Notes to Consolidated Financial Statements
SilverBow Resources, Inc. and Subsidiaries
1. Summary of Significant Accounting Policies
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.
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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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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estimates in the assessment of current litigation claims against the Company; and
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estimates in amounts due with respect to open state regulatory audits.
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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
years ended December 31, 2018 and 2017
, such internal costs capitalized totaled
$4.5 million
and
$4.6 million
, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 4 of these consolidated financial statements for further discussion on capitalized interest costs).
The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
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December 31,
2018
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December 31,
2017
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Property and Equipment
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Proved oil and gas properties
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$
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925,865
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$
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658,519
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Unproved oil and gas properties
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56,715
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50,377
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Furniture, fixtures, and other equipment
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3,520
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3,270
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Less – Accumulated depreciation, depletion, amortization & impairment
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(284,804
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)
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(216,769
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)
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Property and Equipment, Net
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$
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701,296
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$
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495,397
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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 associated with 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
years ended December 31, 2018 and 2017
.
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 possible 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; therefore we cannot estimate the amount 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
. The Company adopted the new revenue recognition standard for revenue from contracts from customers (ASC 606) effective January 1, 2018. See Note 8 in these notes to consolidated financial statements for further details.
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 both
December 31, 2018 and 2017
, 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, 2018
, our “Accounts receivable” balance included
$36.9 million
for oil and gas sales,
$5.6 million
for joint interest owners,
$2.4 million
for severance tax credit receivables and
$1.6 million
for other receivables. 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.
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. The amount of supervision fees charged for the
years ended December 31, 2018 and 2017
did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was
$4.6 million
and
$4.7 million
for the
years ended December 31, 2018 and 2017
, 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, 2018
, 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 was in a net deferred tax asset position as of
December 31, 2018
for United States federal income taxes. Management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining federal carryover items, and accordingly, has taken a full valuation allowance to offset its tax assets. Tax expense associated with federal income taxes was fully offset by adjustments to the valuation allowance.
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 made 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 regime, both effective January 1, 2018. Because of the Company's net deferred tax asset and valuation allowance positions, these changes had minimal impact on income tax expense. See Note 3 for more information.
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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December 31,
2018
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December 31,
2017
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Trade accounts payable
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$
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32,683
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$
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20,884
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Accrued operating expenses
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3,549
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3,490
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Accrued compensation costs
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4,785
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5,334
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Asset retirement obligations – current portion
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302
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2,109
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Accrued non-income based taxes
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3,583
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3,898
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Accrued corporate and legal fees
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534
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2,784
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Other payables
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3,485
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5,938
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Total Accounts payable and accrued liabilities
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$
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48,921
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$
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44,437
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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.
Long-term Restricted Cash.
Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of
December 31, 2018
, there was
no
long-term restricted cash held, while at
December 31, 2017
, there was
$0.2 million
. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying consolidated balance sheets.
The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying consolidated statement of cash flows and their corresponding balance sheet presentation (in thousands):
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December 31, 2018
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December 31, 2017
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Cash and cash equivalents
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$
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2,465
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$
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7,806
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Long-term restricted cash (1)
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—
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220
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Total cash, cash equivalents and restricted cash
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$
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2,465
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$
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8,026
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(1) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.
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
years ended December 31, 2018 and 2017
, parties that accounted for
10%
or more of our total oil and gas receipts were as follows:
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Customers greater than 10%
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Year Ended December 31, 2018
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Year Ended December 31, 2017
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Kinder Morgan
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37
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%
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48
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%
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Treasury Stock.
Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the
years ended December 31, 2018 and 2017
, respectively,
15,107
and
28,279
treasury shares were purchased to satisfy withholding tax obligations arising upon the vesting of restricted shares.
New Accounting Pronouncements
.
In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“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. The Company adopted this standard on January 1, 2019 using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has also made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet.
As a result of adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities will be less than
$3.0 million
, attributable to operating leases. The balances could increase during the year if the Company enters into new lease agreements. Adoption of this guidance will not result in a cumulative adjustment to retained earnings.
2. Earnings Per Share
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, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the
years ended December 31, 2018 and 2017
, and are discussed below.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):
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Year Ended December 31, 2018
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|
Year Ended December 31, 2017
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Net Income (Loss)
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Shares
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|
Per Share
Amount
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|
Net Income (Loss)
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Shares
|
|
Per Share
Amount
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Basic EPS:
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Net Income (Loss) and Share Amounts
|
$
|
74,615
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|
11,655
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|
$
|
6.40
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|
$
|
71,971
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|
|
11,453
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|
$
|
6.28
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|
Dilutive Securities:
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Restricted Stock Unit Awards
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|
94
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|
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6
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|
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|
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Stock Option Awards
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|
15
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55
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Diluted EPS:
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Net Income (Loss) and Assumed Share Conversions
|
$
|
74,615
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|
11,764
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|
$
|
6.34
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|
$
|
71,971
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|
11,514
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|
$
|
6.25
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|
Approximately
0.6 million
and
0.3 million
stock options to purchase shares were not included in the computation of Diluted EPS for the
years ended December 31, 2018 and 2017
respectively, because these stock options were antidilutive.
Less than
0.1 million
and
0.1 million
shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for the
years ended December 31, 2018 and 2017
, respectively, because they were antidilutive.
Less than
0.1 million
performance-based restricted stock units were not included in the computation of Diluted EPS for the
year ended December 31, 2018
because they were antidilutive.
Approximately
4.3 million
warrants to purchase common stock were not included in the computation of Diluted EPS for the
years ended December 31, 2018 and 2017
, respectively, because these warrants were antidilutive.
3. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
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Year Ended December 31, 2018
|
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Year Ended December 31, 2017
|
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Income (Loss) Before Income Taxes
|
$
|
75,543
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|
|
$
|
70,017
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|
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
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Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Current
|
$
|
(86
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)
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|
$
|
(1,954
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)
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Deferred
|
1,014
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|
—
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|
Total
|
$
|
928
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|
|
$
|
(1,954
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)
|
Reconciliations of income taxes computed using the U.S. Federal statutory rates of (
21%
) and (
35%
) to the effective income tax rates are as follows (in thousands):
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Year Ended December 31, 2018
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|
Year Ended December 31, 2017
|
|
Federal Statutory Rate
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21.0
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%
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|
35.0
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%
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State tax provisions (benefits), net of federal benefits
|
1.2
|
%
|
|
1.6
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%
|
|
Expiration/Write-off of NOL Carryovers
|
—
|
%
|
|
13.9
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%
|
|
Change in Enacted Tax Rates
|
—
|
%
|
|
55.6
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%
|
|
Executive Compensation Limitation
|
0.3
|
%
|
|
0.6
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%
|
|
Other, net
|
0.2
|
%
|
|
2.3
|
%
|
|
Valuation allowance adjustments
|
(21.4
|
)%
|
|
(111.8
|
)%
|
|
Effective rate
|
1.2
|
%
|
|
(2.8
|
)%
|
The tax effects of temporary differences representing the net deferred tax asset (liability) at
December 31, 2018 and 2017
were as follows (in thousands):
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|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Deferred tax assets:
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|
Federal net operating loss (“NOL”) carryovers
|
$
|
71,736
|
|
|
$
|
58,438
|
|
|
Alternative minimum tax credits
|
—
|
|
|
138
|
|
|
Other Carryover Items
|
583
|
|
|
619
|
|
|
Asset Retirement Obligations
|
920
|
|
|
2,329
|
|
|
Derivative Contracts
|
—
|
|
|
29
|
|
|
Share-based compensation
|
906
|
|
|
872
|
|
|
Other
|
956
|
|
|
2,190
|
|
|
Valuation allowance
|
(42,335
|
)
|
|
(58,398
|
)
|
|
Total deferred tax assets
|
$
|
32,766
|
|
|
$
|
6,217
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
Oil and gas exploration and development costs
|
$
|
(30,935
|
)
|
|
$
|
(6,054
|
)
|
|
Derivative Contracts
|
(2,817
|
)
|
|
—
|
|
|
Other
|
(28
|
)
|
|
(163
|
)
|
|
Total deferred tax liabilities
|
(33,780
|
)
|
|
(6,217
|
)
|
|
|
|
|
|
|
Net deferred tax liabilities
|
$
|
(1,014
|
)
|
|
$
|
—
|
|
The Company was in a net deferred tax asset position at
December 31, 2018
and
2017
for United States federal income tax purposes. 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
$42 million
and
$58 million
at
December 31, 2018
and
2017
, respectively. The Company recorded a net deferred tax liability for state income tax purposes at
December 31, 2018
.
The Company’s NOL carryforward asset is attributable to Federal tax losses of
$115 million
generated from 2013 through 2015,
$160 million
generated in 2017, and a
$67 million
tax loss for 2018. The losses generated between 2013 and 2015 are subject to an annual utilization limit under Sec. 382. These losses will expire between 2033 and 2035 if not utilized in earlier periods. The 2017 loss will expire in 2037 if not utilized. The 2018 loss will not expire under the current tax code, but its usage will be limited to
80%
of taxable income.
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 Company completed its review of previously recorded provisional income tax amounts related to its deferred tax assets impacted by the Act, and concluded that additional information, interpretation and guidance that became available during the twelve-month measurement period did not alter the Company’s application of tax law in remeasuring gross deferred tax assets and related valuation allowances. There were no material adjustments deemed necessary in the period ended December 31, 2018 and the Company’s accounting for the Act is now final.
As of
December 31, 2018
, the Company does 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 the taxing authorities.
4. Long-Term Debt
As of
December 31, 2018
and
December 31, 2017
, the Company's long-term debt consisted of the following (in thousands):
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|
December 31, 2018
|
|
December 31, 2017
|
|
Credit Facility Borrowings
(1)
|
$
|
195,000
|
|
|
$
|
73,000
|
|
|
Second Lien Notes due 2024
|
200,000
|
|
|
200,000
|
|
|
|
395,000
|
|
|
273,000
|
|
|
Unamortized discount on Second Lien Notes due 2024
|
(1,782
|
)
|
|
(1,992
|
)
|
|
Unamortized debt issuance cost on Second Lien Notes due 2024
|
(5,230
|
)
|
|
(5,683
|
)
|
|
Total Long-Term Debt
|
$
|
387,988
|
|
|
$
|
265,325
|
|
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in
“
Other Long-Term Assets
”
in our consolidated balance sheet. As of
December 31, 2018
and
2017
, we had
$4.5 million
and
$5.5 million
, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility.
Amounts outstanding under our Credit Facility (defined below) were
$195.0 million
and
$73.0 million
as of
December 31, 2018
and
2017
, respectively. On April 19, 2017 the Company entered into a First Amended and Restated Senior Secured Revolving Credit Agreement among the Company as borrower, JPMorgan Chase Bank, National Association as administrative agent, and certain lenders party thereto, as amended from time to time, including pursuant to the Fourth Amendment to the First Amended and Restated Senior Secured Credit Agreement (the “Fourth Amendment to Credit Agreement”) effective November 6, 2018 (as so amended, the “Credit Agreement” and such facility, the “Credit Facility”). The Fourth Amendment to Credit Agreement, among other things, increased the borrowing base from
$330 million
to
$410 million
and decreased the applicable margins used to calculate the interest rate under the Credit Agreement by
25
basis points.
The Credit Facility matures April 19, 2022 and provides for a maximum credit amount of
$600 million
and a current borrowing base of
$410 million
. The borrowing base is regularly redetermined on or about 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 in accordance 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. There were no letters of credit outstanding as of
December 31, 2018
.
Interest under the Credit Facility accrues at the Company’s option either at the Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). As of November 6, 2018, the applicable margin ranged from
1.00%
to
2.00%
for ABR Loans and
2.00%
to
3.00%
for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate 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, 2018
, the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replace produced reserves
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.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was
$8.0 million
and
$14.9 million
for the
years ended December 31, 2018 and 2017
, respectively. Additionally, interest expense for the
year ended December 31, 2017
included a write-down of debt issuance costs of
$2.7 million
. The amount of commitment fee amortization included in interest expense, net was
$1.1 million
and
$0.4 million
for the
years ended December 31, 2018 and 2017
, respectively.
We capitalized interest on our unproved properties in the amount
$0.9 million
and
$0.8 million
for the
years ended December 31, 2018 and 2017
, respectively.
Senior Secured Second Lien Notes
. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement”, and such second lien facility 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 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 on 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 under 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, 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 Second Lien being prepaid; during
year four,
1.0%
of the principal amount of the Second Lien 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 believes 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 issuance of 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 Second Lien Note 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. As of
December 31, 2018
, the Company was in compliance with all financial covenants under the Second Lien.
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 to be immediately due and payable.
As of
December 31, 2018
, net amounts recorded for the Second Lien Notes were
$193.0 million
, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled
$20.5 million
and
$0.8 million
for the
years ended December 31, 2018 and 2017
, respectively.
Debt Issuance Costs
. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and Second Lien and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.
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 and natural gas prices, mainly through the purchase of commodity price swaps and collars, as well as basis swaps.
For the
years ended December 31, 2018 and 2017
, the Company recognized a
$9.8 million
loss
and a
$17.9 million
gain
, respectively, relating to our derivative activities. The Company made net cash payments of
$19.7 million
and
$1.4 million
for settled derivative contracts for the
years ended December 31, 2018 and 2017
.
As of
December 31, 2018 and 2017
the Company had
$0.7 million
and
$2.2 million
in receivables for settled derivatives which were recognized on the accompanying consolidated balance sheet in “Accounts receivable” and were subsequently collected in January
2019
and
2018
, respectively. As of
December 31, 2018 and 2017
, the Company had
$2.2 million
and
$0.4 million
, respectively, 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
2019
and
2018
, respectively.
The fair values of our swap contracts are computed using observable market data while our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. As of December 31,
2018
and
2017
, there was
$15.3 million
and
$5.1 million
, respectively, in current unsettled derivative assets, and
$4.3 million
and
$2.6 million
,
respectively, in long-term unsettled derivative assets. Additionally, as of December 31,
2018
and
2017
, the Company had
$2.8 million
and
$5.1 million
, respectively, in current unsettled derivative liabilities, and
$3.7 million
and
$2.8 million
, respectively, in long-term unsettled derivative liabilities.
The Company uses an International Swap and Derivatives Association master agreement for its 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 has elected to 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
$13.0 million
net fair value
asset
and
$0.1 million
net fair value
liability
at
December 31, 2018
and
December 31, 2017
, 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 summarize the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of
December 31, 2018
.
|
|
|
|
|
|
|
|
|
|
|
Oil Derivative Swaps
(NYMEX WTI Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|
2019 Contracts
|
|
|
|
|
1Q19
|
124,200
|
|
|
$
|
54.95
|
|
|
2Q19
|
134,700
|
|
|
$
|
57.08
|
|
|
3Q19
|
130,500
|
|
|
$
|
57.27
|
|
|
4Q19
|
126,500
|
|
|
$
|
57.37
|
|
|
|
|
|
|
|
2020 Contracts
|
|
|
|
|
1Q20
|
103,800
|
|
|
$
|
56.28
|
|
|
2Q20
|
100,350
|
|
|
$
|
56.38
|
|
|
3Q20
|
97,200
|
|
|
$
|
56.49
|
|
|
4Q20
|
72,000
|
|
|
$
|
52.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements)
|
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|
Weighted Average Collar Floor Price
|
|
Weighted Average Collar Call Price
|
|
2019 Contracts
|
|
|
|
|
|
|
|
|
1Q19
|
5,693,000
|
|
|
$
|
3.11
|
|
|
|
|
|
|
2Q19
|
12,130,000
|
|
|
$
|
2.80
|
|
|
|
|
|
|
3Q19
|
11,990,000
|
|
|
$
|
2.80
|
|
|
|
|
|
|
4Q19
|
9,646,000
|
|
|
$
|
2.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020 Contracts
|
|
|
|
|
|
|
|
|
1Q20
|
5,370,000
|
|
|
$
|
2.83
|
|
|
|
|
|
|
2Q20
|
3,688,000
|
|
|
$
|
2.76
|
|
|
|
|
|
|
3Q20
|
3,585,000
|
|
|
$
|
2.76
|
|
|
|
|
|
|
4Q20
|
3,362,000
|
|
|
$
|
2.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
1Q19
|
3,337,500
|
|
|
|
|
$
|
3.34
|
|
|
$
|
3.82
|
|
|
2Q19
|
300,000
|
|
|
|
|
$
|
2.90
|
|
|
$
|
3.15
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Derivative Swaps
(OPIS Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|
2019 Contracts
|
|
|
|
|
1Q19
|
180,000
|
|
|
$
|
27.93
|
|
|
2Q19
|
180,000
|
|
|
$
|
27.93
|
|
|
3Q19
|
180,000
|
|
|
$
|
27.93
|
|
|
4Q19
|
180,000
|
|
|
$
|
27.93
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs NYMEX Settlements)
|
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|
2019 Contracts
|
|
|
|
|
1Q19
|
9,047,500
|
|
|
$
|
(0.05
|
)
|
|
2Q19
|
14,477,500
|
|
|
$
|
0.05
|
|
|
3Q19
|
14,625,000
|
|
|
$
|
0.04
|
|
|
4Q19
|
14,625,000
|
|
|
$
|
(0.02
|
)
|
|
|
|
|
|
|
2020 Contracts
|
|
|
|
|
1Q20
|
11,739,000
|
|
|
$
|
(0.03
|
)
|
|
2Q20
|
11,739,000
|
|
|
$
|
(0.04
|
)
|
|
3Q20
|
11,868,000
|
|
|
$
|
(0.03
|
)
|
|
4Q20
|
11,868,000
|
|
|
$
|
(0.04
|
)
|
|
|
|
|
|
|
2021 Contracts
|
|
|
|
|
1Q21
|
5,400,000
|
|
|
$
|
(0.004
|
)
|
|
2Q21
|
5,460,000
|
|
|
$
|
(0.004
|
)
|
|
3Q21
|
5,520,000
|
|
|
$
|
(0.004
|
)
|
|
4Q21
|
5,520,000
|
|
|
$
|
(0.004
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Oil Basis Derivative Swaps
(Argus Cushing (WTI) and LLS Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|
2019 Contracts
|
|
|
|
|
1Q19
|
30,000
|
|
|
$
|
4.65
|
|
|
2Q19
|
45,000
|
|
|
$
|
4.65
|
|
|
3Q19
|
45,000
|
|
|
$
|
4.65
|
|
|
4Q19
|
45,000
|
|
|
$
|
4.65
|
|
6. Commitments and Contingencies
Rental and lease expense was
$4.4 million
and
$4.2 million
for the
years ended December 31, 2018 and 2017
, 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
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, 2018
, the minimum contractual obligations were approximately
$1.5 million
in the aggregate.
Our minimum annual obligations under non-cancelable operating lease commitments are
$2.3 million
for
2019
,
$0.8 million
for
2020
,
$0.3 million
for
2021
and approximately
$3.5 million
in the aggregate.
We have gas transportation and processing minimum obligations amounting to
$8.3 million
for
2019
,
$12.6 million
for
2020
,
$5.6 million
for
2021
,
$4.0 million
for
2022
,
$2.8 million
for
2023
and
$35.9 million
in the aggregate.
Additionally we have drilling commitments amounting to
$2.2 million
for
2019
and executive severance agreements amounting to
$0.6 million
for
2019
.
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
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, 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.
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
years ended December 31, 2018 and 2017
,
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.
The expense for awards issued under the Plans to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying consolidated statements of operations was
$6.0 million
and
$6.8 million
for the
years ended December 31, 2018 and 2017
, respectively.
We capitalized in property and equipment
$0.5 million
and
$0.2 million
of share-based compensation for the
years ended December 31, 2018 and 2017
, 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.
Our shares available for future grant under the Plans were
253,293
at
December 31, 2018
.
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, 2018
:
|
|
|
|
|
|
|
|
|
Stock Option Valuation Assumptions
|
|
Expected dividend
|
—
|
|
|
Expected volatility
|
66.55
|
%
|
|
Risk-free interest rate
|
2.83
|
%
|
|
Expected life of stock option awards (in years)
|
6.0
|
|
|
Grant-date exercise price
|
$
|
31.14
|
|
|
Grant-date fair value
|
$
|
19.30
|
|
At
December 31, 2018
, we had
$6.4 million
in unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the
year ended December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Wtd. Avg.
Exer. Price
|
|
Options outstanding, beginning of period
|
508,730
|
|
|
$
|
26.82
|
|
|
Options granted
|
201,406
|
|
|
$
|
31.14
|
|
|
Options forfeited
|
(24,365
|
)
|
|
$
|
26.96
|
|
|
Options canceled
|
(11,997
|
)
|
|
$
|
26.96
|
|
|
Options exercised
|
(29,199
|
)
|
|
$
|
24.27
|
|
|
Options outstanding, end of period
|
644,575
|
|
|
$
|
28.28
|
|
|
Options exercisable, end of period
|
159,127
|
|
|
$
|
26.84
|
|
Our outstanding stock option awards at
December 31, 2018
had
$0.1 million
in aggregate intrinsic value. At
December 31, 2018
the weighted average remaining contract life of stock option awards outstanding was
7.2
years and exercisable was
3.1
years. The total intrinsic value of stock option awards exercisable as of
December 31, 2018
was less than
$0.1 million
.
Restricted Stock Units
The Plans allow 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, 2018
, we had unrecognized compensation expense of
$6.2 million
related to our restricted stock units which is expected to be recognized over a weighted-average period of
2.3
years.
The following table represents restricted stock unit activity for the
year ended December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Wtd. Avg.
Grant Price
|
|
Restricted units outstanding, beginning of period
|
346,740
|
|
|
$
|
26.99
|
|
|
Restricted stock units granted
|
126,728
|
|
|
$
|
28.63
|
|
|
Restricted stock units forfeited
|
(26,100
|
)
|
|
$
|
26.53
|
|
|
Restricted stock units vested
|
(106,690
|
)
|
|
$
|
26.99
|
|
|
Restricted stock units outstanding, end of period
|
340,678
|
|
|
$
|
27.64
|
|
Performance Share Units
On February 20, 2018, the Company granted
30,700
performance share units for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers ("Peer Group") during the performance period from January 1, 2018 to December 31, 2020 ("Performance Period"). The awards contain market conditions which allow a payout ranging between
0%
payout and
200%
of the target payout. The fair value as of the date of valuation was
$41.66
per unit or
150.61%
as a percentage of stock price with a remaining performance period of
2.1
years. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of
three
years.
As of
December 31, 2018
, we had unrecognized compensation expense of
$0.9 million
related to our performance share units. Expense is calculated based on the assumption of a target payout of
100.0%
.
No
shares vested during the
year ended December 31, 2018
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
2018
and
2017
. The Company's
2018
plan contributions of
$0.6 million
were paid in cash during each pay period. The Company's
2017
plan contributions of
$0.5 million
were paid in cash during the first quarter of 2018. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.
8. Revenue Recognition
Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605. The new standard includes a five-step revenue recognition model to follow to determine the timing and amounts to be recognized as revenues in an entity’s financial statements. Adoption of this standard did not result in a different amount reported for oil and gas sales than what we would have reported under the previous standard. Accordingly, there was no cumulative effect adjustment required upon adoption.
Virtually all of our revenue reported as oil and gas sales in our consolidated statements of operations is derived from contracts. No other material revenue sources are attributable to Revenue from Contracts within the scope of ASC 606.
Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. The types of contracts vary between product streams as described below:
Sales Contracts for Unprocessed Gas
We deliver natural gas to midstream entities at field delivery meter stations, under either transportation or processing agreements. For unprocessed gas (delivered under transportation or gathering agreements), we retain title to the gas through the redelivery points into downstream pipelines. The purchasers take control at these redelivery points. Sales proceeds are determined using the gas delivered for each monthly period based on an agreed upon index. We record the monthly proceeds realized at the redelivery points as gas sales revenue, and record the fees paid to the mid-stream pipeline as transportation expense.
Contracts for Processed Gas and NGLs
NGLs are unique in that they remain in a gas state through normal field operations, and are typically part of the gas stream delivered to a gas processor. A gas processing facility is necessary to separate the NGLs from the gas. The most common NGL components are ethane, propane, butane, isobutane and pentane. Each of these NGL components has unique industrial and/or residential markets. Prices, which are typically quoted on a per gallon basis, can vary substantially between these products.
Where our raw gas contains commercially recoverable NGL components, we enter into agreements with midstream gas processors under which the processor takes control at meter stations in the field and transports the gas to its processing facility. The processing facility extracts the recoverable NGLs and the remaining natural gas (“residue gas”) is delivered to a downstream pipeline, while the processor typically takes control of and purchases the NGLs at the plant tailgate.
We either take control of (take in kind) the residue gas at the plant tailgate and sell it to third party purchasers, or we sell the residue gas to the processor. Sales to third parties are negotiated on a monthly, seasonal or term basis and are priced at applicable market indexes. When we sell to the processor, the sales price is determined using monthly index prices.
When we sell the NGLs to the processor, each NGL component has a separate index price. The processor’s statement segregates the individual component quantities and lists separate settlement amounts for each NGL component. The processor charges service or processing fees that are fixed in the processing agreement. We aggregate the revenue for all components and record NGL revenues as a single product.
Based on an analysis of the terms of our existing contracts, we determined that under substantially all of our processing agreements, we retain control of both the gas and NGLs through the processing facilities. As a result, the processor is both a service provider and a customer of the NGLs (and residue gas not sold to other parties) with the sales occurring at the plant outlet. Accordingly, we record gas and NGL sales at the value realized at the plant tailgate and record the processor’s fees as transportation and processing expense.
Contracts for
Oil sales
Under our oil sales contracts, we sell oil production at field delivery points at agreed-upon index pricing, adjusted for location differentials and product quality. Oil is priced on a per barrel basis. Oil is picked up by our purchasers’ trucks at our tank batteries. Control transfers when it is loaded on the purchasers’ trucks. We record oil revenue at the price received at the pick-up points.
Contract balances
Under our contracts we either invoice our customers on a monthly basis or receive monthly settlement statements from the purchasers. Invoices and settlement statements cover the products delivered during the calendar month. The performance obligation is deemed fully satisfied for each unit of product at the time control is transferred to the purchaser. Payment of each monthly settlement is unconditional. Accordingly, our product sales contracts do not give rise to any contract assets or liabilities connected to future performance obligations under ASC 606. Receivables for oil and gas sales are included in Accounts Receivable, net in the consolidated balance sheets.
Settlements for performance obligations
We record revenue for the production delivered to the purchasers during each monthly accounting period. Settlements typically occur 30 - 60 days after the end of the delivery month. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Adjustments to prior period estimates were not material for the periods presented in our consolidated statements of operations.
Transaction price allocated to remaining performance obligations
Our contract terms vary, with many being greater than one-year. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Product prices under our long-term contracts (with delivery obligations greater than one month) are tied to indexes reflective of market value at the time of delivery.
Production imbalances
Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer available under ASC 606. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. We do not have any material imbalances, so this change had no impact on our reported revenues.
Oil and Gas sales by product
The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the
years ended December 31, 2018 and 2017
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Oil, natural gas and NGLs sales:
|
|
|
|
|
|
Oil
|
|
$
|
45,375
|
|
|
$
|
34,903
|
|
|
Natural gas
|
|
183,272
|
|
|
138,404
|
|
|
NGLs
|
|
28,639
|
|
|
22,602
|
|
|
Total
|
|
$
|
257,286
|
|
|
$
|
195,910
|
|
9. Acquisitions and Dispositions
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 and recorded a
$16.3 million
obligation related to the funding of certain plugging and abandonment costs. Of the
$16.3 million
original obligation,
$8.7 million
was paid during the
year ended December 31, 2018
. The remaining obligation under this contract is
$7.5 million
and is carried in the accompanying consolidated balance sheet as a current liability in “Accounts payable and accrued liabilities” as of
December 31, 2018
.
On March 1, 2018, the Company closed the sale of certain wells in its AWP Olmos field for proceeds, net of selling expenses, of
$27.0 million
, with an effective date of January 1, 2018. The buyer assumed approximately
$6.3 million
in asset retirement obligations. No gain or loss was recorded on the sale of this property.
10. Fair Value Measurements
Fair Value on a Recurring Basis
. Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, the Credit Facility, and the Second Lien. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The carrying value of our Credit Facility and the Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (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, 2018
and
2017
. 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, 2018
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
$
|
7.5
|
|
|
$
|
—
|
|
|
$
|
7.5
|
|
|
$
|
—
|
|
|
Natural Gas Basis Derivatives
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
|
Oil Derivatives
|
$
|
6.9
|
|
|
$
|
—
|
|
|
$
|
6.9
|
|
|
$
|
—
|
|
|
NGL Derivatives
|
$
|
4.7
|
|
|
$
|
—
|
|
|
$
|
4.7
|
|
|
$
|
—
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
$
|
1.0
|
|
|
$
|
—
|
|
|
$
|
1.0
|
|
|
$
|
—
|
|
|
Natural Gas Basis Derivatives
|
$
|
5.3
|
|
|
$
|
—
|
|
|
$
|
5.3
|
|
|
$
|
—
|
|
|
NGL Derivatives
|
$
|
0.2
|
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
—
|
|
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 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 amortized on a unit-of-production basis as part of depreciation, depletion, and amortization 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 included in the “Property and Equipment” balance on our accompanying consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.
The following provides a roll-forward of our asset retirement obligations (in thousands):
|
|
|
|
|
|
|
|
Asset Retirement Obligations as of December 31, 2016
|
$
|
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
|
$
|
10,787
|
|
|
Accretion expense
|
419
|
|
|
Liabilities incurred for new wells and facilities construction
|
93
|
|
|
Reductions due to sold wells and facilities
|
(6,298
|
)
|
|
Reductions due to plugged wells and facilities
|
(180
|
)
|
|
Revisions in estimates
|
(562
|
)
|
|
Asset Retirement Obligations as of December 31, 2018
|
$
|
4,259
|
|
At
December 31, 2018 and 2017
, approximately
$0.3 million
and
$2.1 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 2018 reductions due to sold wells and facilities are primarily attributable to the disposition of our assets from our AWP Olmos field while the 2017 reductions due to sold wells and facilities are primarily attributable to the disposition of our assets from our Bay De Chene field.
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, 2018
|
|
|
Proved oil and gas properties
|
$
|
925,865
|
|
|
Unproved oil and gas properties
|
56,715
|
|
|
|
982,580
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(282,663
|
)
|
|
Net capitalized costs
|
$
|
699,917
|
|
|
|
|
|
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
|
|
There were
$56.7 million
and
$50.4 million
of unproved property costs at
December 31, 2018
and
2017
, 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, 2018 and 2017
.
Costs Incurred.
The following table sets forth costs incurred related to our oil and natural gas operations (in thousands) for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2017
|
|
Lease acquisitions and prospect costs
|
$
|
22,681
|
|
|
$
|
44,569
|
|
|
Exploration
|
—
|
|
|
—
|
|
|
Development
(1) (3)
|
284,525
|
|
|
149,293
|
|
|
Acquisition of property
|
1,096
|
|
|
9,426
|
|
|
Total acquisition, exploration, and development
(2)
|
$
|
308,302
|
|
|
$
|
203,288
|
|
(1) Facility construction costs and capital costs have been included in development costs, and totaled $16.4 million and $11.6 million for the
years ended December 31, 2018 and 2017
, respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately
$4.5 million
and
$4.6 million
for the
years ended December 31, 2018 and 2017
, respectively. In addition, the total includes
$0.9 million
and
$0.8 million
for the
years ended December 31, 2018 and 2017
, respectively, of capitalized interest on unproved properties.
(3) Includes asset retirement obligations incurred, including revisions, of approximately $0.6 million and $2.3 million for the
years ended December 31, 2018 and 2017
respectively. Does not include accrued payments associated with our Bay De Chene sale for the
year ended December 31, 2018
.
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 Gruy as of the
years ended December 31, 2018, 2017 and 2016
. Proved reserves, as of
December 31, 2018, 2017 and 2016
, 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
2018
average adjusted prices after differentials used in our calculations were
$3.04
per Mcf of natural gas,
$66.96
per barrel of oil, and
$26.63
per barrel of NGL compared to
$2.95
per Mcf of natural gas,
$50.38
per barrel of oil, and
$20.32
per barrel of NGL for the 12-month average
2017
prices and
$2.43
per Mcf of natural gas,
$41.07
per barrel of oil, and
$16.13
per barrel of NGL for
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimates of Proved Reserves
|
Total
|
|
Natural Gas
|
|
Oil
|
|
NGL
|
|
|
(Mcfe)
|
|
(Mcf)
|
|
(Bbls)
|
|
(Bbls)
|
|
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
|
)
|
|
(8,705,712
|
)
|
|
29,178
|
|
|
(36,164
|
)
|
|
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
|
)
|
|
(45,751,178
|
)
|
|
(684,670
|
)
|
|
(1,045,944
|
)
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2017
|
1,024,421,384
|
|
|
842,735,076
|
|
|
7,159,695
|
|
|
23,121,356
|
|
|
Extensions, discoveries, and other additions
(3)
|
450,353,613
|
|
|
357,778,652
|
|
|
6,690,818
|
|
|
8,738,342
|
|
|
Revisions of previous estimates
(1)
|
(34,442,827
|
)
|
|
(31,025,348
|
)
|
|
149,332
|
|
|
(718,912
|
)
|
|
Purchases of minerals in place
|
427,200
|
|
|
427,200
|
|
|
—
|
|
|
—
|
|
|
Sales of minerals in place
(4)
|
(27,866,979
|
)
|
|
(16,842,753
|
)
|
|
(532,809
|
)
|
|
(1,304,562
|
)
|
|
Production
|
(67,530,138
|
)
|
|
(56,665,272
|
)
|
|
(688,221
|
)
|
|
(1,122,590
|
)
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2018
|
1,345,362,253
|
|
|
1,096,407,555
|
|
|
12,778,815
|
|
|
28,713,634
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
(2)
:
|
|
|
|
|
|
|
|
|
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
|
|
|
December 31, 2018
|
554,896,291
|
|
|
466,128,862
|
|
|
5,507,442
|
|
|
9,287,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
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
|
|
|
December 31, 2018
|
790,465,963
|
|
|
630,278,693
|
|
|
7,271,373
|
|
|
19,426,505
|
|
(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 downward revisions for 2017 were primarily attributable to well performance of Bracken lease wells in our AWP field. The downward revisions for 2018 were primarily attributable to removing Bracken proved undeveloped locations out of the Company's five year plan.
(2) At
December 31, 2018, 2017 and 2016
,
41%
, 45% and 51% of our reserves were proved developed, respectively.
(3) We have added proved reserves through our drilling activities. The 2018 and 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 additional AWP Olmos wells in South Texas in 2018. 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,
|
|
|
2018
|
|
2017
|
|
Future gross revenues
|
$
|
4,950,917
|
|
|
$
|
3,319,101
|
|
|
Future production costs
|
(1,366,404
|
)
|
|
(1,027,860
|
)
|
|
Future development costs
(1)
|
(866,436
|
)
|
|
(529,088
|
)
|
|
Future net cash flows before income taxes
|
2,718,077
|
|
|
1,762,153
|
|
|
Future income taxes
|
(431,513
|
)
|
|
(237,396
|
)
|
|
Future net cash flows after income taxes
|
2,286,564
|
|
|
1,524,757
|
|
|
Discount at 10% per annum
|
(1,292,835
|
)
|
|
(793,230
|
)
|
|
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
|
$
|
993,729
|
|
|
$
|
731,527
|
|
(1) These amounts include future costs related to plugging and abandoning the Company's wells.
The standardized measure of discounted future net cash flows from production of proved reserves as of
December 31, 2018, 2017 and 2016
, 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, 2018, 2017 and 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
Beginning balance
|
$
|
731,527
|
|
|
$
|
406,993
|
|
|
|
|
|
|
|
Revisions to reserves proved in prior years:
|
|
|
|
|
Net changes in prices, net of production costs
|
182,718
|
|
|
204,445
|
|
|
Net changes in future development costs
|
(4,264
|
)
|
|
35,735
|
|
|
Net changes due to revisions in quantity estimates
|
(38,067
|
)
|
|
(8,926
|
)
|
|
Accretion of discount
|
106,129
|
|
|
44,193
|
|
|
Other
|
80,573
|
|
|
27,056
|
|
|
Total revisions
|
327,089
|
|
|
302,503
|
|
|
|
|
|
|
|
New field discoveries and extensions, net of future production and development costs
|
182,030
|
|
|
121,117
|
|
|
Purchase of reserves
|
472
|
|
|
11,491
|
|
|
Sales of minerals in place
|
(39,598
|
)
|
|
(1,953
|
)
|
|
Sales of oil and gas produced, net of production costs
|
(204,403
|
)
|
|
(146,471
|
)
|
|
Previously estimated development costs incurred
|
57,332
|
|
|
75,968
|
|
|
Net change in income taxes
|
(60,720
|
)
|
|
(38,121
|
)
|
|
Net change in standardized measure of discounted future net cash flows
|
262,202
|
|
|
324,534
|
|
|
Ending balance
|
$
|
993,729
|
|
|
$
|
731,527
|
|
Selected Quarterly Financial Data (Unaudited).
The following table presents summarized quarterly financial information for the
years ended December 31, 2018 and 2017
(in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Sales
|
|
Net Income (Loss) Before Taxes
|
|
Net Income (Loss)
|
|
Basic EPS
|
|
Diluted EPS
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
First
|
52,752
|
|
|
8,466
|
|
|
8,466
|
|
|
$
|
0.73
|
|
|
$
|
0.72
|
|
|
Second
|
51,347
|
|
|
2,647
|
|
|
2,319
|
|
|
0.20
|
|
|
0.20
|
|
|
Third
|
65,034
|
|
|
7,300
|
|
|
7,080
|
|
|
0.61
|
|
|
0.60
|
|
|
Fourth
|
88,153
|
|
|
57,130
|
|
|
56,750
|
|
|
4.85
|
|
|
4.82
|
|
|
Total
|
$
|
257,286
|
|
|
$
|
75,543
|
|
|
$
|
74,615
|
|
|
$
|
6.40
|
|
|
$
|
6.34
|
|
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.