–Dec 2018	284.1	$      53.00
Swaps	Jul–Dec 2018	412.8	56.08
Swaps	Jul 2018–Sep 2019	560.5	53.53
Collars	Jul–Dec 2018	57.0		$     62.29	$   66.35
Collars	Jan–Jun 2019	338.8		57.77	63.30
Swaps	Jul 2018	4.0	68.00

 

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		$	49			$	735
Current derivative liability			(12,890	)			(4,200	)
Net current derivative liability			(12,841	)			(3,465	)
Long term derivative asset		$	-			$	-
Long term derivative liability			(1,918	)			(1,477	)
Net long term derivative liability		$	(1,918	)		$	(1,477	)

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 ($6.1) million and a ($0.7) million in realized loss related to its derivative financial instruments in the six months ended June 30, 2018 and 2017, respectively. The Company recognized a ($9.3) million unrealized loss and a $7.5 million unrealized gain related to its derivative financial instruments in the six months ended June 30, 2018 and 2017, respectively.

 

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

 

Fair Value Measurement

 

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

 

		Fair Value				Level 1				Level 2				Level 3
At June 30, 2018:
Assets—oil, natural gas and
natural gas liquids derivatives		$	49			$	-			$	49			$	-
Liabilities—oil, natural gas and
natural gas liquids derivatives			(14,808	)			-				(14,808	)			-
At December 31, 2017:
Assets—oil, natural gas and
natural gas liquids derivatives		$	735			$	-			$	735			$	-
Liabilities—oil, natural gas and
natural gas liquids derivatives			(5,677	)			-				(5,677	)			-

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.

 

8.

Subsequent Events

 

Subsequent events were evaluated through Septemeber 14, 2018, which is the date these condensed 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 III Management, LLC; and Deep Gulf Energy III, 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.

 

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