General Accounting and Disclosure Matters

Fair Value Measurements

The carrying amounts reported in the unaudited condensed consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments. Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

Fair value contracts consist of derivative financial instruments and are recorded as either an asset or liability measured at its fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and we elect, cash flow hedge accounting. We had no contracts designated for hedge accounting during any current reporting periods. See Note 7 for further information.

Investments in Unconsolidated Affiliates

Bencap. We owned a 30% member interest in Bencap LLC (“Bencap”). Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. We accounted for this investment under the equity method of accounting. Underlying the terms of the investment agreement, Bencap had the option to request borrowings from us of up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that we were required to provide or forfeit our 30% member interest. During 2016, our management determined that we were unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception. During 2016, we recognized a net loss of $1.4 million to write-off our investment in Bencap during the quarter ended September 30, 2016, which included a pre-tax impairment charge of $1.7 million and pre-tax losses from the equity method investment of $0.5 million. In February 2017, Bencap requested additional funding of approximately $0.5 million. We declined the additional funding request and forfeited our 30% member interest in Bencap. At June 30, 2017, we have no further ownership interest in Bencap. We currently do not have any plans to pursue additional medical-related investments.

VestaCare. We own an approximate 15% equity interest (less than 3% voting interest) in VestaCare, Inc., a California corporation (“VestaCare”). VestaCare provides an array of software as a service (“SaaS”) electronic payment technologies to medical providers, payers and patients including VestaCare’s most recent product offering, VestaPay™. VestaPay™ allows medical care providers to structure fully automated and dynamically updating electronic payment plans for their patients. We account for this investment under the cost method of accounting.

AREC. As a result of the voluntary bankruptcy filing in April 2017 and our loss of control of AREC, we deconsolidated AREC effective with the bankruptcy filing and we now record our investment in AREC under the cost method. See Note 3 for further information.

Letter of Credit Facility

We maintain a Credit and Security Agreement with Wells Fargo Bank to provide up to a $60 million stand-by letter of credit facility used to support crude oil purchases within our crude oil marketing segment. This facility is collateralized by the eligible accounts receivable within the crude oil marketing segment.

The issued stand-by letters of credit are canceled as the underlying purchase obligations are satisfied by cash payment when due. The letter of credit facility places certain restrictions on Gulfmark Energy, Inc., our wholly owned subsidiary. Such restrictions include the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions. We are currently in compliance with all such financial covenants. No letter of credit amounts were outstanding at June 30, 2017 and December 31, 2016. The letter of credit facility expires on August 31, 2017, and we anticipate renewing the facility for another one-year term.

Prepayments and Other Current Assets

The components of prepayments and other current assets are as follows at the dates indicated (in thousands):



	June 30,		December 31,
	2017		2016

Insurance premiums	$	679	$	1,403
Rents, license and other	529		694
Total	$	1,208	$	2,097

Property and Equipment

We capitalize expenditures for major renewals and betterments, and we expense expenditures for maintenance and repairs as incurred. We capitalize interest costs incurred in connection with major capital expenditures and amortize these costs over the lives of the related assets. When properties are retired or sold, the related cost and accumulated depreciation, depletion and amortization is removed from the accounts and any gain or loss is reflected in earnings.

We account for oil and gas exploration and development expenditures in accordance with the successful efforts method of accounting. We capitalize direct costs of acquiring developed or undeveloped leasehold acreage, including lease bonus, brokerage and other fees. We initially capitalize exploratory drilling costs until the properties are evaluated and determined to be either productive or nonproductive. Such evaluations are made on a quarterly basis. If an exploratory well is determined to be nonproductive, the costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized. As of June 30, 2017, we had no unevaluated or suspended exploratory drilling costs. Effective in April 2017, our oil and gas subsidiary was deconsolidated and is now accounted for as a cost method investment, as a result of its bankruptcy filing (see Note 3).

We calculate depreciation, depletion and amortization of the cost of proved oil and gas properties using the units-of-production method. The reserve base or denominator used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. For lease and well equipment, development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. The numerator for such calculations is actual production volumes for the period. All other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years.

We review our long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. Any impairment recognized is permanent and may not be restored. Property and equipment is reviewed at the lowest level of indentifiable cash flows. Producing oil and gas properties are reviewed on a field-by-field basis. Fields with carrying values in excess of their estimated undiscounted future net cash flows are deemed impaired. For properties requiring impairment, the fair value is estimated based on an internal discounted cash flow model. Cash flows are developed based on estimated future production and prices are then discounted using a market based rate of return consistent with that used by us in evaluating cash flows for other assets of a similar nature.

On a quarterly basis, our management evaluates the carrying value of non-producing oil and gas leasehold properties and may deem them impaired based on remaining lease term, area drilling activity and our plans for the property. This fair value measure depends highly on our assessment of the likelihood of continued exploration efforts in a given area. Therefore, such data inputs are categorized as “unobservable” or “Level 3” inputs (see Note 7). Impairment provisions included in our oil and gas segment operating losses were not material during the three and six months ended June 30, 2017 and 2016.

Since we are no longer the operator of our oil and gas property interests, we do not maintain the underlying detail acreage data and we are dependent on the operator when determining which specific acreage will ultimately be drilled. However, the capitalized cost detail on a property-by-property basis is reviewed by management, and deemed impaired if development is not anticipated prior to lease expiration. Onshore leasehold periods are normally three years and may contain renewal options.

Revenue Recognition

Certain commodity purchase and sale contracts utilized by our crude oil marketing business qualify as derivative instruments with certain specifically identified contracts also designated as trading activity. From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying consolidated financial statements.

Most crude oil purchase and sale contracts qualify and are designated as non-trading activities, and we consider such contracts as normal purchases and sales activity. For normal purchases and sales, our customers are invoiced monthly based upon contractually agreed upon terms with revenue recognized in the month in which the physical product is delivered to the customer. Such sales are recorded on a gross basis in the financial statements because we take title, have risk of loss for the products, are the primary obligor for the purchase, establish the sale price independently with a third party and maintain credit risk associated with the sale of the product.

Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations. These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer. Such buy/sell arrangements are reflected on a net revenue basis in the accompanying unaudited condensed consolidated financial statements.

Reporting such crude oil contracts on a gross revenue basis would increase our reported revenues as follows for the periods indicated (in thousands):



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016

Revenue gross-up	$	44,908	$	99,082	$	102,473	$	175,009

Transportation segment customers are invoiced, and the related revenue is recognized as the service is provided. Oil and gas revenue from our interests in producing wells is recognized as title and physical possession of the oil and gas passes to the purchaser.

Recent Accounting Developments

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”). The new accounting standard, along with its related amendments, replaces the current rules-based U.S. GAAP governing revenue recognition with a principles-based approach. We plan to adopt the new standard on January 1, 2018 using the modified retrospective approach, which requires us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised.

The core principle in the new guidance is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. In order to apply this core principle, companies will apply the following five steps in determining the amount of revenues to recognize: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management’s judgment and an analysis of the contract’s material terms and conditions.

Our implementation activities related to ASC 606 are ongoing. We do not anticipate that there will be material differences in the amount or timing of revenues recognized following the new standard’s adoption date. Although total consolidated revenues may not be materially impacted by the new guidance, we do anticipate significant changes to our disclosures based on the additional requirements prescribed by ASC 606. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we are currently evaluating our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance.

Leases. In February 2016, the FASB issued ASC 842, Leases (“ASC 842”), which requires substantially all leases (with the exception of leases with a term of one year or less) to be recorded on the balance sheet using a method referred to as the right-of-use (“ROU”) asset approach. We plan to adopt the new standard on January 1, 2019 using the modified retrospective method described within ASC 842.

The new standard introduces two lease accounting models, which result in a lease being classified as either a “finance” or “operating” lease on the basis of whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with current lease accounting guidance. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a ROU asset representing a company’s right to use the underlying asset for a specified period of time and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.

The subsequent measurement of each type of lease varies. Leases classified as a finance lease will be accounted for using the effective interest method. Under this approach, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and the discount on the lease liability (as a component of interest expense). Leases classified as an operating lease will result in the recognition of a single lease expense amount that is recorded on a straight-line basis (or another systematic basis, if more appropriate).

We are in the process of reviewing our lease agreements in light of the new guidance. Although we are in the early stages of our ASC 842 implementation project, we anticipate that this new lease guidance will cause significant changes to the way leases are recorded, presented and disclosed in our consolidated financial statements.