Exhibit 99.1

 

 

 

 

Deep Gulf Energy LP   Financial Statements as of and for the Year Ended December 31, 2017, and Independent Auditors’ Report

 

 

 

 

 

 

 

 

Deep Gulf Energy LP

 

TABLE OF Contents
	Page
INDEPENDENT AUDITORS’ REPORT	1–2
FINANCIAL STATEMENTS AS OF AND FOR THE
YEAR ENDED DECEMBER 31, 2017:
Balance Sheet	3
Statement of Operations	4
Statement of Partners’ Capital	5
Statement of Cash Flows	6
Notes to Financial Statements	7–18

 

 

 

INDEPENDENT AUDITORS’ REPORT

 

The Partners
Deep Gulf Energy LP

 

We have audited the accompanying financial statements of Deep Gulf Energy LP (the “Partnership”), which comprise the balance sheet as of December 31, 2017, and the related statements of operations, partners’ capital, and cash flows for the year then ended, and the related notes to the financial statements (“financial statements”).

 

Management’s Responsibility for the Financial Statements

 

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

 

Auditors’ Responsibility

 

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

 

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Partnership’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

 

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

 

Opinion

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Deep Gulf Energy LP 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 Partnership 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 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 Partnership had been operated as an unrelated company (see Note 3).

 

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 financial statements. Such information, although not a part of the financial statements, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the financial statements, and other knowledge we obtained during our audit of the 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

 

DEEP GULF ENERGY LP
BALANCE SHEET
AS OF DECEMBER 31, 2017
(In thousands)

 

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,606
Accounts receivable, net		1,339
Prepaid expenditures		281
Total current assets		11,226
PROPERTY, PLANT, AND EQUIPMENT—
Oil and gas properties, successful efforts method—net of accumulated
depreciation, depletion and amortization of $388,398 at December 31, 2017		10,638
OTHER ASSETS		725
TOTAL ASSETS	$	22,589
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	445
Accounts payable—related-party		102
Accrued liabilities		4,015
Current portion of asset retirement obligations		5,150
Total current liabilities		9,712
LONG-TERM LIABILITIES—Asset retirement obligations		11,883
COMMITMENTS AND CONTINGENCIES (Note 4)
PARTNERS’ CAPITAL—Limited partners’ interest		994
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	22,589
See accompanying notes to the financial statements.

 

 

 

DEEP GULF ENERGY LP
STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2017
(In thousands)

 

REVENUE:
Oil revenue	$	6,975
Gas revenue		1,105
NGL revenue		262
Total revenue		8,342
OPERATING COSTS AND EXPENSES:
Lease operating expenses		4,463
Workover expenses		1,471
Transportation expenses		248
Exploration expenses		18
Depreciation, depletion, and amortization		1,906
Impairment		4,537
Accretion expense		786
General and administrative expenses		326
Gain on sale of inventory		(1,171	)
Other operating income		(16	)
Total operating costs and expenses		12,568
OPERATING LOSS		(4,226	)
INTEREST EXPENSE		(1	)
NET LOSS	$	(4,227	)
See accompanying notes to the financial statements.

 

DEEP GULF ENERGY LP
STATEMENT OF PARTNERS’ CAPITAL
FOR THE YEAR ENDED DECEMBER 31, 2017
(In thousands)

 

	Limited												Total
	Partners’									Retained			Partners’
	Units			Contributions			Distributions			Earnings			Capital
BALANCE—January 1, 2017		100		$	148,601		$	(283,875	)	$	140,495		$	5,221
Net loss		—			—			—			(4,227	)		(4,227	)
BALANCE—December 31, 2017		100		$	148,601		$	(283,875	)	$	136,268		$	994
See accompanying notes to the financial statements.

 

DEEP GULF ENERGY LP
STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2017
(In thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(4,227	)
Adjustments to reconcile net cash provided by
operating activities:
Depreciation, depletion, and amortization		1,906
Impairment		4,537
Bad debt expense		142
Accretion expense		786
Settlement of asset retirement obligations		(3,183	)
Net changes in assets and liabilities:
Accounts receivable		6,473
Prepaid expenditures		787
Other assets		(325	)
Accounts payable		(5,336	)
Accounts payable—related-party		(1,082	)
Accrued liabilities		1,772
Net cash provided by operating activities		2,250
CASH FLOWS FROM INVESTING ACTIVITIES—
Capital expenditures for oil and gas properties—net of reimbursements		16
Net cash provided by investing activities		16
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,266
CASH AND CASH EQUIVALENTS—Beginning of year		7,340
CASH AND CASH EQUIVALENTS—End of year	$	9,606
See accompanying notes to the financial statements.

 

 

Deep Gulf Energy LP

Notes to Financial Statements

AS OF AND FOR THE YEAR ENDED December 31, 2017 

 

1.

Nature of Business and Basis of Presentation

 

Nature of Business—Deep Gulf Energy LP, a Texas limited partnership (the “Partnership”), was formed 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 Partnership has a perpetual existence unless and until dissolved and terminated.

 

Basis of Presentation—The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). The financial statements include all the accounts of the Partnership. 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 Partnership’s financial position, results of operations and cash flows for the period are reflected.

 

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 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 Partnership uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Partnership 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 Partnership, 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 Partnership has taken less than its share of production. There were no imbalances recorded at December 31, 2017.

 

Service Charges—The Partnership’s service charges are generated through standardized industry overhead charges the Partnership 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 statements of operations.

 

Concentration of Credit Risk—The Partnership 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	82 %
Chevron Natural Gas	11 %

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 Partnership 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.

 

Accounts Receivable—Accounts receivable consist of oil and gas receivables and joint interest billing receivables on wells that the Partnership operates. Accounts receivable are carried at cost, net of allowance for losses. The Partnership 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 Partnership has an allowance for doubtful accounts in the amount of $142 thousand.

 

Prepaid Expenditures—Prepaid expenditures consist of deposits and insurance. Prepaid expenditures are classified as current and are expected to be realized within twelve months.

 

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

 

Unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Unproved leasehold costs are assessed periodically to determine whether an impairment of the cost of significant individual properties has occurred. The cost of impairment is charged to exploration expense in the period in which it occurs. Costs incurred for exploratory dry holes, geological and geophysical work, and delay rentals are charged to exploration expense as incurred.

 

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

Proved properties—net of accumulated depreciation, depletion and
amortization	$	10,370
Unproved properties		268
Total oil and gas properties—net of accumulated depreciation,
depletion and amortization	$	10,638

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

discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable and possible reserves, expected to be produced based on a stipulated amount of capital expenditures.

In 2017, the Partnership determined that it would be unable to recover the net book value of its investment in certain of its proved properties due to current reserves profile of the wells. Accordingly, the Partnership recorded impairment charges on the Sargent Property located at Garden Banks block 339 of $0.7 for the year ended December 31, 2017. The Partnership used an income-based approach to determine impairment that considered cash flows and other significant unobservable Level 3 inputs, including the Partnership’s estimated future oil, gas and NGL production, costs and capital expenditures, forward prices, and a discount rate believed to be consistent with those applied by market participants. Additionally, in 2017 the Partnership recorded impairment charges of $3.8 million related to properties that are no longer producing.

 

Commodity prices have remained volatile subsequent to December 31, 2017. Further price declines from these levels and/or changes to the Partnership’s future capital, production rates, levels of proved reserves and development plans as a consequence of the lower price environment may result in an additional impairment of the carrying value of the Partnership’s proved and/or unproved properties in the future.

 

In 2017 the Partnership received proceeds of $1.2 million on the sale inventory on a well that was previously plugged and abandoned. The partnership recognized a gain of $1.2 million on the sale of inventory.

 

Other Assets—The Partnership has $0.4 million in credit with another operator to offset future asset retirement obligations associated with one of the Partnership’s offshore platforms. Additionally, the Partnership has a deposit of $0.3 million as collateral related to a bond for the Nancy well, which the Partnership exited in early 2017. See Note 4 for more information about the collateralized bond. The Partnership has recorded the liability associated with the platform and the Nancy well, gross of these assets, in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic (ASC) 410, Asset Retirement and Environmental Obligations.

 

Asset Retirement Obligations—The Partnership 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 Partnership’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 Partnership abandons wells in accordance with governmental regulations. The Partnership 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 Partnership’s credit-adjusted risk-free rate.

 

In estimating the liability associated with its asset retirement obligations, the Partnership 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 Partnership incurs an amount different from the amount accrued for decommissioning obligations, it recognizes the difference as a gain or loss on settlement of asset retirement obligations on the statements of operations.

The discounted asset retirement liability included on the balance sheets in current and noncurrent liabilities, and the changes in that liability for the year ended December 31, 2017, were as follows (in thousands):

Asset retirement obligations at beginning of year	$	13,937
Settlement of asset retirement obligations		(3,183	)
Revisions in estimated liabilities		5,493
Accretion expense		786
Asset retirement obligations at end of year		17,033
Less current portion		(5,150	)
Asset retirement obligations, long term	$	11,883

 

The Partnership partially settled asset retirement obligations related to four different properties during 2017. The total cost to partially settle those obligations was $3.2 million, and has a remaining asset retirement obligation of $5.1 million.

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

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

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

Employee Share Ownership Program—The Amended and Restated Limited Partnership Agreement of the Partnership (the “Operating Agreement”) established Common Units and Incentive Units. Incentive Units are generally intended to be used as incentives for Partnership employees. The Partnership 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 Partnership was authorized to issue 50,000 Incentive Units.

With the exception of annual distributions to cover the assumed tax liability of the Incentive Unit holders, Incentive Units do not participate in cash distributions prior to vesting and until non-employee holders of Common Units have received a 2.00X return on

investment multiple. After issuance, the Incentive Units fully vest (a) annually over a three year period from grant date, (b) upon occurrence of a Liquidity Event, or (c) upon occurrence of a Tag Along Sale.

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 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which entity expects to be entitled in exchange for those goods or services. The Partnership 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 Partnership is continuing to evaluate the provisions of this ASU, and has not determined the impact this standard may have on its financial statements and related disclosures or decided upon the method of adoption.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the Partnership’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. 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 Partnership’s ability to continue as a going concern. ASU 2014-15 is effective for annual periods ending after December 15, 2016. The Partnership adopted the guidance in ASU 2014-15 in 2016. The adoption of ASU 2014-15 did not have a material impact on our financial statements.

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 Partnership 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, Statements 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 statements of cash flows. For nonpublic entities, the new standard is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted. The Partnership does not expect the adoption of the new standard to have a material impact on its 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 Partnership does not expect the adoption of the new standard to have a material impact on its consolidated financial statements and related disclosures.

3.

Related-Party Transactions

The Partnership’s controlling interest is owned by the same persons who own DGE II Management, LLC; Deep Gulf Energy II, LLC; DGE III Management, LLC; and Deep Gulf Energy III, LLC. DGE II Management, LLC; DGE III Management, LLC; and the Partnership have entered into Master Services and License Agreements in which operating services, engineering services, and other cost-sharing services are provided to each other. As of December 31, 2017, the Partnership had related party payables to other entities under this Master Services and License Agreement of $0.1 million.

These 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 Partnership had been operated as an unrelated company.

4.

Commitments and Contingencies

Insurance—The Partnership 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 Partnership’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 Partnership’s general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and cost of replacement facilities. Its general liability insurance program provides a limit of $150 million (for the Partnership’s interest) for each occurrence and in the aggregate and includes varying deductibles, and the Partnership’s Offshore Pollution Act insurance is also subject to a maximum of $35 million for each occurrence and in the aggregate and includes a $100,000 (100%) retention. The Partnership separately maintains an operator’s extra expense policy for wells being drilled and producing wells with additional coverage for an amount up to $100 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 Partnership customarily has reciprocal agreements with its customers and vendors in which each contracting party is responsible for its respective personnel. Under these agreements, the Partnership is indemnified against third party claims related to the injury or death of its customers’ or vendors’ personnel.

Although there can be no assurance the amount of insurance the Partnership carries is sufficient to protect it fully in all events, it 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 Partnership had secured performance bonds totaling approximately $4.1 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 removal of certain facilities in its Gulf of Mexico fields, respectively. These performance bonds are uncollateralized. If the Partnership were to have to obtain additional performance bonds for other reasons, it cannot ensure that it would be able to secure any such additional performance bonds on acceptable commercial terms or at all.

Additionally, the Partnership has a $1.2 million collateralized bond to a third party for the plugging and abandonment of Nancy property located at Garden Banks block 463 that the Partnership exited in 2017. On January 4, 2017 the Partnership executed an agreement withdrawing from the Nancy property located at Garden Banks block 463. The agreement has an effective date of August 19, 2016. As part of the agreement, the Partnership was required to post a performance bond with the purchaser as obligee for the Partnership’s estimated share of certain future abandonment expenses as the Partnership retained financial responsibility and liability for its proportionate share of certain of the abandonment liabilities. The Partnership posted such performance bond on January 4, 2017 in the amount of $1.2 million. As part of the performance bond, the Partnership entered into a collateral agreement with the bonding surety and was required to fund a collateral account with an initial contribution of $50 thousand by January 10, 2017 and in monthly deposits of $25 thousand on the 1^st day of each month beginning on February 1, 2017 through November 1, 2018 in until such time that the deposit totals $0.6 million. As of December 31, 2017 the Partnership has recorded a $0.3 million deposit related to this bond.

Legal Proceedings and Other Contingencies—The Partnership 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 Partnership is required to reimburse ERT $7.3 million from the Project’s net cash flow in monthly installments if the gross production from the Project equals or exceeds 265 BCFE. As of December 31, 2017, the Partnership does not expect gross production from the Project to equal or exceed 265 BCFE. As of December 31, 2017, the Partnership had no liability recorded for this DAPA.

From time to time, the Partnership could be a party to certain legal actions and claims arising in the ordinary course of business. Management is not aware of any legal actions or claims against the Partnership.

5.

Subsequent Events

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

6.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (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—net of accumulated depreciation, depletion and
amortization	$ 10,370
Unproved properties	268
Total oil and gas properties—net of accumulated depletion	$ 10,638

Included in the depletable basis of the Partnership’s proved properties is the estimate of the Partnership’s proportionate share of asset retirement obligations relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2017 oil and gas asset retirement obligations totaled $17.0 million.

Estimated Quantities of Proved Oil and Gas Reserves—Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

A variety of deterministic methods are used to determine the Partnership’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, our 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 Partnership engaged Ryder Scott Company, L.P. Petroleum Consultants to prepare reserves estimates for all of the Partnership’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)(2)
Proved reserves at December 31, 2016		1,048			965			62			1,271
Revision of previous estimate(1)		102			579			7			205
Production		(142	)		(352	)		(11	)		(211	)
Purchase of reserves in place		—			—			—			—
Sales of reserves in place		—			—			—			—
Extensions and discoveries		—			—			—			—
Proved reserves at December 31, 2017		1,008			1,192			58			1,265
Proved developed reserves at December 31, 2017		1,008			1,192			58			1,265

(1)

Revisions in quantity estimates resulted from positive performance in the following fields:

-

Danny Noonan +0.2 MMBOE for performance-based increase in recovery efficiency

-

Sargent +0.1 MMBOE based on continued performance above what was expected year end 2016

-

Gladden -0.1 MMBOE for a performance-based decrease in expected ultimate gas-oil-ratio

(2)

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 Partnership does not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

 

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Partnership’s estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent our 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	$	51,486
Future production costs		(29,149	)
Future completion & abandonment costs		(23,681	)
Future income tax expense		—
Future net cash flows(1)		(1,344	)
Discount at 10% annual rate		153
Standardized measure of discounted future net cash flows	$	(1,191	)

(1)

Negative future net cash flows attributable to certain plug and abadndonment liability costs.

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 Partnership’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(2)	$	(3,919	)
Changes during the year:
Sales, net of production		(2,161	)
Net change in prices and production costs		4,367
Changes in future completion and abandonment costs		(5,421	)
Development costs incurred		3,183
Accretion of discount		(392	)
Net change in income taxes(1)		—
Purchase of reserves in place		—
Extensions and discoveries		—
Sales of reserves in place		—
Net change due to revision in quantity estimates		2,417
Changes in production rates (timing) and other		735
Standardized measure, end of year(2)		(1,191	)

(1)

The Partnership’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 Partnership is not subject to federal or state income taxes on income from proved oil and gas reserves.

(2)

Negative future net income attributable to certain plug and abadndonment liability costs.

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