Note 2—Summary of Significant Accounting Policies

Below are the Company’s significant accounting policies.

Cash and Cash Equivalents

We reflect our cash as cash and cash equivalents on our consolidated balance sheets. We consider all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost plus accrued interest, which approximates fair value.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $5.9 million at December 31, 2017 and $4.9 million at December 31, 2016, which approximates fair value. We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we believe that we will not collect all or part of the outstanding balance. On a quarterly basis we review collectability and establish or adjust our allowance as necessary using the specific identification method.

Other Current Assets

Other current assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are estimates related to royalties which we are required to pay the ONRR within thirty days of the production rate. On a monthly basis we adjust the deposit based on actual royalty payments remitted to the ONRR.

Inventory

Inventory primarily represents oil in lease tanks and line fill in pipelines. Our inventory is stated at the net realizable value. Sales of oil are accounted for by a weighted average cost method whereby oil sold from inventory is relieved at the weighted average cost of oil remaining in inventory.

Revenue Recognition and Imbalances

We record revenues from the sale of oil, natural gas and natural gas liquids (“NGLs”) based on quantities of production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.

We have interests with other producers in certain properties. In these cases, we use the entitlement method to account for sales of production. Under the entitlement method, revenue is recorded when title passes based on our net interest. We may receive more or less than our entitled share of production, and we record our entitled share of revenues based on entitled volumes and contracted sales prices. If we receive more than our entitled share of production, the imbalance is recorded as a liability in accrued liabilities on the consolidated balance sheets. If we receive less than our entitled share, the imbalance is recorded as an asset in other current assets on the consolidated balance sheets. Our imbalances are recorded gross on our consolidated balance sheets. At December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million. At December 31, 2016, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.8 million. At December 31, 2015, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.6 million.

We record the gross amount of reimbursements for costs from third parties as other revenues whenever the Company is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related costs are incurred and when it has assumed the credit risk associated with the reimbursement for such costs. The costs associated with these third-party reimbursements are also recorded within the applicable cost and expenses line item in the consolidated statements of operations. Our other revenues have been generated primarily through fees for processing third-party production through some of our production facilities.

Accounting for Oil and Natural Gas Activities

The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. In August 2016, the Company entered into a capital lease for the use of the Helix Producer I (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy, and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included within proved property and subject to the ceiling test calculation described below. Due to the inclusion within proved properties, the HP-I is depleted as part of the full cost pool. See Note 10—Commitments and Contingencies for additional information.

Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, wells currently drilling and capitalized interest are initially excluded from the amortizable base. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves or when we have completed an evaluation of the unproved properties resulting in an impairment. We evaluate each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which we own a direct interest.

Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statement of operations and an increase to accumulated depreciation, depletion and amortization on our consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with the Securities and Exchange Commission (“SEC”) rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. The ceiling test computation resulted in a write-down of our oil and natural gas properties of nil, nil and $603.4 million during the years ended December 31, 2017, 2016 and 2015, respectively.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When we sell or convey interests in oil and natural gas properties, we reduce our oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. We treat sales proceeds on non-significant sales as reductions to the cost of our oil and natural gas properties.

We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs were $10.3 million, $9.1 million and $10.5 million in the years ended December 31, 2017, 2016 and 2015, respectively.

Other Property and Equipment

Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to five years.

Other Well Equipment Inventory

Other well equipment inventory primarily represents the cost of equipment to be used in our oil and natural gas drilling and development activities such as drilling pipe, tubular and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. Our inventory is stated at net realizable value. We recorded $0.3 million, $0.2 million, $2.1 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in workover/maintenance expense, during the years ended December 31, 2017, 2016 and 2015, respectively.

Fair Value Measure of Financial Instruments

Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

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 fair value is an exit price, presenting 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.

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 is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Asset Retirement Obligations

We are required to record our 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. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our oil and natural gas properties. The estimate of the asset retirement cost is determined, inflated to an estimated future value using a ten year average of the Consumer Price Index and discounted to present value using our credit-adjusted risk-free rate. 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.

Price Risk Management Activities

The Company uses commodity derivatives to manage market risks resulting from fluctuations in prices of oil and natural gas. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. We do not enter into derivative agreements for trading or other speculative purposes.

The fair value of commodity derivatives reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be favorable or unfavorable.

Equity Based Compensation

Certain of our employees participate in the equity based compensation plan of the Company. We measure all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to our employees and recognize compensation cost on a straight-line basis in our financial statements over the vesting period of each grant according to Accounting Standards Codification 718, Compensation—Stock Compensation.

Income Taxes

The Company is a limited liability company and not subject to federal or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial.

We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, income taxes are provided for based upon the tax laws and rates in effect in the foreign tax authorities.

Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that the overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowances of $4.0 million and $2.3 million, which is the amount of deferred tax assets.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives.

Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which, at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has experienced no losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, majority of which participate in our senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has experienced no losses due to counterparty default on these instruments.

We market substantially all of our oil and natural gas production from properties we operate and those we do not operate. The majority of our oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. Our customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our oil, natural gas and NGL revenues, was as follows:


	Year Ended December 31,
	2017			2016			2015
Shell Trading (US) Company		80	%		68	%		68	%
Chevron U.S.A Inc.		*	*		14	%		16	%

**	less than 10%

While the loss of Shell Trading (US) Company and Chevron U.S.A. Inc. as buyers might have a material effect on the Company in the short term, we believe that the Company would be able to obtain other customers for its oil, natural gas and NGL production.

Supplementary Cash Flow Information

Supplementary cash flow information for each period presented was as follows (in thousands):


	Year Ended December 31,
	2017		2016		2015
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	40,626	$	13,832	$	30,125
Fair value of assets acquired	$	—	$	—	$	75,519
Fair value of liabilities assumed	$	—	$	—	$	75,519
Capital lease transaction	$	—	$	124,300	$	—
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	47,994	$	55,254	$	37,247