Notes to Consolidated Financial Statements
SilverBow Resources, Inc. and Subsidiaries
1. Summary of Significant Accounting Policies
Fresh Start Accounting.
Upon emergence from bankruptcy on April 22, 2016, the Company adopted Fresh Start Accounting. As a result of the application of fresh start accounting, as well as the effects of the implementation of the joint plan of reorganization (the “Plan”), the Consolidated Financial Statements after April 22, 2016, are not comparable with the Consolidated Financial Statements prior to that date. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 22, 2016. References to “Predecessor” or “Predecessor Company” refer to the financial position and results of operations of the Company prior to April 23, 2016. See Notes 12 and 13 for further details.
Basis of Presentation
. The consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.
Principles of Consolidation
. The accompanying consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.
Subsequent Events.
We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements. On January 24, 2018 the Company executed a definitive purchase and sale agreement to divest certain wells in its AWP Olmos field for
$28.8 million
.
This
transaction closed on March 1, 2018 and has an effective date of January 1, 2018. The buyer will assume approximately
$6.2 million
in asset retirement obligations. Additionally, on February 28, 2018 the Company signed a one-year contract for a second drilling rig.
Use of Estimates.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:
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•
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the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling test impairment calculation,
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•
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estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
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•
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estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
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•
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estimates of future costs to develop and produce reserves,
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•
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accruals related to oil and gas sales, capital expenditures and lease operating expenses,
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•
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estimates in the calculation of share-based compensation expense,
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•
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estimates of our ownership in properties prior to final division of interest determination,
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•
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the estimated future cost and timing of asset retirement obligations,
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•
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estimates made in our income tax calculations,
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•
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estimates in the calculation of the fair value of commodity derivative assets and liabilities,
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•
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estimates in the assessment of current litigation claims against the Company,
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•
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estimates in amounts due with respect to open state regulatory audits, and
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•
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the estimates of reorganization value, enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and application of fresh start accounting.
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While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many
of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment.
We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the year ended December 31, 2015 (predecessor)
, such internal costs capitalized totaled
$4.6 million
,
$5.4 million
,
$2.9 million
and
$12.7 million
, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 4 of these consolidated financial statements for further discussion on capitalized interest costs).
The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
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Successor
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December 31,
2017
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December 31,
2016
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Property and Equipment
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Proved oil and gas properties
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$
|
658,519
|
|
$
|
480,499
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|
Unproved oil and gas properties
|
50,377
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|
33,354
|
|
Furniture, fixtures, and other equipment
|
3,270
|
|
3,221
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|
Less – Accumulated depreciation, depletion, amortization and impairment
|
(216,769
|
)
|
(169,879
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)
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Property and Equipment, Net
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$
|
495,397
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|
$
|
347,195
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|
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties—including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between
two
and
20
years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are directly associated with specific unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test
. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at
10%
, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
There was
no
write-down for the
year ended December 31, 2017
(successor). Primarily due to pricing differences between the 12-month average oil and gas prices used in the Ceiling Test and the forward strip prices used to estimate the initial fair value of oil and gas properties on the Company’s April 22, 2016 (successor) balance sheet, we incurred a non-cash impairment write-down for the
period of April 23, 2016 through December 31, 2016 (successor)
of
$133.5 million
. Write-downs in prior periods were primarily the result of declining historical prices along with timing changes and reduction of projects and changes in our reserves product mix. For the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended
2015
(predecessor) we reported non-cash impairment write-downs on a before-tax basis of
$77.7 million
and
$1.6 billion
, respectively, on our oil and natural gas properties.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is likely that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.
Revenue Recognition
. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. The Company uses the entitlement method of accounting for gas imbalances in which we recognize our ownership interest in such production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying consolidated balance sheets when our ownership share of production exceeds sales. As of
December 31, 2017 and 2016
, we did not have any material natural gas imbalances.
Accounts Receivable, Net
. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At
December 31, 2017 and 2016
, we had an allowance for doubtful accounts of less than
$0.1 million
. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying consolidated balance sheets.
At
December 31, 2017
, our “Accounts receivable” balance included
$20.1 million
for oil and gas sales,
$2.1 million
for joint interest owners,
$2.1 million
for severance tax credit receivables and
$3.0 million
for other receivables. At
December 31, 2016
, our “Accounts receivable” balance included
$12.6 million
for oil and gas sales,
$2.7 million
for joint interest owners,
$1.6 million
for severance tax credit receivables and
$0.6 million
for other receivables.
Supervision Fees
. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a
100%
working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying consolidated statements of operations. Our supervision fees are allocated to each well based on general and administrative costs incurred for well maintenance and support. The amount of supervision fees charged for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the year ended December 31, 2015 (predecessor)
did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was
$4.7 million
,
$4.5 million
,
$2.7 million
and
$9.2 million
for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the year ended December 31, 2015 (predecessor)
, respectively.
Income Taxes.
Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.
Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At
December 31, 2017
, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
The Company has evaluated the full impact of the reorganization on our carryover tax attributes and did not incur a cash income tax liability as a result of emergence from bankruptcy on April 22, 2016. The Company fully absorbed cancellation of debt income generated in the bankruptcy reorganization with its then existing NOL carryforwards. The amount of remaining NOL carryforward available following emergence from bankruptcy was limited under United States Internal Revenue Code Sec. 382 due to the change in control. The Company’s amortizable tax basis exceeded the book carrying value of its assets at April 22, 2016 and
December 31, 2017
, leaving the Company in a net deferred tax asset position as of such dates. Management has determined that it is not more likely than not that the Company will realize future cash benefits from this additional tax basis and remaining carryover items and accordingly has taken a full valuation allowance to offset its tax assets.
The Company expects to incur a net taxable loss in the current taxable period thus no current income taxes are anticipated to be paid.
Accounts Payable and Accrued Liabilities
. The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands):
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Successor
|
|
December 31,
2017
|
December 31,
2016
|
Trade accounts payable
|
$
|
20,884
|
|
$
|
12,372
|
|
Accrued operating expenses
|
3,490
|
|
2,990
|
|
Accrued compensation costs
|
5,334
|
|
4,730
|
|
Asset retirement obligations – current portion
|
2,109
|
|
9,965
|
|
Accrued non-income based taxes
|
3,898
|
|
3,937
|
|
Accrued corporate and legal fees
|
2,784
|
|
3,075
|
|
Other payables
|
5,938
|
|
3,365
|
|
Total Accounts payable and accrued liabilities
|
$
|
44,437
|
|
$
|
40,434
|
|
Cash and Cash Equivalents.
We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Recognition of Severance Expense for Executive Retirements
. On August 9, 2016, the Company announced that the Chief Executive Officer and Chief Financial Officer for the Company would be retiring. In the third quarter of 2016 we accrued
$2.1 million
for severance payments that will be paid out in accordance with their employment agreement. This amount was expensed in "General and administrative, net" in the consolidated statement of operations for the
period of April 23, 2016 through December 31, 2016 (successor)
. Additionally, we accelerated expense related to the equity awards held by the retiring Chief Executive Officer and Chief Financial Officer. See Note 7 for more details.
Credit Risk Due to Certain Concentrations.
We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss.
For the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended December 31, 2015 (predecessor) parties that accounted for approximately 10% or more of our total oil and gas receipts were as follows:
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Successor
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Predecessor
|
Sellers greater than 10%
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
Kinder Morgan
|
48
|
%
|
|
38
|
%
|
|
|
20
|
%
|
|
27
|
%
|
Plains Marketing
(1)
|
—
|
%
|
|
14
|
%
|
|
|
14
|
%
|
|
18
|
%
|
Howard Energy
(1)
|
—
|
%
|
|
—
|
%
|
|
|
11
|
%
|
|
13
|
%
|
Southcross Energy
(1)
|
—
|
%
|
|
—
|
%
|
|
|
11
|
%
|
|
—
|
%
|
Shell
(1)
|
—
|
%
|
|
15
|
%
|
|
|
19
|
%
|
|
16
|
%
|
(1) Less than 10% for the
year ended December 31, 2017
(successor).
Treasury Stock.
Treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost" on the accompanying consolidated balance sheets. When the Company reissues treasury stock the gains are recorded in "Additional paid-in capital" ("APIC") on the accompanying consolidated balance sheets, while the losses are recorded to APIC to the extent that previous net gains on the reissuance of treasury stock are available to offset the losses. If the loss is larger than the previous gains available, then the loss is recorded to "Retained earnings (Accumulated deficit)" on the accompanying consolidated balance sheets. For the
year ended December 31, 2017
(successor),
28,279
treasury shares were purchased to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the
period of April 23, 2016 through December 31, 2016 (successor)
,
22,485
treasury shares were purchased in connection with the retirements of the former Chief Executive Officer and the former Chief Financial Officer.
New Accounting Pronouncements
.
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, followed by the issuance of certain additional related accounting standards updates (collectively codified in “ASC 606”), providing a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance. The guidance requires entities to recognize revenue using the following five-step model: 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 as the entity satisfies each performance obligation.
The Company is adopting this guidance effective January 1, 2018. In preparation for adoption, we evaluated our sales contracts and accounting procedures for recording revenue. We did not identify any material differences between our existing revenue recognition practices vs. the new guidance with respect to either timing or presentation in our financial statements. The Company’s stated policy for recognition of revenue when sales for our account are not in proportion to our ownership interest in production was to use the entitlement method. The entitlement method is not available under the new standard. However, there were no disproportionate sales arrangements in place for any of the reporting periods presented. The Company is using the modified retrospective transition method of adoption, but adoption will not require an adjustment to retained earnings. The Company will provide expanded disclosures beginning with the quarter ended March 31, 2018 to comply with the requirements of this new guidance.
In February 2016, the FASB issued ASU 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.
At December 31, 2017 the Company’s total lease commitments were approximately
$6.2 million
. Of this total,
$2.0 million
related to our corporate office sub-lease which has a remaining term of
3.4
years. The remaining are generally for equipment and vehicle leases, most of which are expiring during 2018.The Company is in the process of evaluating other contracts that may contain lease components that need to be recognized under this standard. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Management continuously evaluates the economics of leasing vs. purchase for operating equipment. The
lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than the current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted.
In August 2016, the FASB issued ASU 2016-15, which provides greater clarity to preparers on the treatment of eight specific items within an entity’s statement of cash flows with the goal of reducing existing diversity on these items. The guidance is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The Company will apply this new guidance to the statement of cash flows that will be included in our first quarter 2018 10-Q.
In January 2017, the FASB issued ASU 2017-01, to assist entities in evaluating whether transactions should be accounted for as an acquisition or disposal of an asset or business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities are not a business. The guidance is effective for companies beginning January 1, 2018 with early adoption permitted. The Company will apply this guidance to any new acquisition or disposal transactions that in may enter into after January 1, 2018.
In May 2017, the FASB issued ASU 2017-09, which provides clarity on what changes to share-based payment awards are considered substantive and require modification accounting to be applied. The guidance is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. The Company does not expect ASU 2017-09 to have a significant impact on our financial statements or disclosures.
2. Earnings Per Share
Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 12, the Company’s then outstanding common stock was canceled and new common stock and warrants were issued.
Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, as if the end of the reporting period was the end of the performance period. As we recognized a net loss for the
period of April 23, 2016 through December 31, 2016 (successor)
and the year ended
2015
(predecessor), the unvested share-based payments and stock options were not recognized in the Diluted EPS calculations as they would be antidilutive. Certain stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the
period of January 1, 2016 through April 22, 2016 (predecessor)
, and are discussed below.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the year ended
2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended
2015
(predecessor) (in thousands, except per share amounts):
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Successor Year Ended December 31, 2017
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|
Successor from April 23, 2016 through December 31, 2016
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Share Amounts
|
$
|
71,971
|
|
|
11,453
|
|
|
$
|
6.28
|
|
|
$
|
(156,288
|
)
|
|
10,013
|
|
|
$
|
(15.61
|
)
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Awards
|
|
|
6
|
|
|
|
|
|
|
—
|
|
|
|
|
Restricted Stock Units Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
Stock Option Awards
|
|
|
55
|
|
|
|
|
|
|
—
|
|
|
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Assumed Share Conversions
|
$
|
71,971
|
|
|
11,514
|
|
|
$
|
6.25
|
|
|
$
|
(156,288
|
)
|
|
10,013
|
|
|
$
|
(15.61
|
)
|
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|
|
|
|
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|
Predecessor from January 1, 2016 through April 22, 2016
|
|
Predecessor Year Ended December 31, 2015
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Share Amounts
|
$
|
851,611
|
|
|
44,692
|
|
|
$
|
19.06
|
|
|
$
|
(1,653,971
|
)
|
|
44,463
|
|
|
$
|
(37.20
|
)
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Awards
|
|
|
1,005
|
|
|
|
|
|
|
—
|
|
|
|
Restricted Stock Unit Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
Stock Option Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Assumed Share Conversions
|
$
|
851,611
|
|
|
45,697
|
|
|
$
|
18.64
|
|
|
$
|
(1,653,971
|
)
|
|
44,463
|
|
|
$
|
(37.20
|
)
|
Approximately
0.3 million
and
0.1 million
stock options to purchase shares were not included in the computation of Diluted EPS for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
, respectively, because these stock options were antidilutive. Approximately
1.3 million
stock options to purchase shares were not included in the computation of Diluted EPS for the
period of January 1, 2016 through April 22, 2016 (predecessor)
, because the exercise price was out of the money, while
1.3 million
stock options to purchase shares were not included in the computation of Diluted EPS for the year ended December 31,
2015
(predecessor) as they were antidilutive.
Approximately
0.3 million
restricted stock awards for the
period of January 1, 2016 through April 22, 2016 (predecessor)
, and
0.5 million
restricted stock awards for the year ended December 31,
2015
(predecessor) were not included in the computation of Diluted EPS because they were antidilutive.
Approximately
0.1 million
and
0.2 million
shares related to restricted stock units were not included in the computation of Diluted EPS for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
, respectively, because these stock awards were antidilutive. Approximately
0.8 million
shares for the
period of January 1, 2016 through April 22, 2016 (predecessor)
, and
0.6 million
shares related to performance-based restricted stock units that could be converted to common shares based on predetermined performance and market goals, were not included in the computation of Diluted EPS for year ended December 31,
2015
(predecessor), primarily because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the performance period.
Upon the Company's emergence from bankruptcy on April 22, 2016, the Company issued 2019 and 2020 warrants (as discussed in Note 12 of these consolidated financial statements). These warrants were not included in the computation of Diluted EPS for the
year ended December 31, 2017
(successor) and the period of April 23, 2016 through December 31, 2016 (successor), as they were antidilutive.
3. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
$
|
70,017
|
|
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
|
$
|
(1,734,514
|
)
|
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
Current
|
$
|
(1,954
|
)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(410
|
)
|
Deferred
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(80,133
|
)
|
Total
|
$
|
(1,954
|
)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(80,543
|
)
|
Reconciliations of income taxes computed using the U.S. Federal statutory rate (
35%
) to the effective income tax rates are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
Federal Statutory Rate
|
35.0
|
%
|
|
35.0
|
%
|
|
|
35.0
|
%
|
|
35.0
|
%
|
State tax provisions (benefits), net of federal benefits
|
1.6
|
%
|
|
0.9
|
%
|
|
|
0.9
|
%
|
|
1.0
|
%
|
Reorganization Adjustments
|
—
|
%
|
|
—
|
%
|
|
|
(1.8
|
)%
|
|
—
|
%
|
Expiration/Write-off of NOL Carryovers
|
13.9
|
%
|
|
(74.9
|
)%
|
|
|
—
|
%
|
|
—
|
%
|
Change in Enacted Tax Rates
|
55.6
|
%
|
|
—
|
%
|
|
|
—
|
%
|
|
—
|
%
|
Executive Compensation Limitation
|
0.6
|
%
|
|
—
|
%
|
|
|
—
|
%
|
|
—
|
%
|
Other, net
|
2.3
|
%
|
|
0.2
|
%
|
|
|
1.0
|
%
|
|
(0.1
|
)%
|
Valuation allowance adjustments
|
(111.8
|
)%
|
|
38.9
|
%
|
|
|
(35.1
|
)%
|
|
(31.3
|
)%
|
Effective rate
|
(2.8
|
)%
|
|
—
|
%
|
|
|
—
|
%
|
|
4.6
|
%
|
The tax effects of temporary differences representing the net deferred tax asset (liability) at
December 31, 2017 and 2016
were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Successor
|
|
Year Ended December 31, 2017
|
|
Year Ended December 31, 2016
|
Deferred tax assets:
|
|
|
|
Federal net operating loss (“NOL”) carryovers
|
$
|
58,438
|
|
|
$
|
40,104
|
|
Oil and gas exploration and development costs
|
—
|
|
|
71,292
|
|
Alternative minimum tax credits
|
138
|
|
|
2,092
|
|
Other Carryover Items
|
619
|
|
|
1,107
|
|
Asset Retirement Obligations
|
2,329
|
|
|
11,447
|
|
Derivative Contracts
|
29
|
|
|
5,802
|
|
Unrealized share-based compensation
|
872
|
|
|
648
|
|
Other
|
2,190
|
|
|
4,164
|
|
Valuation allowance
|
(58,398
|
)
|
|
(136,656
|
)
|
Total deferred tax assets
|
$
|
6,217
|
|
|
$
|
—
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
Oil and gas exploration and development costs
|
$
|
(6,054
|
)
|
|
$
|
—
|
|
Other
|
(163
|
)
|
|
—
|
|
Total deferred tax liabilities
|
(6,217
|
)
|
|
—
|
|
|
|
|
|
Net deferred tax liabilities
|
$
|
—
|
|
|
$
|
—
|
|
The 2016 reorganization and emergence from bankruptcy had a significant impact on the Company’s tax attributes. The Company’s net operating loss carryforward (NOL) was
$1.3 billion
as of December 31, 2016. The Company was able to fully absorb cancellation of debt income (CODI) of
$854 million
from the reorganization with NOL carryforwards, reducing the available NOL carryforward to
$451 million
. The Company’s remaining NOL carryforward is severely limited under Sec. 382 due to the change in control annual limitation of
$6 million
. The NOL carryforward that will expire before utilization due to the IRC Sec. 382 limitation is estimated to be
$337 million
. A substantial portion of the deferred tax asset associated with the NOLs expected to expire was written off in 2016 and the remaining portion was written off in 2017. The remaining NOL carryforward after excess Sec. 382 limitation is
$114 million
. The current year taxable loss has increased the available NOL carryforward to
$278 million
as of
December 31, 2017
, which will expire in 2033 through 2037 if not utilized in earlier periods.
The Company was in a net deferred tax asset position at
December 31, 2017
and
2016
. Management has determined that it is not more likely than not that the Company will realize future cash benefits from this additional tax basis and remaining carryover items and accordingly has recorded a full valuation allowance to offset its tax assets. The Company’s valuation allowance balance was
$58 million
and
$137 million
at
December 31, 2017
and
2016
, respectively.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the "Act"). The Act makes broad and complex changes to the U.S. tax code that includes, among other provisions, a permanent reduction of the U.S. federal corporate tax rate from
35%
to
21%
and a repeal of the alternative minimum tax regime, both effective January 1, 2018. The remeasurement of the Company’s deferred tax balances to reflect the reduced corporate income tax rate as of
December 31, 2017
resulted in a
$39 million
reduction in the net deferred tax asset balance with a corresponding reduction in the previously established valuation allowance. Under the transition rules related to the repeal of the alternative minimum tax regime, the alternative minimum tax credit carryforward of
$2 million
will be refundable in 2018 through 2021, if not used to offset regular tax liability. The previously established valuation allowance against the AMT credit carryforward has been released, resulting in a tax benefit of
$2 million
.
The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop. The final application of the Act to the Company’s financial results may differ from what we have provisionally provided for as of
December 31, 2017
. Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Company has utilized in calculating the transition impacts.
As of
December 31, 2017
, we do not have any accrued liability for uncertain tax positions. We do not believe the total of unrecognized tax positions will significantly increase or decrease during the next 12 months.
The Company records interest and penalties related to potential underpayment of any unrecognized tax benefits as a component of income tax expense. The Company has not incurred any interest or penalties associated with unrecognized tax benefits.
Our U.S. federal and state income tax returns from 2015 forward are subject to examination. For years prior to 2015 our U.S federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. There are no material unresolved items related to periods previously audited by these taxing authorities.
4. Long-Term Debt
As of
December 31, 2017
and
December 31, 2016
, the Company's long-term debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
Bank Borrowings
(1)
|
$
|
73,000
|
|
|
$
|
198,000
|
|
Second Lien Notes due 2024
|
200,000
|
|
|
—
|
|
|
273,000
|
|
|
198,000
|
|
Unamortized discount on Second Lien Notes due 2024
|
(1,992
|
)
|
|
—
|
|
Unamortized debt issuance cost on Second Lien Notes due 2024
|
(5,683
|
)
|
|
—
|
|
Total Long-Term Debt
|
$
|
265,325
|
|
|
$
|
198,000
|
|
(1) Unamortized debt issuance costs on our Credit Facility borrowing are included in "Other Long-Term Assets" in our consolidated balance sheet. As of
December 31, 2017
we had
$5.5 million
in unamortized debt issuance costs.
Revolving Credit Facility.
Amounts outstanding under our Credit Facility (defined below) were
$73.0 million
and
$198.0 million
as of
December 31, 2017
and
2016
, respectively. As discussed in Note 12 of these consolidated financial statements, on April 22, 2016 (the “Effective Date”), the Prior First Lien Credit Facility was terminated and paid in full, and the Company entered into a Senior Secured Revolving Credit Agreement among the Company as borrower, JPMorgan Chase Bank, National Association as administrative agent, and certain lenders party thereto. On April 19, 2017, the Company amended and restated the Senior Secured Revolving Credit Agreement by entering into a First Amended and Restated Senior Secured Revolving Credit Agreement (the “Credit Agreement”) among the Company as borrower, JPMorgan Chase Bank, N.A. as administrative agent, and certain lenders that are a party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “Credit Facility”). The Credit Facility matures April 19, 2022. The maximum credit amount under the Credit Facility is currently
$600 million
with a borrowing base of
$330 million
. The borrowing base is scheduled to be redetermined in May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders in their discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to
$25 million
, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.
Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). The applicable margin ranges from
1.75%
to
2.75%
for ABR Loans and
2.75%
to
3.75%
for Eurodollar Loans. The Alternate Base Rate and LIBOR Rates are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a
0.50%
commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at
2.00%
per annum above the rate and margin otherwise applicable thereto.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries, including a first priority lien on properties attributed with at least
85%
of estimated proved reserves of the Company and its subsidiaries.
The Credit Agreement contains the following financial covenants:
|
|
•
|
a ratio of total debt to EBITDA, as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed
4.0
to 1.0 as of the last day of each fiscal quarter; and
|
|
|
•
|
a current ratio, as defined in the Credit Agreement and which includes in the numerator available borrowings undrawn under the borrowing base, of not less than
1.0
to 1.0 as of the last day of each fiscal quarter.
|
As of
December 31, 2017
, the Company was in compliance with all financial covenants under the Credit Agreement.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
Interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, totaled
$14.9 million
and
$15.3 million
for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
, respectively. Additionally, interest expense for the
year ended December 31, 2017
(successor) includes a write-down of debt issuance costs of
$2.7 million
. The amount of commitment fee amortization included in interest expense, net was
$0.4 million
and
$0.2 million
for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
, respectively.
We capitalized interest on our unproved properties in the amount
$0.8 million
and
$0.5 million
for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
, respectively.
Senior Secured Second Lien Notes
. On December 15, 2017, the Company entered into a note purchase agreement for Senior Secured Second Lien Notes (the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent (the “Second Lien Agent”), and certain holders that are a party thereto, and issued notes in an initial principal amount of
$200 million
, with a
$2.0 million
discount, for net proceeds of
$198.0 million
(the “Second Lien Facility”). The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed
$100 million
. The Second Lien matures on December 15, 2024.
Interest under the Second Lien is payable quarterly and accrues at LIBOR plus
7.5%
; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus
6.5%
as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Second Lien. To the extent that a payment, insolvency or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at
2.0%
per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default on our Credit Facility.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes issued pursuant to the Second Lien, subject to the following repayment fees: during years one and two, a customary “make-whole” amount (which is equal to the present value of the remaining interest payments through the twenty-four month anniversary of the issuance of the Second Lien, discounted at a rate equal to the Treasury Rate plus
50
basis points) plus
2.0%
of the principal amount of the notes repaid; during year three,
2.0%
of the principal amount of the notes being prepaid; during year four,
1.0%
of the principal amount of the notes being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management has deemed the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and certain of its subsidiaries, including a mortgage lien on oil and gas properties attributed with at least
85%
of estimated PV-9 of proved reserves of the Company and its subsidiaries and
85%
of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the Administrative Agent of the Credit Facility.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issue additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiaries and in the denominator the total net indebtedness of the Company and its restricted subsidiaries, of not less than
1.25
to 1.0 as of each date of determination (the “Asset Coverage Ratio Requirement”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.
The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA, as defined in the purchase agreement, for the most recently completed four fiscal quarters, not to exceed
4.5
to 1.0 as of the last day of each fiscal quarter.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien Facility to be immediately due and payable.
As of
December 31, 2017
, net amounts recorded for the Second Lien Notes
$192.3 million
, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled
$0.8 million
from the date of issuance through
December 31, 2017
(successor).
Debt Issuance Costs
. The Company capitalizes legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with issuing debt. The costs associated with our Second Lien Notes are amortized on an effective interest basis over the term of the Second Lien Notes, while issuance costs related to our line of credit arrangement are capitalized and amortized ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings.
Bankruptcy Filing.
As discussed in Note 12 of these consolidated condensed financial statements, the Chapter 11 filing of the Company and the Chapter 11 Subsidiaries constituted an event of default with respect to our then-existing debt obligations. As a result, the Company's pre-petition unsecured senior notes and secured debt under the Company's previous credit facility (the “Prior First Lien Credit Facility”) became immediately due and payable, but any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 filing. On April 22, 2016, upon the Company's emergence from bankruptcy, the senior notes and borrowing under the debtor-in-possession credit facility (“DIP Credit Agreement”) (along with certain unsecured claims as discussed further in Note 12) were exchanged for
88.5%
of the common stock of the reorganized entity. Additional information regarding the bankruptcy proceedings is included in Note 12 of these consolidated financial statements.
Debtor-In-Possession Financing
. As part of the Chapter 11 filings, we entered into the DIP Credit Agreement. The proceeds of borrowings under the DIP Credit Agreement were primarily used to pay down the pre-petition Prior First Lien Credit Facility upon emergence from bankruptcy, and were also used to pay certain costs, fees and expenses related to the Chapter 11 cases, authorized pre-petition claims, and amounts due in connection with the DIP Credit Agreement, including on account of certain “adequate protection” obligations. Pursuant to the Plan, the DIP Credit Agreement, at the option of the lenders, converted into the post-emergence Company’s common stock, which was part of the
88.5%
of the common stock distributed to the then current holders of the senior notes and certain unsecured creditors upon emergence from the bankruptcy proceedings. As a result, the
$75.0 million
borrowed under the DIP Credit Agreement was not required to be repaid and the DIP Credit Agreement was terminated upon the Company’s exit from bankruptcy.
We paid the lenders under the DIP Credit Agreement a
3.0%
commitment fee, at the time funds were made available under the facility. The commitment fee was included in interest expense during the
period of January 1, 2016 through April 22, 2016 (predecessor)
. Total interest expense on the DIP Credit Agreement was
$6.4 million
during the
period of January 1, 2016 through April 22, 2016 (predecessor)
.
Prior First Lien Credit Facility Bank Borrowings
. During the bankruptcy proceedings we paid interest on our Prior First Lien Credit Facility in the normal course. Interest expense on the Prior First Lien Credit Facility, including commitment fees and amortization of debt issuance costs, totaled
$6.8 million
and
$9.4 million
for the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the year ended December 31, 2015 (predecessor)
, respectively. The amount of commitment fees included in interest expense, net was
no
t material for the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
$0.5 million
for
the year ended December 31, 2015 (predecessor)
, respectively.
Additionally, we capitalized interest on our unproved properties in the amount of
$4.9 million
for
the year ended December 31, 2015 (predecessor)
. Capitalized interest on our unproved properties would have been immaterial for the
period of January 1, 2016 through April 22, 2016 (predecessor)
, and therefore we did
no
t capitalize any interest.
Prior Senior Notes Due
. On April 22, 2016, the obligations of the Company and the Chapter 11 Subsidiaries with respect to these notes were canceled pursuant to the plan of reorganization and the holders thereof were issued common stock of the post-emergence entity in exchange therefor. There was
no
interest expense on the senior notes for the
period of January 1, 2016 through April 22, 2016 (predecessor)
due to our bankruptcy proceedings. Contractual interest on the senior notes for the
period of January 1, 2016 through April 22, 2016 (predecessor)
totaled
$21.6 million
. Interest expense on the senior notes, including amortization of debt issuance costs, debt discount and debt premium, totaled
$70.8 million
for
the year ended December 31, 2015 (predecessor)
.
5. Price-Risk Management Activities
Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in "Net gain (loss) on commodity derivatives" on the accompanying consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil, natural gas and NGL prices, mainly through the purchase of price swaps, collars and basis swaps.
For the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
we recognized a
$17.9 million
gain and a
$19.7 million
loss, respectively, relating to our derivative activities. For
the year ended December 31, 2015 (predecessor)
we recognized a
$0.2 million
gain. The Company made net cash payments of
$1.4 million
and
$1.9 million
for settled derivative contracts for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
. For
the year ended December 31, 2015 (predecessor)
we received net cash payments of
$2.5 million
for settled derivative contracts. There were no derivative instruments outstanding during the
period of January 1, 2016 through April 22, 2016 (predecessor)
.
As of December 31, 2017 and 2016 we had
$2.2 million
and
$0.4 million
in receivables for settled derivatives which were recognized on the accompanying consolidated balance sheet in “Accounts receivable” and were subsequently collected in January
2018
and
2017
, respectively. As of December 31, 2017 and 2016 we had
$0.4 million
and
$1.8 million
in payables for settled derivatives which were recognized on the accompanying consolidated balance sheet in "Accounts payable and accrued liabilities" and were subsequently paid in January
2018
and
2017
, respectively.
The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. As of December 31,
2017
and
2016
there was
$5.1 million
and
$0.5 million
in current unsettled derivative assets, while long-term unsettled derivative assets were
$2.6 million
and
no
t material as of
December 31, 2017
and
2016
, which are included in other long-term assets. As of December 31,
2017
and
2016
there was
$5.1 million
and
$15.8 million
in current unsettled derivative liabilities and
$2.8 million
and
$1.0 million
in long-term unsettled derivative liabilities, which are included in other long-term liabilities.
The Company uses an International Swap and Derivatives Association "ISDA" master agreement for all derivative contracts. This is an industry standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company does not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a
$0.1 million
and
$16.4 million
net fair value
liability
at
December 31, 2017
and
December 31, 2016
, respectively. For further discussion related to the fair value of the Company's derivatives, refer to Note 10 of these consolidated financial statements.
The following tables summarizes the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of December 31, 2017.
|
|
|
|
|
|
|
|
Oil Derivative Swaps
(NYMEX WTI Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
2018 Contracts
|
|
|
|
1Q18
|
151,000
|
|
|
$
|
52.80
|
|
2Q18
|
140,400
|
|
|
$
|
52.57
|
|
3Q18
|
130,400
|
|
|
$
|
52.40
|
|
4Q18
|
122,800
|
|
|
$
|
52.23
|
|
|
|
|
|
2019 Contracts
|
|
|
|
1Q19
|
97,200
|
|
|
$
|
52.40
|
|
2Q19
|
92,700
|
|
|
$
|
52.32
|
|
3Q19
|
88,500
|
|
|
$
|
52.39
|
|
4Q19
|
84,500
|
|
|
$
|
52.30
|
|
|
|
|
|
2020 Contracts
|
|
|
|
1Q20
|
51,000
|
|
|
$
|
51.49
|
|
2Q20
|
49,250
|
|
|
$
|
51.46
|
|
3Q20
|
47,500
|
|
|
$
|
51.42
|
|
4Q20
|
46,500
|
|
|
$
|
51.40
|
|
|
|
|
|
|
|
|
|
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements)
|
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|
|
|
|
2018 Contracts
|
|
|
|
1Q18
|
5,238,000
|
|
|
$
|
3.42
|
|
2Q18
|
8,245,000
|
|
|
$
|
2.86
|
|
3Q18
|
8,014,000
|
|
|
$
|
2.88
|
|
4Q18
|
7,976,000
|
|
|
$
|
2.96
|
|
|
|
|
|
2019 Contracts
|
|
|
|
1Q19
|
6,016,000
|
|
|
$
|
3.07
|
|
2Q19
|
6,060,000
|
|
|
$
|
2.83
|
|
3Q19
|
5,550,000
|
|
|
$
|
2.84
|
|
4Q19
|
5,966,000
|
|
|
$
|
2.84
|
|
|
|
|
|
2020 Contracts
|
|
|
|
1Q20
|
5,370,000
|
|
|
$
|
2.83
|
|
2Q20
|
1,170,000
|
|
|
$
|
2.86
|
|
3Q20
|
1,170,000
|
|
|
$
|
2.86
|
|
4Q20
|
1,170,000
|
|
|
$
|
2.86
|
|
|
|
|
|
|
|
|
|
NGL Derivative Swaps
(OPIS Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
2018 Contracts
|
|
|
|
1Q18
|
126,000
|
|
|
$
|
24.78
|
|
2Q18
|
118,200
|
|
|
$
|
24.78
|
|
3Q18
|
112,200
|
|
|
$
|
24.78
|
|
4Q18
|
148,200
|
|
|
$
|
24.78
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel Settlements)
|
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
2018 Contracts
|
|
|
|
1Q18
|
5,105,000
|
|
|
$
|
(0.11
|
)
|
2Q18
|
6,795,000
|
|
|
$
|
(0.04
|
)
|
3Q18
|
3,020,000
|
|
|
$
|
(0.03
|
)
|
4Q18
|
2,730,000
|
|
|
$
|
(0.09
|
)
|
|
|
|
|
2019 Contracts
|
|
|
|
1Q19
|
750,000
|
|
|
$
|
(0.11
|
)
|
|
|
|
|
|
|
|
|
Oil Basis Derivative Swaps
(NYMEX WTI and Argus Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
2018 Contracts
|
|
|
|
1Q18
|
20,000
|
|
|
$
|
4.06
|
|
2Q18
|
30,000
|
|
|
$
|
4.06
|
|
3Q18
|
30,000
|
|
|
$
|
4.06
|
|
4Q18
|
30,000
|
|
|
$
|
4.06
|
|
6. Commitments and Contingencies
Rental and lease expense was
$4.2 million
,
$5.7 million
,
$4.5 million
and
$16.8 million
for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended December 31, 2015 (predecessor), respectively. The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During 2016 the Company entered into a new
four
-year sub-lease agreement for office space in Houston, Texas. The operating lease commenced on January 1, 2017. Additionally, on August 31, 2017 we amended the sub-lease agreement for additional office space. As of
December 31, 2017
, the minimum contractual obligations were approximately
$2.0 million
in the aggregate. Our policy is to amortize the total payments under the lease agreement on a straight-line basis over the term of the lease.
Our minimum annual obligations under non-cancelable operating lease commitments were
$4.6 million
for 2018,
$0.7 million
for 2019,
$0.6 million
for
2020
,
$0.3 million
for
2021
and approximately
$6.2 million
in the aggregate.
We have gas transportation and processing minimum obligations amounting to
$6.8 million
for
2018
,
$8.4 million
for
2019
,
$7.5 million
for
2020
,
$0.3 million
for
2021
and
$23.0 million
in the aggregate.
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.
7. Share-Based Compensation
Share-Based Compensation Plans
Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 12, the Company's previous share-based compensation plans were canceled and the new 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Additionally, upon the emergence the awards issued under the previous share-based compensation plan for most employees vested on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled.
For awards granted after emergence from bankruptcy, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. For the
predecessor periods the Company had estimated the forfeiture rate for share-based compensation during the initial calculation of compensation cost.
The Company computes a deferred tax benefit for restricted stock awards, unit awards and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units the Company's actual tax deduction is based on the value of the units at the time of vesting.
We receive a tax deduction for certain stock option exercises during the period the stock option awards are exercised, generally for the excess of the market value on the exercise date over the exercise price of the stock option awards. We receive an additional tax deduction when restricted stock awards vest at a higher value than the value used to recognize compensation expense at the date of grant. We are required to report excess tax benefits from the award of equity instruments as operating cash flows.
For the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
,
no
incremental tax benefit was recognized for shares that vested due to the offsetting valuation allowance as discussed in Note 3 of these consolidated financial statements. For the
period of January 1, 2016 through April 22, 2016 (predecessor)
the tax deduction realized was significantly less than the associated deferred tax asset, however the tax asset had been fully offset with a valuation allowance in prior periods so
no
incremental tax expense was realized. For the year ended December 31, 2015 (predecessor), we recognized an income tax shortfall in earnings as referenced in Note 3 of these consolidated financial statements.
Share-based compensation for the predecessor and successor periods are not comparable. The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying consolidated statements of operations was
$6.8 million
and
$3.6 million
for the
year ended December 31, 2017
(successor) and the
period of April 23, 2016 through December 31, 2016 (successor)
, respectively, and
$0.9 million
and
$4.4 million
for the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the year ended December 31, 2015 (predecessor)
, respectively.
We capitalized in property and equipment
$0.2 million
of share-based compensation for the
year ended December 31, 2017
(successor) and did
no
t capitalize any share-based compensation for the
period of April 23, 2016 through December 31, 2016 (successor)
. For the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the year ended December 31, 2015 (predecessor)
we capitalized
$0.2 million
and
$1.4 million
, respectively. We view stock option awards and restricted stock unit awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.
There was
no
share-based compensation recorded in lease operating cost for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
and the
period of January 1, 2016 through April 22, 2016 (predecessor)
. Share-based compensation recorded in lease operating cost was
$0.2 million
for
the year ended December 31, 2015 (predecessor)
.
Our shares available for future grant under our Share-Based Compensation plans were
549,665
at
December 31, 2017
. Each restricted stock award and restricted stock unit granted reduces the shares available for future grant by
one
share.
Stock Option Awards
The compensation cost related to these awards is based on the grant date fair value and is expensed over the vesting period (generally
one
to
five
years). We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards with the following assumptions for stock option awards issued during the
year ended December 31, 2017
:
|
|
|
|
|
|
Stock Option Valuation Assumptions
|
Expected Dividend
|
—
|
|
Expected volatility
|
70.3
|
%
|
Risk-free interest rate
|
1.99
|
%
|
Expected life of stock option awards (in years)
|
5.7
|
|
Grant-date market value
|
$
|
27.71
|
|
Grant-date fair value
|
$
|
17.09
|
|
To estimate expected volatility of our 2017 stock option grants we used the historical volatility of stock prices based on a group of our peer companies. The expected term for grants issued considers all relevant factors including historical and expected future employee exercise behavior. We have analyzed historical volatility and, based on an analysis of all relevant factors, we have used a
6
year look-back period to estimate expected volatility of our stock option awards.
At
December 31, 2017
, we had
$5.2 million
in unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the
year ended December 31, 2017
:
|
|
|
|
|
|
|
|
|
Shares
|
|
Wtd. Avg.
Exer. Price
|
|
|
|
|
Options outstanding, beginning of period (successor)
|
105,811
|
|
|
$
|
23.25
|
|
Options granted
|
428,974
|
|
|
$
|
27.71
|
|
Options forfeited
|
(26,055
|
)
|
|
$
|
26.96
|
|
Options canceled
|
—
|
|
|
$
|
—
|
|
Options exercised
|
—
|
|
|
$
|
—
|
|
Options outstanding, end of period (successor)
|
508,730
|
|
|
$
|
26.82
|
|
Options exercisable, end of period (successor)
|
112,338
|
|
|
$
|
25.47
|
|
Our outstanding stock option awards at
December 31, 2017
had
$1.7 million
in aggregate intrinsic value. At
December 31, 2017
the weighted average remaining contract life of stock option awards outstanding was
6.9
years and exercisable was
2.0
years. The total intrinsic value of stock option awards exercisable as of
December 31, 2017
was
$0.6 million
.
Restricted Stock Units
The 2016 equity incentive compensation plan allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is expensed over the requisite service period (generally
one
to
five
years).
As of
December 31, 2017
, we had unrecognized compensation expense of
$7.1 million
related to our restricted stock units which is expected to be recognized over a weighted-average period of
2.8 years
.
The following table represents restricted stock unit activity for the
year ended December 31, 2017
:
|
|
|
|
|
|
|
|
|
Shares
|
|
Wtd. Avg.
Grant Price
|
Restricted units outstanding, beginning of period (successor)
|
178,847
|
|
|
$
|
23.25
|
|
Restricted stock units granted
|
326,532
|
|
|
$
|
28.21
|
|
Restricted stock units forfeited
|
(16,821
|
)
|
|
$
|
26.41
|
|
Restricted stock units vested
|
(141,818
|
)
|
|
$
|
25.15
|
|
Restricted stock units outstanding, end of period (successor)
|
346,740
|
|
|
$
|
26.99
|
|
In accordance with their employment agreements, the former Chief Executive Officer and Chief Financial Officer vested in all of their share-based compensation awards in conjunction with their retirements. As such, all expense for their stock option awards and restricted stock unit awards was accelerated and is included in the share-based compensation expense for the
period of April 23, 2016 through December 31, 2016 (successor)
. The total expense included in the period for such awards was
$1.6 million
for
76,058
restricted stock unit awards and
$0.7 million
for
60,847
stock option awards.
Employee Savings Plan
We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible employees an amount up to
100%
of the first
6%
of compensation based on the contributions made by the eligible employees in 2017 and
2%
in 2016. The Company's 2017 and 2016 plan contributions of
$0.5 million
and
$0.3 million
were paid in cash during the first quarter of 2018 and 2017, respectively. The Company's contributions to the 401(k) savings plan were
$0.7 million
for the year ended December 31, 2015 (predecessor). These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.
Predecessor Share-Based Compensation Awards
We previously had shares outstanding under multiple share-based compensation plans. In addition, we had an employee stock purchase plan and also had an employee stock ownership plan prior to their termination during 2016 and 2015, respectively.
Under the previous plans, stock option awards and other equity-based awards could be granted to employees, directors, and consultants, with directors only eligible to receive restricted awards. Restricted stock grants became vested over a three-year period, and stock option awards were exercisable in various terms ranging from one year to five years. Stock option awards granted typically expired ten years after the date of grant or earlier in the event of the optionee's separation from employment. At the time the stock option awards were exercised, the cash received was credited to common stock and additional paid-in capital.
The employee stock purchase plan, which began in 1993, provided eligible employees the opportunity to acquire shares of Swift Energy common stock at a discount through payroll deductions. Under this plan, we had issued
87,629
shares at a price of
$3.44
in 2015. As of December 31, 2015, this plan was terminated.
During the year ended December 31, 2015, we did
no
t grant any stock option awards and there were
no
stock option exercises. The total intrinsic value of stock option awards exercised was
no
t material.
For the year ended December 31, 2015, the Company issued
609,238
shares of restricted stock to employees, consultants, and directors. The weighted average fair values of these shares when issued for the year ended December 31, 2015 was
$2.64
per share. The grant date fair values of shares vested for the year ended December 31, 2015 was
$6.1 million
. All of the remaining grants either vested or were canceled upon emergence from bankruptcy.
During the year ended 2015, the Company granted
147,812
units of cash-settled restricted stock units. The grants had a cliff vesting period of approximately
1.0
year while the compensation expense and corresponding liability were re-measured quarterly over the corresponding service period. All of the remaining grants were canceled upon emergence from bankruptcy.
For the year ended December 31, 2015, the Company granted
216,450
performance-based restricted stock units. These units contained predetermined market and performance conditions set by our compensation committee with a performance period of
3
years.
No
shares vested during the year ended December 31, 2015. The weighted average grant date fair value for the restricted stock units granted during the year ended December 31, 2015 was
$1.98
per unit. All of the remaining grants were canceled upon emergence from bankruptcy.
8. Related-Party Transactions
We received research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled and majority owned by the aunt of the Company's former Chairman of the Board and Chief Executive Officer. We paid Tec-Com, for services pursuant to the terms of the contract, approximately
$0.5 million
for the year ended 2015 (predecessor). The contract was terminated on March 31, 2016.
As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee's charter.
9. Acquisitions and Dispositions
On April 15, 2016, we closed our transaction with Texegy LLC for the sale of a
75%
working interest share of the Company's holdings in the South Bearhead Creek and Burr Ferry field areas located in Central Louisiana. The net proceeds of
$46.9 million
were credited to the full cost pool and used primarily to reduce the amount of borrowings under the Company’s Prior First Lien Credit Facility, and for other general corporate purposes. This disposition also included the buyer's assumption of approximately
$6.5 million
of plugging and abandonment liability. On December 8, 2016, we sold the remaining
25%
working interest share of the Company's holdings in the South Bearhead Creek and Burr Ferry fields to Texegy. We received net proceeds of
$7.1 million
on the sale which were used to reduce the amount of borrowings under the Company's Credit Facility. This disposition also included the buyer's assumption of approximately
$2.4 million
of plugging and abandonment liability.
Effective April 25, 2016, we disposed of our Masters Creek field in Central Louisiana. We received net proceeds of less than
$0.1 million
and the buyer assumed approximately
$8.1 million
of plugging and abandonment liability.
Effective September 30, 2016, we closed our transaction with Blue Marble Resources LLC for the sale of the Company's holdings in our Sun TSH field located in South Texas. We received net proceeds of approximately
$0.9 million
and the buyer assumed approximately
$1.8 million
of plugging and abandonment liability.
On December 1, 2016, we closed our transaction with Hilcorp Energy I, L.P., effective September 1, 2016, for the sale of the Company's holdings in our Lake Washington field located in South East Louisiana. We received net proceeds of approximately
$37.0 million
which were used to reduce the amount of borrowings under the Company's Credit Facility. The buyer assumed approximately
$30.5 million
of plugging and abandonment liability.
Effective December 16, 2016, we sold an overriding royalty package in the Barnett Shale area for
$0.5 million
to San Saba Royalty Company.
Effective July 31, 2017, we disposed of our Wheeler Ranch wells in AWP Olmos in South Texas. We received net proceeds of
$0.7 million
and the buyer's assumption of approximately
$0.6 million
of plugging and abandonment liability. No gain or loss was recorded on the sale of this property.
On November 6, 2017 the Company purchased the non-operating working interest of two joint interest partners in certain wells and leases in AWP Field. The value of these assets are concentrated in proved oil and gas reserves. This purchase constitutes a business combination. The acquisition cost of this interest was
$9.4 million
. Additionally, the Company assumed asset retirement obligations of
$0.2 million
. We determined that these amounts are representative of the fair value of these assets. The fair-value measurements of these assets and associated asset retirement obligations are based on inputs that are not observable in the market and thus represent Level 3 inputs. This fair value assessment is primarily based on the income stream forecast for these properties.
Effective December 22, 2017, the Company closed a Purchase and Sale contract to sell the Company's wellbores and facilities in Bay De Chene. The contract price of
$16.3 million
will be paid by the Company, as seller. The payments will be funded over time, passed through an escrow account, with funds being released as abandonment work is performed and certified to meet state requirements. The buyer assumed approximately
$20.9 million
of plugging and abandonment liability with no gain or loss recorded on the sale of this property. Of the
$16.3 million
to be paid by the Company, approximately
$6 million
was released in the first quarter of 2018 for completion of initial post-closing requirements. The remaining
$10 million
will be funded as the abandonment work is completed and certified. Based on the estimated timing of the abandonment work to be performed,
$11.3 million
has been included in accrued capital expenditures as a current liability and
$5.0 million
has been included in other long-term liabilities in the accompanying consolidated balance sheet as of
December 31, 2017
.
In accordance with the full cost method of accounting, no gains or losses were recognized on these disposition transactions as they were not considered a significant amount of reserves or the proceeds did not significantly alter the relationships between capitalized costs and reserves. The sales proceeds, accrued payments and removal of related asset retirement obligations were treated as adjustments to our proved oil and gas property accounts.
10. Fair Value Measurements
Fair Value on a Recurring Basis
. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the highly liquid or short-term nature of these instruments.
The carrying value of our revolving Credit Facility approximates fair value because the Company's current borrowing base rate does not materially differ from market rates for similar bank borrowings. The carrying value of our Second Lien Notes included in long-term debt approximates fair value because market conditions have not changed significantly since the Second Lien Notes were issued on December 15, 2017. These are considered Level 3 valuations (defined below).
The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers.
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (table below in millions):
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
The following table presents our assets and liabilities that are measured at fair value on a recurring basis as of
December 31, 2017
and
2016
. For additional discussion related to the fair value of the Company's derivatives, refer to Note 5 of these consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
(in millions)
|
Total
|
|
Quoted Prices in
Active markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
December 31, 2017
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
$
|
7.2
|
|
|
$
|
—
|
|
|
$
|
7.2
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.3
|
|
|
$
|
—
|
|
|
$
|
0.3
|
|
|
$
|
—
|
|
NGL Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
$
|
1.3
|
|
|
$
|
—
|
|
|
$
|
1.3
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.3
|
|
|
$
|
—
|
|
|
$
|
0.3
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
5.2
|
|
|
$
|
—
|
|
|
$
|
5.2
|
|
|
$
|
—
|
|
Oil Basis Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
NGL Derivatives
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
Natural Gas Basis Derivatives
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
$
|
13.7
|
|
|
$
|
—
|
|
|
$
|
13.7
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
3.0
|
|
|
$
|
—
|
|
|
$
|
3.0
|
|
|
$
|
—
|
|
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying consolidated balance sheets in “Other current assets”, "Other long-term assets", "Accounts payable and accrued liabilities" and "Other long-term liabilities", respectively.
11. Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis as part of DD&A expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is recorded to the “Property and Equipment” balance on our accompanying consolidated balance sheets.
Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 12, the Company applied fresh start accounting. This included adjusting the Asset Retirement Obligations based on the estimated fair values at April 22, 2016.
The following provides a roll-forward of our asset retirement obligations (in thousands):
|
|
|
|
|
Asset Retirement Obligations as of December 31, 2015
|
$
|
63,555
|
|
Accretion expense
|
1,610
|
|
Liabilities incurred for new wells and facilities construction
|
1
|
|
Reductions due to sold wells and facilities
|
(6,545
|
)
|
Reductions due to plugged wells and facilities
|
(85
|
)
|
Revisions in estimates
|
488
|
|
Asset Retirement Obligations as of April 22, 2016 (Predecessor)
|
$
|
59,024
|
|
Fair value fresh start adjustment
|
5,216
|
|
|
|
|
|
Asset Retirement Obligation as of April 22, 2016 (Successor)
|
$
|
64,240
|
|
Accretion expense
|
2,878
|
|
Liabilities incurred for new wells and facilities construction
|
34
|
|
Reductions due to sold wells and facilities
|
(42,857
|
)
|
Reductions due to plugged wells and facilities
|
(916
|
)
|
Revisions in estimates
|
8,877
|
|
Asset Retirement Obligations as of December 31, 2016 (Successor)
|
$
|
32,256
|
|
Accretion expense
|
2,322
|
|
Liabilities incurred for new wells and facilities construction
|
253
|
|
Reductions due to sold wells and facilities
|
(21,466
|
)
|
Reductions due to plugged wells and facilities
|
(2,366
|
)
|
Revisions in estimates
|
(212
|
)
|
Asset Retirement Obligations as of December 31, 2017 (Successor)
|
$
|
10,787
|
|
At
December 31, 2017 and 2016
, approximately
$2.1 million
and
$10.0 million
, respectively, of our asset retirement obligation was classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. The 2016 revisions in estimates are primarily attributable to revaluation changes in our Bay De Chene field and a portion of our South Texas AWP field, which led to an increase in the estimated plugging and abandonment costs for our wells. The 2017 and 2016 reductions due to sold wells and facilities are primarily attributable to the disposition of our assets in the Bay De Chene and Lake Washington fields, respectively.
12. Emergence from Voluntary Reorganization under Chapter 11 Proceedings
On
December 31, 2015
, Swift Energy Company ("Swift Energy," the "Company" or "we") and eight of its U.S. subsidiaries (the "Chapter 11 Subsidiaries") filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the U.S. Bankruptcy Code (the "Bankruptcy Code") in the U.S. Bankruptcy Court for the District of Delaware under the caption
In re Swift Energy Company, et al
(Case No. 15-12670). The Company and the Chapter 11 Subsidiaries received bankruptcy court confirmation of their joint plan of reorganization (the "Plan") on March 31, 2016, and subsequently emerged from bankruptcy on April 22, 2016 (the "Effective Date").
Effect of the Bankruptcy Proceedings.
During the bankruptcy proceedings, the Company conducted normal business activities and was authorized to pay and has paid (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, pre-petition amounts owed to pipeline owners that transport the Company's production, and funds belonging to third parties, including royalty holders and partners.
In addition, subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, we did not record interest expense on the Company’s senior notes for the period of January 1, 2016 through April 22, 2016 (as the predecessor). For that period, contractual interest on the senior notes totaled
$21.6 million
.
Plan of Reorganization
. Pursuant to the Plan, the significant transactions that occurred upon emergence from bankruptcy were as follows:
|
|
•
|
the approximately
$906 million
of indebtedness outstanding on account of the Company’s senior notes,
$75 million
in borrowings under the Company's DIP Credit Agreement (described below) and certain other unsecured claims were exchanged for
88.5%
of the post-emergence Company’s common stock;
|
|
|
•
|
the lenders under the DIP Credit Agreement (as defined and more fully described below) received an additional backstop fee consisting of
7.5%
of the post-emergence Company’s common stock;
|
|
|
•
|
the Company’s pre-petition common stock was canceled and the current shareholders received
4%
of the post-emergence Company’s common stock and warrants to purchase up to
30%
of the reorganized Company's equity. See Note 13 of these consolidated financial statements for more information;
|
|
|
•
|
claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;
|
|
|
•
|
the Company entered into a registration rights agreement to provide customary registration rights to certain holders of the Company’s post-emergence common stock who, together with their affiliates received upon emergence
5%
or more of the outstanding common stock of the Company;
|
|
|
•
|
the Company sold (effective April 15, 2016) a portion of its interest in its Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, for net proceeds of approximately
$46.9 million
including deposits received prior to the closing date; and
|
|
|
•
|
the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (defined herein as "Credit Facility") with an initial
$320 million
borrowing base was established. For more information refer to Note 4 of these consolidated financial statements.
|
DIP Credit Agreement.
In connection with the pre-petition negotiations of the restructuring support agreement, certain holders of the Company’s senior notes agreed to provide the Company and the Chapter 11 Subsidiaries a debtor in possession facility (the “DIP Credit Agreement”). The DIP Credit Agreement provided for a multi-draw term loan of up to
$75.0 million
, which became available to the Company upon the satisfaction of certain milestones and contingencies. Upon emergence from bankruptcy, the Company had drawn down the entire
$75.0 million
available. Pursuant to the Plan, the borrowings under the DIP Credit Agreement, at the option of the lenders to the DIP Credit Agreement, converted into the post-emergence Company's common stock, which was part of the
88.5%
of the common stock distributed to the holders of the Company's senior notes and certain unsecured creditors. As such, the
$75.0 million
borrowed under the DIP Credit Agreement was not required to be repaid in cash and terminated upon the Company’s exit from bankruptcy. For more information refer to Note 4 of these consolidated financial statements.
13. Fresh Start Accounting
Upon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh start accounting, pursuant to FASB ASC 852, “
Reorganizations”
, and applied the provisions thereof to its consolidated financial statements. The Company qualified for fresh start accounting because (i) the holders of existing voting shares of the pre-emergence debtor-in-possession, referred to herein as the "Predecessor" or "Predecessor Company," received less than 50% of the voting shares of the post-emergence successor entity, which we refer to herein as the "Successor" or "Successor Company" and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting following the close of business on April 22, 2016 when it emerged from bankruptcy protection. Adopting
fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the consolidated financial statements as of April 23, 2016 forward are not comparable with the consolidated financial statements prior to that date. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 22, 2016.
Reorganization Value
. Reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately before restructuring. Under fresh start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values.
Our reorganization value was derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the bankruptcy court to be in the range of
$460 million
to
$800 million
. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to be approximately
$474 million
. This valuation analysis was prepared using reserve information, development schedules, other
financial information and financial projections and applying standard valuation techniques, including risked net asset value analysis and public comparable company analyses.
Valuation of Oil and Gas Properties.
The Company’s principal assets are its oil and gas properties, which the Company accounts for under the Full Cost Accounting method as described in Note 1. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.
The Company’s Reserves Engineers developed full cycle production models for all of the Company’s developed wells and identified undeveloped drilling locations within the Company’s leased acreage. The undeveloped locations were categorized based on varying levels of risk using industry standards. The proved locations were limited to wells expected to be drilled in the Company’s five-year plan. The locations were then segregated into geographic areas. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five year forward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. These prices were adjusted for typical differentials realized by the Company for location and product quality adjustments. Transportation cost estimates were based on agreements in place at the emergence date. Development and operating costs were based the Company’s recent cost trends adjusted for inflation.
Risk factors were determined separately for each geographic area. Based on the geological characteristics of each area appropriate risk factors for each of the reserve categories were applied. The Company and its valuation experts considered production, geological and mechanical risk to determine the probability factor for each reserve category in each area.
The risk adjusted after tax cash flows were discounted at
12%
. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. The after tax cash flow computations included utilization of the Company’s unamortized tax basis in the properties as of the emergence date. Plugging and abandonment costs were included in the cash flow projections for undeveloped reserves but were excluded for developed reserves since the fair value of this liability was determined separately and included in the emergence date liabilities reported on the consolidated balance sheet.
From this analysis the Company concluded the fair value of its proved reserves was
$509.4 million
, and the value of its probable reserves was
$45.5 million
as of the Effective Date. The fair value of the possible reserves was determined to be de minimus and no value therefore recognized. The value of probable reserves was classified as unevaluated costs. The Company also reviewed its undeveloped leasehold acreage and concluded that the fair value of its probable reserves appropriately captured the fair value of its undeveloped leasehold acreage. These amounts are reflected in the Fresh Start Adjustments item number 12 below.
The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Effective Date (in thousands):
|
|
|
|
|
|
April 22, 2016
|
Enterprise Value
|
$
|
473,660
|
|
Plus: Cash and cash equivalents
|
8,739
|
|
Less: Fair value of debt
|
(253,000
|
)
|
Less: Fair value of warrants
|
(14,967
|
)
|
Fair value of Successor common stock
|
$
|
214,432
|
|
|
|
Shares outstanding at April 22, 2016
|
10,000
|
|
|
|
Per share value
|
$
|
21.44
|
|
Upon issuance of the Credit Facility on April 22, 2016, the Company received net proceeds of approximately
$253 million
and incurred debt issuance costs of approximately
$7.0 million
.
In accordance with the Plan, the Company issued
two
series of warrants (each for up to
15%
of the reorganized Company's equity) to the former holders of the Company’s common stock, one to expire on the close of business on April 22, 2019 (the “2019 Warrants”) and the other to expire on the close of business on April 22, 2020 (the “2020 Warrants” and, together with the 2019 Warrants, the “Warrants”). Following the Effective Date, there were 2019 Warrants outstanding to purchase up to an aggregate of
2,142,857
shares of Common Stock at an initial exercise price of
$80.00
per share. Following the Effective Date, there were 2020
Warrants outstanding to purchase up to an aggregate of
2,142,857
shares of Common Stock at an initial exercise price of
$86.18
per share. All unexercised Warrants shall expire, and the rights of the holders of such Warrants to purchase Common Stock shall terminate at the close of business on the first to occur of (i) their respective expiration dates or (ii) the date of completion of (A) any Fundamental Equity Change (as defined in the Warrant Agreement) or (B) an Asset Sale (as defined in the Warrant Agreement). The fair value of the 2019 and 2020 Warrants was
$3.26
and
$3.73
per warrant, respectively. A Black- Scholes pricing model with the following assumptions was used in determining the fair value: strike price of
$80
and
$86.18
; expected volatility of
70%
and
65%
; expected dividend rate of
0.0%
; risk free interest rate of
1.01%
and
1.19%
; and expiration date of
3
and
4
years, respectively. The fair value of these warrants was estimated using Level 2 inputs (for additional discussion of the Level 2 inputs, refer to Note 10 of these consolidated financial statements).
The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands):
|
|
|
|
|
|
April 22, 2016
|
Enterprise Value
|
$
|
473,660
|
|
Plus: Cash and cash equivalents
|
8,739
|
|
Plus: Other working capital liabilities
|
73,318
|
|
Plus: Other long-term liabilities
|
58,992
|
|
Reorganization value of Successor assets
|
$
|
614,709
|
|
Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.
Consolidated Balance Sheet.
The adjustments set forth in the following consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.
The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of
April 22, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
ASSETS
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
57,599
|
|
|
$
|
(48,860
|
)
|
(1)
|
$
|
—
|
|
|
$
|
8,739
|
|
Accounts receivable
|
34,278
|
|
|
(597
|
)
|
(2)
|
—
|
|
|
33,681
|
|
Other current assets
|
3,503
|
|
|
—
|
|
|
—
|
|
|
3,503
|
|
Total current assets
|
95,380
|
|
|
(49,457
|
)
|
|
—
|
|
|
45,923
|
|
Property and equipment
|
6,007,326
|
|
|
—
|
|
|
(5,448,759
|
)
|
(12)
|
558,567
|
|
Less - accumulated depreciation, depletion and amortization
|
(5,676,252
|
)
|
|
—
|
|
|
5,676,252
|
|
(12)
|
—
|
|
Property and equipment, net
|
331,074
|
|
|
—
|
|
|
227,493
|
|
|
558,567
|
|
Other Long-Term Assets
|
4,629
|
|
|
6,388
|
|
(3)
|
(798
|
)
|
(13)
|
10,219
|
|
Total Assets
|
$
|
431,083
|
|
|
$
|
(43,069
|
)
|
|
$
|
226,695
|
|
|
$
|
614,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
$
|
64,324
|
|
|
$
|
(4,666
|
)
|
(4)
|
$
|
(885
|
)
|
(14
|
)
|
$
|
58,773
|
|
Accrued capital costs
|
5,410
|
|
|
—
|
|
|
—
|
|
|
5,410
|
|
Accrued interest
|
768
|
|
|
(104
|
)
|
(5)
|
—
|
|
|
664
|
|
Undistributed oil and gas revenues
|
8,471
|
|
|
—
|
|
|
—
|
|
|
8,471
|
|
Current portion of debt
|
364,500
|
|
|
(364,500
|
)
|
(6)
|
—
|
|
|
—
|
|
Total current liabilities
|
443,473
|
|
|
(369,270
|
)
|
|
(885
|
)
|
|
73,318
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
—
|
|
|
253,000
|
|
(7)
|
—
|
|
|
253,000
|
|
Asset retirement obligation
|
51,800
|
|
|
—
|
|
|
6,101
|
|
(14
|
)
|
57,901
|
|
Other long-term liabilities
|
2,124
|
|
|
—
|
|
|
(1,033
|
)
|
(15
|
)
|
1,091
|
|
Liabilities subject to compromise
|
911,381
|
|
|
(911,381
|
)
|
(8)
|
—
|
|
|
—
|
|
Total Liabilities
|
1,408,778
|
|
|
(1,027,651
|
)
|
|
4,183
|
|
|
385,310
|
|
Stockholders' Equity:
|
|
|
|
|
|
|
|
Preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Common stock (Predecessor)
|
450
|
|
|
(450
|
)
|
(9)
|
—
|
|
|
—
|
|
Common stock (Successor)
|
—
|
|
|
100
|
|
(10)
|
—
|
|
|
100
|
|
Additional paid-in capital (Predecessor)
|
777,475
|
|
|
(777,475
|
)
|
(9)
|
—
|
|
|
—
|
|
Additional paid-in capital (Successor)
|
—
|
|
|
229,299
|
|
(10)
|
—
|
|
|
229,299
|
|
Treasury stock held at cost
|
(2,496
|
)
|
|
2,496
|
|
(9)
|
—
|
|
|
—
|
|
Retained earnings (accumulated deficit)
|
(1,753,124
|
)
|
|
1,530,612
|
|
(11)
|
222,512
|
|
(16
|
)
|
—
|
|
Total Stockholders' Equity (Deficit)
|
(977,695
|
)
|
|
984,582
|
|
|
222,512
|
|
|
229,399
|
|
Total Liabilities and Stockholders' Equity
|
$
|
431,083
|
|
|
$
|
(43,069
|
)
|
|
$
|
226,695
|
|
|
$
|
614,709
|
|
Reorganization Adjustments
|
|
1.
|
Reflects the net cash payments recorded as of the Effective Date from implementation of the Plan (in thousands):
|
|
|
|
|
|
Sources:
|
|
Net proceeds from Credit Facility
|
253,000
|
|
Total Sources
|
$
|
253,000
|
|
Uses:
|
|
Repayment of Prior First Lien Credit Facility
|
289,500
|
|
Debt issuance costs
|
6,482
|
|
Predecessor accounts payable paid upon emergence
|
5,878
|
|
Total Uses
|
$
|
301,860
|
|
Net Uses
|
$
|
(48,860
|
)
|
|
|
2.
|
Reflects the impairment of a short-term leasehold improvement build-out receivable for
$0.6 million
that will no longer be reimbursed by the building lessor as the Company's office lease contract was rejected as part of the bankruptcy.
|
|
|
3.
|
Reflects the capitalization of debt issuance costs on the Credit Facility for
$7.0 million
, of which
$6.5 million
was paid on emergence and
$0.5 million
included in accounts payable and accrued liabilities and paid in the subsequent month, as well as the write-off of a long-term leasehold improvement build-out receivable for
$0.6 million
relating to an office lease contract that was rejected in connection with the bankruptcy.
|
|
|
4.
|
Reflects the settlement of predecessor accounts payable of
$5.2 million
partially offset by accrued debt issuance costs of
$0.5 million
.
|
|
|
5.
|
Reflects the settlement of accrued interest on the Company's DIP Credit Agreement which was equitized upon emergence.
|
|
|
6.
|
On the Effective Date, the Company repaid in full all borrowings outstanding of
$289.5 million
under the Prior First Lien Credit Facility. In addition the Company equitized the outstanding DIP Credit Agreement borrowings of
$75 million
via the issuance of equity valued at
$142.3 million
.
|
|
|
7.
|
Reflects the
$253 million
in new borrowings under the Credit Facility.
|
|
|
8.
|
Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):
|
|
|
|
|
|
|
|
7.125% senior notes due 2017
|
$
|
250,000
|
|
8.875% senior notes due 2020
|
225,000
|
|
7.875% senior notes due 2022
|
400,000
|
|
Accrued interest
|
30,043
|
|
Accounts payable and accrued liabilities
|
1,713
|
|
Other long-term liabilities
|
4,625
|
|
Liabilities subject to compromise of the Predecessor Company (LSTC)
|
911,381
|
|
Fair value of equity issued to former holders of the senior notes of the Predecessor
|
(47,443
|
)
|
Gain on settlement of Liabilities subject to compromise
|
$
|
863,938
|
|
|
|
9.
|
Reflects the cancellation of the Predecessor Company equity to retained earnings.
|
|
|
10.
|
Reflects the issuance of
10.0 million
shares of common stock at a per share price of
$21.44
and
4.3 million
warrants to purchase up to
30%
of the reorganized Company's equity valued at
$15.0 million
with an average per unit value of
$3.49
. Former holders of the senior notes and certain unsecured creditors were issued
8.85 million
shares of common stock while the Backstop
|
Lenders (as defined in the DIP Credit Agreement) were issued
0.75 million
shares of common stock. Former shareholders received the warrants and
0.4 million
shares of common stock.
|
|
11.
|
Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):
|
|
|
|
|
|
|
|
Gain on settlement of Liabilities subject to compromise
|
$
|
863,938
|
|
Fair value of equity issued in excess of DIP principal
|
(67,329
|
)
|
Fair value of equity and warrants issued to Predecessor stockholders
|
(23,544
|
)
|
Fair value of equity issued to DIP lenders for backstop fee
|
(16,082
|
)
|
Other reorganization adjustments
|
(1,800
|
)
|
Cancellation of Predecessor Company equity
|
775,429
|
|
Net impact to accumulated deficit
|
$
|
1,530,612
|
|
Fresh Start Adjustments
|
|
12.
|
The following table summarizes the fair value adjustment on our oil and gas properties and accumulated depletion, depreciation and amortization (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Company
|
Fresh Start Adjustments
|
Successor Company
|
Oil and Gas Properties
|
|
|
|
Proved properties
|
$
|
5,951,016
|
|
$
|
(5,441,655
|
)
|
$
|
509,361
|
|
Unproved properties
|
12,057
|
|
33,448
|
|
45,505
|
|
Total Oil and Gas Properties
|
5,963,073
|
|
(5,408,207
|
)
|
554,866
|
|
Less - Accumulated depletion and impairments
|
(5,638,741
|
)
|
5,638,741
|
|
—
|
|
Net Oil and Gas Properties
|
324,332
|
|
230,534
|
|
554,866
|
|
|
|
|
|
Furniture, Fixtures, and other equipment
|
44,252
|
|
(40,551
|
)
|
3,701
|
|
Less - Accumulated depreciation
|
(37,510
|
)
|
37,510
|
|
—
|
|
Net Furniture, Fixtures and other equipment
|
$
|
6,742
|
|
$
|
(3,041
|
)
|
$
|
3,701
|
|
Net Oil and Gas Properties, Furniture and fixtures and accumulated depreciation
|
$
|
331,074
|
|
$
|
227,493
|
|
$
|
558,567
|
|
|
|
13.
|
Reflects the adjustment of other non-current assets to fair value.
|
|
|
14.
|
Reflects the current and long-term portion of the Company’s asset retirement obligation computed in accordance with ASC 410-20, applying the appropriate discount rate to future costs as of the emergence date.
|
|
|
15.
|
Reflects the adjustment of other non-current liabilities to fair value.
|
|
|
16.
|
Reflects the cumulative impact of fresh start adjustments as discussed above.
|
Reorganization Items
Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “(Gain) Loss on Reorganization items, net” in the Consolidated Statements of Operations. The following table summarizes reorganization items (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
Predecessor
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
Year Ended December 31, 2015
|
Gain on settlement of liabilities subject to compromise
|
$
|
—
|
|
|
|
$
|
(863,938
|
)
|
$
|
—
|
|
Fair value of equity issued in excess of DIP principal
|
—
|
|
|
|
67,329
|
|
—
|
|
Fresh start adjustments
|
—
|
|
|
|
(222,512
|
)
|
—
|
|
Reorganization legal and professional fees and expenses
|
1,598
|
|
|
|
25,573
|
|
—
|
|
Fair value of equity issued to DIP lenders for backstop fee
|
—
|
|
|
|
16,082
|
|
—
|
|
Write-off of debt issuance costs, including premium and discount on senior notes
|
—
|
|
|
|
—
|
|
6,565
|
|
Other reorganization items
|
41
|
|
|
|
21,324
|
|
—
|
|
(Gain) Loss on Reorganization items, net
|
$
|
1,639
|
|
|
|
$
|
(956,142
|
)
|
$
|
6,565
|
|
Supplementary Information (unaudited)
SilverBow Resources, Inc. and Subsidiaries
Oil and Gas Operations
Capitalized Costs.
The following table presents our aggregate capitalized costs relating to oil and natural gas producing activities and the related depreciation, depletion, and amortization (in thousands):
|
|
|
|
|
|
Total
|
December 31, 2017
|
|
Proved oil and gas properties
|
$
|
658,519
|
|
Unproved oil and gas properties
|
50,377
|
|
|
708,896
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(215,480
|
)
|
Net capitalized costs
|
$
|
493,416
|
|
|
|
December 31, 2016
|
|
Proved oil and gas properties
|
$
|
480,499
|
|
Unproved oil and gas properties
|
33,354
|
|
|
513,853
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(169,335
|
)
|
Net capitalized costs
|
$
|
344,518
|
|
There were
$50.4 million
and
$33.4 million
of unproved property costs at
December 31, 2017
and
2016
, respectively, excluded from the amortizable base. We evaluate the majority of these unproved costs within a two to four-year time frame.
Capitalized asset retirement obligations have been included in the Proved oil and gas properties as of
December 31, 2017 and 2016
.
Costs Incurred.
The following table sets forth costs incurred related to our oil and natural gas operations (in thousands) for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
Lease acquisitions and prospect costs
|
$
|
44,569
|
|
|
$
|
6,466
|
|
|
|
$
|
2,695
|
|
|
$
|
28,571
|
|
Exploration
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
Development
(1) (3)
|
149,293
|
|
|
40,908
|
|
|
|
24,082
|
|
|
74,948
|
|
Acquisition of property
|
9,426
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
Total acquisition, exploration, and development
(2)
|
$
|
203,288
|
|
|
$
|
47,374
|
|
|
|
$
|
26,777
|
|
|
$
|
103,519
|
|
(1) Facility construction costs and capital costs have been included in development costs, and totaled $11.6 million, $6.0 million, $2.2 million and $5.5 million for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended December 31, 2015 (predecessor), respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately
$4.6 million
,
$5.4 million
,
$2.9 million
and
$12.7 million
for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended December 31, 2015, respectively. In addition, the total includes
$0.8 million
,
$0.5 million
and
$4.9 million
for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
and the year ended December 31, 2015 (predecessor), respectively, of capitalized interest on unproved properties. There was no capitalized interest on unproved properties for the
period of January 1, 2016 through April 22, 2016 (predecessor)
due to our bankruptcy proceedings.
(3) Includes asset retirement obligations incurred, including revisions, of approximately $2.3 million, $8.0 million, $0.4 million and ($10.3 million) for the
year ended December 31, 2017
(successor), the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the year ended December 31, 2015 (predecessor), respectively. Does not include accrued payments associated with our Bay De Chene sale for the
year ended December 31, 2017
(successor).
Supplementary Reserves Information.
The following information presents estimates of our proved oil and natural gas reserves. Reserves were prepared in accordance with SEC rules by H. J. Gruy and Associates, Inc. (“Gruy”) as of the
years ended December 31, 2017 and 2016
and Gruy audited
99%
of our proved reserves as of December 31, 2015. Proved reserves, as of
December 31, 2017, 2016 and 2015
, were based upon the preceding 12-months' average price based on closing prices on the first business day of each month, or prices defined by existing contractual arrangements which are held constant, for that year's reserves calculation. The 12-month
2017
average adjusted prices after differentials used in our calculations were
$2.95
per Mcf of natural gas,
$50.38
per barrel of oil, and
$20.32
per barrel of NGL compared to
$2.43
per Mcf of natural gas,
$41.07
per barrel of oil, and
$16.13
per barrel of NGL for the 12-month average
2016
prices and
$2.61
per Mcf of natural gas,
$49.58
per barrel of oil, and
$14.64
per barrel of NGL for the 12-month average
2015
prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimates of Proved Reserves
|
Total
|
|
Natural Gas
|
|
Oil
|
|
NGL
|
|
(Mcfe)
|
|
(Mcf)
|
|
(Bbls)
|
|
(Bbls)
|
Proved reserves as of December 31, 2015
|
421,638,060
|
|
|
311,688,398
|
|
|
10,108,833
|
|
|
8,216,111
|
|
Extensions, discoveries, and other additions
(3)
|
92,804,898
|
|
|
92,804,900
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
(1)
|
326,679,690
|
|
|
270,749,891
|
|
|
1,821,443
|
|
|
7,500,190
|
|
Sales of minerals in place
(4)
|
(42,349,578
|
)
|
|
(7,915,022
|
)
|
|
(4,844,064
|
)
|
|
(895,030
|
)
|
Production
|
(55,031,868
|
)
|
|
(40,539,807
|
)
|
|
(1,308,521
|
)
|
|
(1,106,822
|
)
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2016
|
743,741,202
|
|
|
626,788,360
|
|
|
5,777,691
|
|
|
13,714,449
|
|
Extensions, discoveries, and other additions
(3)
|
317,023,521
|
|
|
250,063,107
|
|
|
2,054,571
|
|
|
9,105,498
|
|
Revisions of previous estimates
(1)
|
(8,747,628
|
)
|
|
(8,711,753
|
)
|
|
29,178
|
|
|
(34,045
|
)
|
Purchases of minerals in place
|
33,405,229
|
|
|
23,499,391
|
|
|
51,275
|
|
|
1,599,698
|
|
Sales of minerals in place
(4)
|
(4,866,078
|
)
|
|
(3,158,892
|
)
|
|
(68,350
|
)
|
|
(216,181
|
)
|
Production
|
(56,134,862
|
)
|
|
(45,745,137
|
)
|
|
(684,670
|
)
|
|
(1,048,063
|
)
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2017
|
1,024,421,384
|
|
|
842,735,076
|
|
|
7,159,695
|
|
|
23,121,356
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
(2)
:
|
|
|
|
|
|
|
|
December 31, 2015
|
338,005,854
|
|
|
238,355,707
|
|
|
10,108,833
|
|
|
6,499,524
|
|
December 31, 2016
|
378,233,832
|
|
|
312,125,091
|
|
|
4,512,842
|
|
|
6,505,282
|
|
December 31, 2017
|
458,252,677
|
|
|
377,504,768
|
|
|
5,026,398
|
|
|
8,431,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
December 31, 2015
|
83,632,206
|
|
|
73,332,691
|
|
|
—
|
|
|
1,716,587
|
|
December 31, 2016
|
365,507,610
|
|
|
314,663,510
|
|
|
1,264,849
|
|
|
7,209,167
|
|
December 31, 2017
|
566,168,707
|
|
|
465,230,305
|
|
|
2,133,297
|
|
|
14,689,769
|
|
(1) Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, reservoir pressure and commodity pricing. The net increase in reserves in 2016 was primarily due to additions of undeveloped reserves which were previously not included because of the uncertainties surrounding the availability of the financing that would be necessary to develop them, due in part to our bankruptcy filing. The downward revisions for 2017 were primarily attributable to well performance of Bracken lease wells in our AWP field.
(2) At
December 31, 2017, 2016 and 2015
,
45%
, 51% and 80% of our reserves were proved developed, respectively.
(3) We have added proved reserves through our drilling activities. The 2016 additions were primarily due to additions of undeveloped reserves which were previously not included because of the uncertainties surrounding the availability of the financing that would be necessary to develop them, due in part to our bankruptcy filing, partially offset by the sale of our Louisiana and other properties. The 2016 extensions were all in the Fasken Eagle Ford area. The 2017 additions were primarily due to additions from drilling results and leasing of adjacent acreage.
(4)
Includes the disposition of a portion of our AWP Olmos wells in South Texas in 2017 and Lake Washington, Masters Creek, Burr Ferry, South Bearhead Creek and Sun TSH fields in 2016. See Note 9 of the consolidated financial statements for more information.
Standardized Measure of Discounted Future Net Cash Flows.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2017
|
|
2016
|
|
2015
|
Future gross revenues
|
$
|
3,319,101
|
|
|
$
|
1,980,642
|
|
|
$
|
1,434,931
|
|
Future production costs
|
(1,027,860
|
)
|
|
(750,823
|
)
|
|
(688,427
|
)
|
Future development costs
(1)
|
(529,088
|
)
|
|
(365,064
|
)
|
|
(280,252
|
)
|
Future net cash flows before income taxes
|
1,762,153
|
|
|
864,755
|
|
|
466,252
|
|
Future income taxes
|
(237,396
|
)
|
|
(88,775
|
)
|
|
(297
|
)
|
Future net cash flows after income taxes
|
1,524,757
|
|
|
775,980
|
|
|
465,955
|
|
Discount at 10% per annum
|
(793,230
|
)
|
|
(368,987
|
)
|
|
(92,190
|
)
|
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
|
$
|
731,527
|
|
|
$
|
406,993
|
|
|
$
|
373,765
|
|
(1) These amounts include future costs related to asset retirement obligations for proved undeveloped oil and natural gas reserves.
The standardized measure of discounted future net cash flows from production of proved reserves as of December 31, 2017, 2016 and 2015, were developed as follows:
1. Estimates were made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
2. The estimated future gross revenues of proved reserves were based on the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
3. The future gross revenues were reduced by estimated future costs to develop and to produce the proved reserves, including asset retirement obligation costs, based on year-end cost estimates and the estimated effect of future income taxes.
4. Future income taxes were computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities and tax carry forwards.
The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.
The following are the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands) for the
years ended December 31, 2017, 2016 and 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
Beginning balance
|
$
|
406,993
|
|
|
$
|
373,765
|
|
|
$
|
1,651,674
|
|
|
|
|
|
|
|
Revisions to reserves proved in prior years:
|
|
|
|
|
|
Net changes in prices, net of production costs
|
204,445
|
|
|
(46,553
|
)
|
|
(2,018,065
|
)
|
Net changes in future development costs
|
35,735
|
|
|
(152,600
|
)
|
|
817,324
|
|
Net changes due to revisions in quantity estimates
|
(8,926
|
)
|
|
264,124
|
|
|
(599,342
|
)
|
Accretion of discount
|
44,193
|
|
|
33,327
|
|
|
194,326
|
|
Other
|
27,056
|
|
|
28,888
|
|
|
119,483
|
|
Total revisions
|
302,503
|
|
|
127,186
|
|
|
(1,486,274
|
)
|
|
|
|
|
|
|
New field discoveries and extensions, net of future production and development costs
|
121,117
|
|
|
75,034
|
|
|
3,025
|
|
Purchase of reserves
|
11,491
|
|
|
—
|
|
|
—
|
|
Sales of minerals in place
|
(1,953
|
)
|
|
(76,327
|
)
|
|
—
|
|
Sales of oil and gas produced, net of production costs
|
(146,471
|
)
|
|
(93,945
|
)
|
|
(137,251
|
)
|
Previously estimated development costs incurred
|
75,968
|
|
|
36,218
|
|
|
51,149
|
|
Net change in income taxes
|
(38,121
|
)
|
|
(34,938
|
)
|
|
291,442
|
|
Net change in standardized measure of discounted future net cash flows
|
324,534
|
|
|
33,228
|
|
|
(1,277,909
|
)
|
Ending balance
|
$
|
731,527
|
|
|
$
|
406,993
|
|
|
$
|
373,765
|
|
Selected Quarterly Financial Data (Unaudited).
The following table presents summarized quarterly financial information for the
year ended December 31, 2017
(successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through December 31, 2016 (successor) (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Sales
|
|
Net Income (Loss) Before Taxes
|
|
Net Income (Loss)
|
|
Basic EPS
|
|
Diluted EPS
|
2017 (Successor)
|
|
|
|
|
|
|
|
|
|
First
|
$
|
42,412
|
|
|
$
|
17,710
|
|
|
$
|
17,710
|
|
|
$
|
1.58
|
|
|
$
|
1.57
|
|
Second
|
45,785
|
|
|
16,241
|
|
|
16,241
|
|
|
1.41
|
|
|
1.41
|
|
Third
|
49,019
|
|
|
12,884
|
|
|
12,884
|
|
|
1.12
|
|
|
1.12
|
|
Fourth
|
58,694
|
|
|
23,182
|
|
|
25,136
|
|
|
2.17
|
|
|
2.17
|
|
Total
|
$
|
195,910
|
|
|
$
|
70,017
|
|
|
$
|
71,971
|
|
|
$
|
6.28
|
|
|
$
|
6.25
|
|
|
|
|
|
|
|
|
|
|
|
January 1 - April 22, 2016 (Predecessor)
|
|
|
|
|
|
|
|
|
|
First
(1)
|
$
|
34,367
|
|
|
$
|
(108,303
|
)
|
|
$
|
(108,303
|
)
|
|
$
|
(2.42
|
)
|
|
$
|
(2.42
|
)
|
April 1 - April 22, 2016
|
8,660
|
|
|
959,914
|
|
|
959,914
|
|
|
21.45
|
|
|
21.03
|
|
Total
|
$
|
43,027
|
|
|
$
|
851,611
|
|
|
$
|
851,611
|
|
|
$
|
19.06
|
|
|
$
|
18.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 23 - December 31, 2016 (Successor)
|
|
|
|
|
|
|
|
|
|
April 23 - June 30, 2016
(1)
|
$
|
30,581
|
|
|
$
|
(149,601
|
)
|
|
$
|
(149,601
|
)
|
|
$
|
(14.96
|
)
|
|
$
|
(14.96
|
)
|
Third
|
47,959
|
|
|
394
|
|
|
394
|
|
|
0.04
|
|
|
0.04
|
|
Fourth
|
42,846
|
|
|
(7,081
|
)
|
|
(7,081
|
)
|
|
(0.71
|
)
|
|
(0.71
|
)
|
Total
|
$
|
121,386
|
|
|
$
|
(156,288
|
)
|
|
$
|
(156,288
|
)
|
|
$
|
(15.61
|
)
|
|
$
|
(15.61
|
)
|
(1) Primarily due to pricing differences between the 12-month average oil and gas prices used in the Ceiling Test and the forward strip prices used to estimate the initial fair value of oil and gas properties on the Company’s April 22, 2016 (successor) balance sheet, we incurred a non-cash impairment write-down for the
period of April 23, 2016 through December 31, 2016 (successor)
of
$133.5 million
. The full amount of this write-down was incurred as of June 30, 2016. Write-downs in prior periods were primarily the result of declining historical prices along with timing changes and reduction of projects and changes in our reserves product mix. For the
period of January 1, 2016 through April 22, 2016 (predecessor)
we reported non-cash impairment write-downs on a before-tax basis of
$77.7 million
.
The sum of the individual quarterly net income (loss) per common share amounts may not agree with year-to-date net income (loss) per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income per common share amounts because to do so would have been antidilutive.