The accompanying notes are an integral part of these condensed consolidated financial statements.
The accompanying notes are an integral part of these condensed consolidated financial statements.
The accompanying notes are an integral part of these condensed consolidated financial statements.
The accompanying notes are an integral part of these condensed consolidated financial statements.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Organization and Nature of Operations
Eclipse Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas.
Note 2—Basis of Presentation
The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, 2015, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 4, 2016.
Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2016 or any other future periods.
Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—
Summary of Significant Accounting Policies
describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the condensed consolidated financial statements are the following:
|
•
|
estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties;
|
|
•
|
estimates of asset retirement obligations;
|
|
•
|
estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;
|
|
•
|
impairment of undeveloped properties and other assets; and
|
|
•
|
depreciation and depletion of property and equipment.
|
Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.
Note 3—Summary of Significant Accounting Policies
(a) Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.
10
(b) Accounts Receivable
Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of September 30, 2016 or December 31, 2015.
The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $18.1 million and $19.9 million of accrued revenues, net of certain expenses, at September 30, 2016 and December 31, 2015, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.
(c) Property and Equipment
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see
“Depreciation, Depletion and Amortization
” below).
Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.
A summary of property and equipment including oil and natural gas properties is as follows (in thousands):
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
578,212
|
|
|
$
|
720,159
|
|
Proved
|
|
|
1,510,341
|
|
|
|
1,288,609
|
|
Gross oil and natural gas properties
|
|
|
2,088,553
|
|
|
|
2,008,768
|
|
Less accumulated depreciation depletion and amortization
|
|
|
(1,103,212
|
)
|
|
|
(1,022,771
|
)
|
Oil and natural gas properties, net
|
|
|
985,341
|
|
|
|
985,997
|
|
Other property and equipment
|
|
|
11,135
|
|
|
|
10,753
|
|
Less accumulated depreciation
|
|
|
(4,202
|
)
|
|
|
(2,782
|
)
|
Other property and equipment, net
|
|
|
6,933
|
|
|
|
7,971
|
|
Property and equipment, net
|
|
$
|
992,274
|
|
|
$
|
993,968
|
|
Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.
11
The Company capitalized interest expense
totaling $0.4 million and $0.5 million for the three months ended September 30, 2016 and 2015, respectively. The Company capitalized interest expense totaling $0.8 million and $3.1 million for the nine months ended September 30, 2016 and 2015, respective
ly.
Other Property and Equipment
Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.
(d) Revenue Recognition
Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of September 30, 2016 or December 31, 2015.
In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.
Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment.
(e) Concentration of Credit Risk
The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of September 30, 2016 and December 31, 2015 (in thousands):
|
|
September 30, 2016
|
|
|
December 31, 2015
|
|
Receivables by product or service:
|
|
|
|
|
|
|
|
|
Sale of oil and natural gas and related products and
services
|
|
$
|
18,110
|
|
|
$
|
19,858
|
|
Joint interest owners
|
|
|
6,085
|
|
|
|
3,095
|
|
Derivatives
|
|
|
1,424
|
|
|
|
4,523
|
|
Miscellaneous other
|
|
|
19
|
|
|
|
—
|
|
Total
|
|
$
|
25,638
|
|
|
$
|
27,476
|
|
Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the
12
Company’s unsettled commodity derivative contracts was a net liability position of ($6.8) million and a net asset position of $34.4 million at September 30, 2016 and December 31, 2015, respectively
. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the
Company. As of September 30, 2016 and December 31, 2015, the Company did not have past-due receivables from or payables to any of such counterparties.
(f) Accumulated Other Comprehensive Income (Loss)
Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its consolidated balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was terminated in October 2015 and lump sum payments were made in final settlement to all remaining participants.
(g) Depreciation, Depletion and Amortization
Oil and Natural Gas Properties
Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $27.7 million and $66.7 million for the three months ended September 30, 2016 and 2015, respectively, and $62.8 million and $168.9 million for the nine months ended September 30, 2016 and 2015, respectively.
Other Property and Equipment
Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million and $0.5 million for the three months ended September 30, 2016 and 2015, respectively, and $1.5 million and $1.3 million for the nine months ended September 30, 2016 and 2015, respectively. This amount is included in DD&A expense in the condensed consolidated statements of operations.
(h) Impairment of Long-Lived Assets
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the nine months ended September 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or nine months ended September 30, 2015 or the three months ended September 30, 2016.
The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.
13
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological i
nterpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $9.4 million and $1.0 million for the three months ended September 30, 2016 and 2015, respectively, and approximately $28.1 million and $7.1 million for the nine months ended September 30, 2016 and 2015, respectively. The increase in impairment charges during the three and nine months ended September 30, 2016 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity pricing environment. These costs are included in exploration expense in the condensed consolidated statements of operations.
(i) Income Taxes
The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.
(j) Fair Value of Financial Instruments
The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1
—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2
—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.
Level 3
—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
(k) Derivative Financial Instruments
The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.
14
Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expi
ration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists.
The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of chan
ge. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.
The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.
(l) Asset Retirement Obligation
The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “
Asset Retirement and Environmental Obligations
,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 10.33% and 10.45% for the nine months ended September 30, 2016 and 2015, respectively.
Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2016 (in thousands):
|
|
Nine Months Ended
|
|
|
|
September 30, 2016
|
|
Asset retirement obligations, beginning of period
|
|
$
|
3,401
|
|
Additional liabilities incurred
|
|
|
923
|
|
Accretion
|
|
|
275
|
|
Asset retirement obligations, end of period
|
|
$
|
4,599
|
|
The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.
(m) Lease Obligations
The Company leases office space under operating leases that expire between the years 2016 to 2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception.
(n) Off-Balance Sheet Arrangements
The Company does not have any off-balance sheet arrangements.
(o) Segment Reporting
The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
15
(p)
Debt Issuance Costs
The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.
(q) Recent Accounting Pronouncements
The FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.
In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” The new standard provides guidance on determining when and how to disclose going concern uncertainties in the financial statements. Management will be required to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date and financial statements are issued. ASU 2014-15 is effective for annual and interim periods ending after December 15, 2016, with early adoption permitted. The adoption of this standard is not expected to have a significant impact on the Company’s financial statement disclosures.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-02 on its financial position, results of operations and related disclosures.
In March 2016, the FASB issued ASU 2016-09, “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The new standard provides guidance involving several aspects of the accounting for share-based payments transactions, including income tax consequences, award classification as liabilities or equity, and cash flow statements classifications. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-09 on its financial position, results of operations and related disclosures.
In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-15 on its financial position, results of operations and related disclosures.
(r) Change in estimates
During the nine months ended September 30, 2016 , the Company reduced its estimate of amounts due from a non-operated partner related to the sale of natural gas and NGLs, net of associated costs, based on revised information received from the non-operated partner during the period. As a result, the Company decreased accounts receivable by approximately $4 million, increased revenue from oil and natural gas sales by approximately $1.5 million, and increased transportation, gathering and compression expense by approximately $5.8 million, which increased the net loss for the nine months ended September 30, 2016 by approximately $4 million, or $0.02 per common share.
16
Du
ring the nine months ended September 30, 2016, the Company reduced its estimate for production and ad valorem tax expense based on recent historical experience and additional information received during the period. As a result, the Company decreased the ac
crual for production and ad valorem taxes to be paid by approximately $4 million, which decreased the net loss for the nine months ended September 30, 2016 by a corresponding amount, or $0.02 per common share.
Note 4—Sale of Oil and Natural Gas Property Interests
During the nine months ended September 30, 2016 , the Company completed the sale of its Conventional oil and gas properties and related equipment for approximately $4.7 million. As a result of this sale, the Company recognized a gain of approximately $1.0 million .
During the nine months ended September 30, 2016 , the Company received $3.9 million from the sale of mineral interests related primarily to unproved properties to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.
During the nine months ended September 30, 2016, the Company received $4.8 million from the sale of unproved leases to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.
During the three months ended September 30, 2016, the Company received $0.4 million from the sale of pipeline assets. As a result of this sale, the Company recognized a loss of less than $0.1 million.
During the three months ended September 30, 2016, the Company received $1.1 million from acreage trades with various working interest owners totaling approximately 149.5 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and gas properties.
Note 5—Derivative Instruments
Commodity Derivatives
The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter (“OTC”) fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.
The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of September 30, 2016, the Company’s derivative instruments were with Bank of Montreal, Citibank, N.A., and Key Bank, N.A. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of September 30, 2016, for future production periods:
17
Natural Gas Derivatives
Description
|
|
Volume
(MMBtu/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/MMBtu)
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65,000
|
|
|
September 2016 – December 2016
|
|
$
|
3.28
|
|
|
|
|
10,000
|
|
|
January 2017 – December 2017
|
|
$
|
2.98
|
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
30,000
|
|
|
September 2016 – December 2017
|
|
$
|
3.00
|
|
Ceiling sold price (call)
|
|
|
30,000
|
|
|
September 2016 – December 2017
|
|
$
|
3.50
|
|
Floor purchase price (put)
|
|
|
100,000
|
|
|
January 2017 – December 2017
|
|
$
|
2.80
|
|
Ceiling sold price (call)
|
|
|
100,000
|
|
|
January 2017 – December 2017
|
|
$
|
3.17
|
|
Floor purchase price (put)
|
|
|
20,000
|
|
|
January 2017 – December 2018
|
|
$
|
2.90
|
|
Ceiling sold price (call)
|
|
|
20,000
|
|
|
January 2017 – December 2018
|
|
$
|
3.25
|
|
Floor purchase price (put)
|
|
|
40,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.75
|
|
Ceiling sold price (call)
|
|
|
40,000
|
|
|
January 2018 – December 2018
|
|
$
|
3.28
|
|
Natural Gas Three-way Collars:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
40,000
|
|
|
September 2016 – December 2016
|
|
$
|
2.90
|
|
Ceiling sold price (call)
|
|
|
40,000
|
|
|
September 2016 – December 2016
|
|
$
|
3.24
|
|
Floor sold price (put)
|
|
|
40,000
|
|
|
September 2016 – December 2016
|
|
$
|
2.35
|
|
Floor purchase price (put)
|
|
|
30,000
|
|
|
January 2017 – December 2017
|
|
$
|
2.75
|
|
Ceiling sold price (call)
|
|
|
30,000
|
|
|
January 2017 – December 2017
|
|
$
|
3.57
|
|
Floor sold price (put)
|
|
|
30,000
|
|
|
January 2017 – December 2017
|
|
$
|
2.25
|
|
Natural Gas Call/Put Options:
|
|
|
|
|
|
|
|
|
|
|
Call sold
|
|
|
40,000
|
|
|
January 2018 – December 2018
|
|
$
|
3.75
|
|
Call sold
|
|
|
10,000
|
|
|
January 2019 – December 2019
|
|
$
|
4.75
|
|
Oil Derivatives
Description
|
|
Volume
(Bbls/d)
|
|
|
Production Period
|
|
Weighted
Average
Price
($/Bbl)
|
|
Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
850
|
|
|
September 2016 – December 2016
|
|
$
|
45.55
|
|
Oil Three-way Collars:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
1,000
|
|
|
September 2016 – December 2016
|
|
$
|
60.00
|
|
Ceiling sold price (call)
|
|
|
1,000
|
|
|
September 2016 – December 2016
|
|
$
|
70.10
|
|
Floor sold price (put)
|
|
|
1,000
|
|
|
September 2016 – December 2016
|
|
$
|
45.00
|
|
Floor purchase price (put)
|
|
|
2,000
|
|
|
January 2017 – September 2017
|
|
$
|
46.00
|
|
Ceiling sold price (call)
|
|
|
2,000
|
|
|
January 2017 – September 2017
|
|
$
|
59.50
|
|
Floor sold price (put)
|
|
|
2,000
|
|
|
January 2017 – September 2017
|
|
$
|
38.00
|
|
Floor purchase price (put)
|
|
|
2,000
|
|
|
January 2017 – December 2017
|
|
$
|
46.00
|
|
Ceiling sold price (call)
|
|
|
2,000
|
|
|
January 2017 – December 2017
|
|
$
|
60.00
|
|
Floor sold price (put)
|
|
|
2,000
|
|
|
January 2017 – December 2017
|
|
$
|
38.00
|
|
Oil Call/Put Options:
|
|
|
|
|
|
|
|
|
|
|
Call sold
|
|
|
1,000
|
|
|
January 2018 – December 2018
|
|
$
|
50.00
|
|
NGL Derivatives
Description
|
|
Volume
(Gal/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/Gal)
|
|
Propane Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,000
|
|
|
September 2016 – December 2016
|
|
$
|
0.46
|
|
|
|
|
10,500
|
|
|
September 2016
|
|
$
|
0.46
|
|
18
Fair Values and Gains (Losses)
The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.
As of September 30, 2016
|
|
Gross Amount
|
|
|
Netting Adjustments(a)
|
|
|
Net Amount Presented in Balance Sheets
|
|
|
Balance Sheet Location
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives - current
|
|
$
|
2,911
|
|
|
$
|
(2,049
|
)
|
|
$
|
863
|
|
|
Other current assets
|
Commodity derivatives - noncurrent
|
|
|
1,471
|
|
|
|
(412
|
)
|
|
|
1,059
|
|
|
Other assets
|
Total assets
|
|
$
|
4,383
|
|
|
$
|
(2,461
|
)
|
|
$
|
1,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives - current
|
|
$
|
(4,133
|
)
|
|
$
|
2,049
|
|
|
$
|
(2,085
|
)
|
|
Accrued liabilities
|
Commodity derivatives - noncurrent
|
|
|
(7,019
|
)
|
|
|
412
|
|
|
|
(6,607
|
)
|
|
Other liabilities
|
Total liabilities
|
|
$
|
(11,152
|
)
|
|
$
|
2,461
|
|
|
$
|
(8,691
|
)
|
|
|
As of December 31, 2015
|
|
Gross Amount
|
|
|
Netting Adjustments(a)
|
|
|
Net Amount Presented in Balance Sheets
|
|
|
Balance Sheet Location
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives - current
|
|
$
|
41,199
|
|
|
$
|
(8,158
|
)
|
|
$
|
33,041
|
|
|
Other current assets
|
Commodity derivatives - noncurrent
|
|
|
4,594
|
|
|
|
(3,194
|
)
|
|
|
1,400
|
|
|
Other assets
|
Total assets
|
|
$
|
45,793
|
|
|
$
|
(11,352
|
)
|
|
$
|
34,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives - current
|
|
$
|
(8,158
|
)
|
|
$
|
8,158
|
|
|
$
|
—
|
|
|
|
Commodity derivatives - noncurrent
|
|
|
(3,194
|
)
|
|
|
3,194
|
|
|
|
—
|
|
|
|
Total liabilities
|
|
$
|
(11,352
|
)
|
|
$
|
11,352
|
|
|
$
|
—
|
|
|
|
(a)
|
The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
|
The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands):
|
|
|
|
Amount of Gain (Loss) Recognized in Income
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
Derivatives not designated as hedging instruments under ASC 815
|
|
Location of Gain (Loss)
Recognized in Income
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Commodity derivatives
|
|
Gain (Loss) on derivative instruments
|
|
$
|
10,639
|
|
|
$
|
23,679
|
|
|
$
|
(8,407
|
)
|
|
$
|
31,527
|
|
19
Note 6—Fair Value Measurements
Fair Value Measurement on a Recurring Basis
The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
Fair Value
|
|
As of September 30, 2016: (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
(6,769
|
)
|
|
$
|
—
|
|
|
$
|
(6,769
|
)
|
Total
|
|
$
|
—
|
|
|
$
|
(6,769
|
)
|
|
$
|
—
|
|
|
$
|
(6,769
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total Fair Value
|
|
As of December 31, 2015: (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
34,441
|
|
|
$
|
—
|
|
|
$
|
34,441
|
|
Total
|
|
$
|
—
|
|
|
$
|
34,441
|
|
|
$
|
—
|
|
|
$
|
34,441
|
|
Nonfinancial Assets and Liabilities
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3—
Summary of Significant Accounting Policies
).
The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3—
Summary of Significant Accounting Policies
).
The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 7—
Debt
).
Note 7—Debt
12% Senior Unsecured PIK Notes Due 2018
The Company redeemed all of the outstanding balance of the 12% Senior PIK Notes on July 13, 2015 for approximately $510.7 million, including outstanding principal balance of $437.3 million, a make-whole premium of $47.6 million, and accrued interest of $25.8 million. The make-whole premium plus unamortized discount and deferred financing costs of $11.8 million were charged to loss on early extinguishment of debt, totaling $59.4 million.
8.875% Senior Unsecured Notes Due 2023
On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% Senior Unsecured Notes due 2023 (the “Notes”) at an issue price of 97.903% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the Notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after
20
deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the C
ompany used approximately $510.7
million to finance the redemption of all of its outstanding Senior PIK Notes. The Compa
ny intends to use the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes. The fair value of the Notes at
September 30, 2016
was $
4
97
.4
million.
During the three and nine months ended September 30, 2016, the Company amortized $0.7 million and $2.5 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. The Company amortized less than $0.1 million and $1.9 million of deferred financing costs and debt discount to interest expense using the effective interest method for the three and nine months ended September 30, 2015, respectively.
The Indenture governing the Notes (the “Indenture”) contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the Indenture. In addition, if the Notes achieve and investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the Indenture has then occurred and is continuing, many of such covenants will be suspended. The Indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the Notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the Indenture at September 30, 2016.
During the nine months ended September 30, 2016, the Company repurchased $39.5 million of the outstanding Notes in open market purchases for $23.4 million. The principal of the outstanding Notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs were charged to gain on early extinguishment of debt, totaling $14.5 million for the nine months ended September 30, 2016. The Company repurchased all such Notes with cash on hand.
Revolving Credit Facility
The Company has entered into a $500 million senior secured revolving bank credit facility (the “Revolving Credit Facility”) that matures in 2018. Borrowings under the Revolving Credit Facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October). At September 30, 2016, the borrowing base was $125 million and the Company had no outstanding borrowings. After giving effect to outstanding letters of credit issued by the Company totaling $31.2 million, the Company had available borrowing capacity under the Revolving Credit Facility of $93.8 million at September 30, 2016.
Subsequent to September 30, 2016, the Company posted a letter of credit for $3.3 million related to firm transportation commitments, which reduced the Company’s available borrowing capacity to $90.5 million. During October 2016, the Company completed its most recent borrowing base redetermination, which resulted in no change to the borrowing base under the Revolving Credit Facility.
On February 24, 2016, the Company amended the Credit Agreement governing its Revolving Credit Facility (the “Credit Agreement”) to, among other things, adjust the Company’s quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% and required the Company to, within 60 days of the effectiveness of the amendment, execute and deliver additional mortgages on the Company’s oil and gas properties that include at least 90% of its proved reserves.
The Revolving Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The Credit Agreement contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the Credit Agreement as of September 30, 2016. Commitment fees on the unused portion of the Revolving Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization.
21
Note 8—Benefit Plans
Defined Contribution Plan
The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recognized expense of $0.1 million and $0.2 million for the three months ended September 30, 2016 and 2015, respectively, and $0.5 million and $0.7 million for the nine months ended September 30, 2016 and 2015, respectively.
Defined Benefit Plan
The Company maintained a defined benefit plan until October 2015. The plan covered 28 employees, of which two were retired, four had deferred vested determination, and one was a survivor. Benefits were based on the employees’ years of service and compensation. The following table details the components of pension benefit cost (in thousands):
|
|
Three Months Ended September 30,
2015
|
|
|
Nine Months Ended September 30,
2015
|
|
Interest cost
|
|
$
|
56
|
|
|
$
|
182
|
|
Expected return on plan assets
|
|
|
(82
|
)
|
|
|
(246
|
)
|
Amortization of net loss
|
|
|
—
|
|
|
|
43
|
|
Settlement costs
|
|
|
—
|
|
|
|
97
|
|
Net periodic benefit cost
|
|
$
|
(26
|
)
|
|
$
|
76
|
|
The defined benefit plan was terminated during October 2015 and lump sum payments were made to the remaining participants. Accordingly, the Company did not have any pension benefit costs for the three and nine months ended September 30, 2016.
Note 9—Stock-Based Compensation
The Company is authorized to grant up to 16,000,000 shares of common stock under its 2014 Long-Term Incentive Plan (the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 8,019,938 shares were available for future grants under the Plan as of September 30, 2016.
Our stock-based compensation expense was as follows for the three and nine months ended September 30, 2016 and 2015 (in thousands):
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Restricted stock units
|
|
$
|
1,012
|
|
|
$
|
608
|
|
|
$
|
3,254
|
|
|
$
|
1,779
|
|
Performance units
|
|
|
651
|
|
|
|
384
|
|
|
|
1,708
|
|
|
|
912
|
|
Restricted stock issued to directors
|
|
|
101
|
|
|
|
213
|
|
|
|
454
|
|
|
|
614
|
|
Incentive units
|
|
|
—
|
|
|
|
32
|
|
|
|
48
|
|
|
|
89
|
|
Total expense
|
|
$
|
1,764
|
|
|
$
|
1,237
|
|
|
$
|
5,464
|
|
|
$
|
3,394
|
|
22
Restricted Stock Units
Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of September 30, 2016, there was $6.2 million of total unrecognized compensation cost related to outstanding restricted stock units. A summary of restricted stock unit awards activity during the nine months ended September 30, 2016 is as follows:
|
|
Number of
shares
|
|
|
Weighted
average grant
date fair value
|
|
|
Aggregate
intrinsic
value (in
thousands)
|
|
Total awarded and unvested, December 31, 2015
|
|
|
1,000,052
|
|
|
$
|
7.07
|
|
|
$
|
1,820
|
|
Granted
|
|
|
3,751,931
|
|
|
|
1.36
|
|
|
|
|
|
Vested
|
|
|
(340,879
|
)
|
|
|
7.13
|
|
|
|
|
|
Forfeited
|
|
|
(67,522
|
)
|
|
|
7.13
|
|
|
|
|
|
Total awarded and unvested, September 30, 2016
|
|
|
4,343,582
|
|
|
$
|
2.14
|
|
|
$
|
14,290
|
|
Performance Units
Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of September 30, 2016, there was $3.7 million of total unrecognized compensation cost related to outstanding performance units. A summary of performance stock unit awards activity during the nine months ended September 30, 2016 is as follows:
|
|
Number of
shares
|
|
|
Weighted
average grant
date fair value
|
|
|
Aggregate
intrinsic
value (in
thousands)
|
|
Total awarded and unvested, December 31, 2015
|
|
|
458,656
|
|
|
$
|
8.77
|
|
|
$
|
417
|
|
Granted
|
|
|
1,469,346
|
|
|
|
1.60
|
|
|
|
|
|
Vested
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Forfeited
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Total awarded and unvested, September 30, 2016
|
|
|
1,928,002
|
|
|
$
|
3.31
|
|
|
$
|
6,343
|
|
The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group.
Restricted Stock Issued to Directors
On October 7, 2014, the Company issued an aggregate of 31,115 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on June 25, 2015. For the nine months ended September 30, 2015, the Company recognized expense of approximately $0.3 million related to these awards, respectively.
On May 11, 2015, the Company issued an aggregate of 132,496 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on May 11, 2016. For the three and nine months ended September 30, 2015, the Company recognized expense of approximately $0.2 million and $0.3 million, respectively, related to these awards. For the nine months ended September 30, 2016, the Company recognized expense of approximately $0.3 million related to these awards.
On May 18, 2016, the Company issued an aggregate of 149,448 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which are scheduled to fully vest on May 18, 2017. For the three and nine months ended September 30, 2016, the Company recognized expense of approximately $0.2 million related to these awards. As of September 30, 2016, there was approximately $0.6 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.
23
Note 10—Equ
ity
Private Placement of Common Stock
On December 27, 2014, the Company entered into a Securities Purchase Agreement with private equity funds managed by EnCap Investments L.P., entities controlled by certain members of the Company’s management team and certain other institutional investors pursuant to which the Company issued and sold to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act (the “Private Placement”).
On January 28, 2015, the Company closed the Private Placement and received net proceeds of approximately $434 million (after deducting placement agent commissions and estimated expenses), which the Company intends to use to fund its capital expenditure plan and for general corporate purposes.
Public Offering of Common Stock
On June 28, 2016, the Company commenced an underwritten public offering of 37,500,000 shares of common stock, which was priced at $3.50 per share. The Company closed the offering on July 5, 2016 and received net proceeds of approximately $123 million (after deducting underwriting discounts and commissions and estimated expenses), which the Company intends to use to fund its capital expenditure plan and for general corporate purposes.
Note 11—Related Party Transactions
During the three and nine months ended September 30, 2016, the Company incurred approximately $0.1 million and $0.4 million, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2015, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer. The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.
Note 12—Commitments and Contingencies
(a) Legal Matters
Prior to the Company’s acquisition of the Oxford Oil Company (“Oxford”), which was completed in June 2013, Oxford commenced a lawsuit on October 24, 2011 in the Common Pleas Court of Belmont County, Ohio against Mr. Barry West, a lessor under an Oxford oil and gas lease, to enforce its rights to access and drill a well pursuant to the lease during its initial 5-year primary term. The lessor counterclaimed, alleging, among other things, that the challenged Oxford lease constituted a lease in perpetuity and, accordingly, should be deemed void and contrary to public policy in the State of Ohio. On October 4, 2013, the Belmont County trial court granted a motion for summary judgment in favor of the lessor and ruled that the lease is a “no term” perpetual lease and, as such, is void as a matter of Ohio law. On October 8, 2013, the Company appealed the trial court’s decision in the
West
case to the Ohio Court of Appeals for the Seventh Appellate District, arguing, among other things, that the Belmont County trial court erred in finding that the lease is a “no term” perpetual lease, by ruling that perpetual leases are void as a matter of Ohio law and by invalidating such leases.
On September 26, 2014, the Ohio Court of Appeals for the Seventh Appellate District issued its decision in the case of
State ex rel. Claugus Family Farm, L.P. v. Beck Energy Corporation (formerly entitled, Hupp v. Beck Energy Corporation)
, an appeal of a Monroe County, Ohio trial court decision upon which the trial court in
West
based its decision. The appellate court held that while Ohio law disfavors perpetual leases, courts in Ohio have not found them to be per se illegal or void from their inception. The appellate court further held that the trial court misinterpreted both the pertinent lease provisions and Ohio law on the subject and erred in concluding that the Beck Energy lease is a no-term, perpetual lease that is void ab initio as against public policy. On November 7, 2014, the plaintiff landowners filed an appeal of the appellate court’s decision with the Supreme Court of Ohio, which was accepted by the Supreme Court of Ohio on January 28, 2015. On March 2, 2015, the Ohio Court of Appeals for the Seventh Appellate District stayed all proceedings in the Company’s appeal in the
West
case pending a decision by the Supreme Court of Ohio in the
Claugus Family v. Beck Energy
appeal. On January 21, 2016, the Supreme Court of Ohio affirmed the Appellate Court’s decision in
Claugus Family v. Beck Energy
and held that the subject lease was not perpetual and not void as against public policy. As a result of such ruling, on February 26, 2016, the Ohio Court of Appeals for the Seventh Appellate District lifted the stay of the Company’s appeal in the
West
case.
24
On September 6, 2016, th
e Ohio Court of Appeals for the Seventh Appellate District issued its decision in the
West
case in the Company’s favor reversing the trial court’s holdings that the Oxford oil and gas lease was perpetual and void. The appellate court held that the Oxford
oil and gas lease in
West
was not perpetual because it had a primary term of a definitive duration of five years, and remanded the lawsuit to the trial court for further proceedings on other claims unrelated to the perpetual lease claim. Mr. West did not
appeal the decision of the Ohio Court of Appeals for the Seventh Appellate District to the Ohio Supreme Court, thus concluding the matter as to the perpetual lease claim.
The Company is a party to one other lawsuit that claims the Oxford oil and gas lease is void as a perpetual lease in reliance upon the trial court’s decision in the
West
case, which was stayed pending the outcome of the appeal in the
West
case. This lawsuit affects approximately 60 leasehold acres and was capitalized on the Company’s condensed consolidated balance sheet as of September 30, 2016 at $0.7 million. Based upon the decision of the appellate court in
West
upholding the validity of the Oxford lease, the Company expects that the perpetual lease claim filed in this additional lawsuit will likely be dismissed by the trial court.
Other Matters
From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.
(b) Environmental Matters
The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.
(c) Leases
The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.
The Company leases office space under operating leases that expire between the years 2016 to 2025. The Company recognized rent expense of $0.1 million and $0.5 million for the three months ended September 30, 2016 and 2015, respectively, and $0.7 million and $0.9 million for the nine months ended September 30, 2016 and 2015, respectively.
Note 13—Income Tax
For the year ending December 31, 2016, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur both a book and tax loss in fiscal year 2016, and thus, no current federal income taxes are anticipated to be paid. The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss. For the quarter ended September 30, 2016, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and other permanent differences.
In forecasting the 2016 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2016. Management reached this conclusion considering several factors such as: (i) the Company’s short tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet. At this time, the estimated valuation allowance to be recorded in 2016 is $53.7 million.
During the second quarter of 2016, the Internal Revenue Service notified the Company that it would examine the federal income tax return of Eclipse Resources Corporation and Subsidiaries for its 2014 tax year. The Company does not anticipate any material adjustments to its provision for income taxes as a result of the examination, as such no reserve has been recorded at this time.
25
Note 14—Subsidiary Guarantors
The Company’s wholly-owned subsidiaries each have fully and unconditionally, joint and severally, guaranteed the Company’s 8.875% Senior Unsecured Notes (See Note 7—
Debt
). The Parent company has no independent assets or operations. The Company’s wholly-owned subsidiaries are not restricted from transferring funds to the Parent or other wholly-owned subsidiaries. The Company’s wholly-owned subsidiaries do not have any restricted net assets.
A subsidiary guarantor may be released from its obligations under the guarantee:
|
•
|
in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or
|
|
•
|
if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the Indenture.
|
Note 15—Subsequent Events
Management has evaluated subsequent events and believes there are no events that would have a material impact on the aforementioned financial statements and related disclosures, other than those disclosed in the accompanying notes to the condensed consolidated financial statements (See Note 7—
Debt
).
26