Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1A. 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;
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|
|
•
|
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 1B of these consolidated financial statements for more information;
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•
|
claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;
|
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|
•
|
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;
|
|
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•
|
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
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•
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the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (the "New Credit Facility") with an initial
$320 million
borrowing base was established. For more information refer to Note 5 of these consolidated financial statements.
|
In accordance with the Plan, the post-emergence Company’s new board of directors is made up of seven directors consisting of the Chief Executive Officer, two directors appointed by Strategic Value Partners LLC ("SVP"), a former holder of the Company’s senior notes, two directors appointed by other former holders of the Company’s senior notes, one independent director and one independent non-executive chairman of the Board. In addition, pursuant to the Plan, SVP and the other former holders of the Company’s senior notes were given certain continuing director nomination rights subject to minimum share ownership conditions.
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 5 of these consolidated financial statements.
Financial Statement Classification of Liabilities Subject to Compromise
. As of December 31, 2015, our financial statements included amounts classified as liabilities subject to compromise, a majority of which were equitized upon emergence from bankruptcy on April 22, 2016. See Note 1B of these consolidated financial statements for more information.
1B. 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 on the Effective Date 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. References to “Predecessor” or “Predecessor Company” refer to the financial position and results of operations of the Company prior to and including 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 2. 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):
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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 New 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 11 of these consolidated financial statements).
The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands):
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|
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|
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):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
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|
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 New 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 New 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 New 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
|
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
|
|
2. Summary of Significant Accounting Policies
Fresh Start Accounting.
Upon emergence from bankruptcy the Company adopted Fresh Start Accounting, see Note 1B for further details.
Basis of Presentation
. The consolidated financial statements included herein have been prepared by Swift Energy Company (“Swift Energy,” the “Company,” or “we”) assuming the Company will continue as a going concern, and 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 Swift Energy 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. Effective January 25, 2017 the Company entered into an agreement to sell approximately
1.4 million
shares of its Common Stock in a private placement at a price of
$28.50
per share, which resulted in approximately
$40.0 million
in gross proceeds. The shares were sold to select institutional accredited investors and proceeds were primarily used to repay credit facility borrowings. Effective January 26, 2017 our borrowing base was reduced from
$320 million
, allocated between a non-conforming borrowing base of
$70 million
and conforming borrowing base of
$250 million
, to a fully conforming borrowing base of
$250 million
. See Note 5 for more information. There were no other material subsequent events requiring additional disclosure in these 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. We believe our estimates and assumptions are reasonable; however, 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:
|
|
•
|
the estimates of reorganization value, enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and application of fresh start accounting,
|
|
|
•
|
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,
|
|
|
•
|
estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
|
|
|
•
|
estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
|
|
|
•
|
estimates of future costs to develop and produce reserves,
|
|
|
•
|
accruals related to oil and gas sales, capital expenditures and lease operating expenses,
|
|
|
•
|
estimates in the calculation of share-based compensation expense,
|
|
|
•
|
estimates of our ownership in properties prior to final division of interest determination,
|
|
|
•
|
the estimated future cost and timing of asset retirement obligations,
|
|
|
•
|
estimates made in our income tax calculations,
|
|
|
•
|
estimates in the calculation of the fair value of hedging assets and liabilities,
|
|
|
•
|
estimates in the assessment of current litigation claims against the Company, and
|
|
|
•
|
estimates in amounts due with respect to open state regulatory audits.
|
While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as 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. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustments occur.
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
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
, and
the years ended December 31, 2015 and 2014 (predecessor)
, such internal costs capitalized totaled
$5.4 million
,
$2.9 million
,
$12.7 million
and
$26.3 million
, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 5 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.
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
December 31,
2016
|
|
|
December 31,
2015
|
Property and Equipment
|
|
|
|
|
Proved oil and gas properties
|
$
|
480,499
|
|
|
|
$
|
5,972,666
|
|
Unproved oil and gas properties
|
33,354
|
|
|
|
18,839
|
|
Furniture, fixtures, and other equipment
|
3,221
|
|
|
|
44,252
|
|
Less – Accumulated depreciation, depletion, amortization and impairment
|
(169,879
|
)
|
|
|
(5,577,854
|
)
|
Property and Equipment, Net
|
$
|
347,195
|
|
|
|
$
|
457,903
|
|
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.
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 estimated 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. 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, international 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 estimated 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 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.
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 during 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)
and the years ended
2015
and
2014
(predecessor) we reported non-cash impairment write-downs on a before-tax basis of
$77.7 million
,
$1.6 billion
and
$445.4 million
, respectively, on our oil and natural gas properties.
If future capital expenditures out pace 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) 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. Swift Energy uses the entitlement method of accounting in which we recognize our ownership interest in 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, 2016 and 2015
, we did not have any material natural gas imbalances.
Accounts Receivable.
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, 2016 and 2015
, we had an allowance for doubtful accounts of less than
$0.1 million
and approximately
$0.1 million
, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying consolidated balance sheets.
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. At
December 31, 2015
, our “Accounts receivable” balance included
$14.9 million
for oil and gas sales,
$4.9 million
for joint interest owners,
$1.2 million
for severance tax credit receivables and
$0.7 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
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the years ended December 31, 2015 and 2014 (predecessor)
did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was
$4.5 million
and
$2.7 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
and the
period of January 1, 2016 through April 22, 2016 (predecessor)
, respectively, and
$9.2 million
and
$12.7 million
for
the years ended December 31, 2015 and 2014 (predecessor)
, respectively.
Other Current Assets.
Included in "Other current assets" on the accompanying consolidated balance sheets are inventories which consist primarily of tubulars and other equipment and supplies that we expect to place in service in production operations. Our inventories are recorded at cost (weighted average method) and totaled
$0.4 million
and
$0.6 million
at
December 31, 2016 and 2015
, respectively. During the year ended December 31,
2015
, we recorded a charge of
$2.0 million
, related to inventory obsolescence in "Price-risk management and other, net" on the accompanying consolidated statement of operations.
Also included in "Other current assets" on the accompanying consolidated balance sheets are prepaid expenses totaling
$2.0 million
and
$4.4 million
at
December 31, 2016 and 2015
, respectively. These prepaid amounts cover well insurance, drilling contracts and various other prepaid expenses. In 2015 we also recorded
$2.4 million
in "Other current assets" related to a deposit received from Texegy as part of a purchase and sale agreement to sell a participating working interest of the Company's position in the South Bearhead Creek and Burr Ferry Field in central Louisiana. This amount was restricted until the transaction closed which occurred prior to our emergence from bankruptcy on
April 22, 2016
. Finally, as a result of the Company's bankruptcy proceedings, we reclassified
$3.3 million
in debt issuance costs related to our revolving credit facility as of December 31, 2015 from "Other Long-Term Assets" to "Other current assets". Debt issuance costs incurred on our New Credit Facility in
2016
were recorded in "Other Long-Term Assets" as of
December 31, 2016
.
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 likely 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, 2016
, 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 believes it will not incur an immediate cash income tax liability as a result of emergence from bankruptcy. The Company will be able to fully absorb cancellation of debt income with NOL carryforwards. The amount of remaining NOL carryforward available will be limited under IRC 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 and
December 31, 2016
, leaving the Company in a net deferred tax asset position. 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 and no benefit will be recorded due to the full valuation allowance on the tax assets.
Accounts Payable and Accrued Liabilities
. The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
December 31,
2016
|
|
|
December 31,
2015
|
Trade accounts payable
(1)
|
$
|
10,563
|
|
|
|
$
|
—
|
|
Accrued operating expenses
(1)
|
2,990
|
|
|
|
—
|
|
Accrued compensation costs
(1)
|
4,730
|
|
|
|
—
|
|
Asset retirement obligations – current portion
|
9,965
|
|
|
|
7,165
|
|
Accrued non-income based taxes
(1)
|
3,937
|
|
|
|
—
|
|
Accrued price risk management liabilities
|
17,632
|
|
|
|
—
|
|
Accrued corporate and legal fees
(1)
|
3,075
|
|
|
|
—
|
|
Other payables
(1)(2)
|
3,365
|
|
|
|
498
|
|
Total Accounts payable and accrued liabilities
|
$
|
56,257
|
|
|
|
$
|
7,663
|
|
(1) Classified as Liabilities Subject to Compromise as of December 31, 2015. Total Liabilities subject to compromise were $984.4 million as of
December 31, 2015
.
(2) Total balance at December 31, 2015 was
$5.3 million
of which
$4.8 million
was classified as Liabilities Subject to Compromise with the remaining portion classified as "Other payables".
Cash and Cash Equivalents.
We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents.
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 8 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
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the years ended December 31, 2015 and 2014 (predecessor), Shell Oil Company and affiliates accounted for
15%
,
19%
,
16%
and
21%
, respectively of our sales proceeds, Kinder Morgan accounted for approximately
38%
,
20%
,
27%
and
20%
, respectively, of our sales proceeds and Plains Marketing accounted for approximately
14%
,
14%
,
18%
and
11%
, respectively, of our sales proceeds. Howard Energy accounted for approximately
11%
and
13%
of our sales proceeds during the
period of January 1, 2016 through April 22, 2016 (predecessor)
and year ended December 31, 2015 (predecessor). Southcross Energy accounted for approximately
11%
of our sales proceeds during the
period of January 1, 2016 through April 22, 2016 (predecessor)
.
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. 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, 2015
(predecessor), the Company recorded losses of
$4.9 million
to "Retained earnings (Accumulated deficit)" as a result of treasury stock transactions. All treasury stock was canceled upon emergence from bankruptcy for the Predecessor Company. For the
period of April 23, 2016 through December 31, 2016 (successor)
,
22,485
treasury shares were purchased in connection with the retirement of the former Chief Executive Officer and future retirement of the Chief Financial Officer.
New Accounting Pronouncements
In May 2014, the FASB issued ASU 2014-09, 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. Adoption of this standard could result, at the option of the Company, in retrospective application, either in the form of recasting all prior periods presented or a cumulative adjustment to equity in the period of adoption. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017.
The Company’s revenues are virtually all attributable to oil and gas sales. Based on our initial review of our contracts, the Company believes the timing and presentation of revenues under ASU 2014-09 will be consistent with our current revenue recognition policy as described above with one probable exception. The Company currently uses the entitlement method of accounting when sales for our account are not in proportion to ownership interest in production. To comply with ASU 2014-09, the Company expects to recognize revenue on the production sold for our account irrespective of ownership share of such production. Currently we do not have any significant imbalance situations; therefore, this is not expected to immediately impact our financial statements. The Company will continue to monitor specific developments for our industry as it relates to ASU 2014-09.
In August 2014, the FASB issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. The guidance applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter. We implemented procedures to comply with this guidance as of December 31, 2016. Adoption of this standard had no impact on our financial statements.
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, 2016 the Company had lease commitments of approximately
$8.8 million
that it believes would be subject to capitalization under ASU 2016-02. This includes
$1.9 million
for our new corporate office sub-lease which has a term of
4.4
years and commitments for equipment and vehicle leases which total
$6.5 million
. These equipment leases generally have original terms of
2
to
3
years. In some instances further analysis is needed to determine if renewal options would result in capitalized amounts in excess of the obligations during the primary lease term. Based on our preliminary assessment, we believe these leases would most likely be deemed to be operating leases under the new standard. The corporate office lease is the only existing lease that extends beyond December 31, 2018. 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 March 2016, the FASB issued ASU 2016-09, which simplifies several aspects of the accounting for employee share based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, with early adoption permitted. This standard was adopted by the Company as of the bankruptcy emergence date April 22, 2016. The adoption of this guidance did not result in any adjustments.
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. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the ASU in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. We are currently reviewing these new requirements to determine the impact of this guidance on our financial statements.
3. Earnings Per Share
Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, 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 have been issuable, according to predetermined performance and market goals, 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 years ended
2015
and
2014
(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
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the years ended
2015
and
2014
(predecessor) (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor from April 23, 2016 through December 31, 2016
|
|
|
Predecessor from January 1, 2016 through April 22, 2016
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Share Amounts
|
$
|
(156,288
|
)
|
|
10,013
|
|
|
$
|
(15.61
|
)
|
|
|
$
|
851,611
|
|
|
44,692
|
|
|
$
|
19.06
|
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Awards
|
|
|
—
|
|
|
|
|
|
|
|
|
1,005
|
|
|
|
Restricted Stock Units Awards
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
Stock Option Awards
|
|
|
—
|
|
|
|
|
|
|
|
|
—
|
|
|
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Assumed Share Conversions
|
$
|
(156,288
|
)
|
|
10,013
|
|
|
$
|
(15.61
|
)
|
|
|
$
|
851,611
|
|
|
45,697
|
|
|
$
|
18.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor 2015
|
|
Predecessor 2014
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Share Amounts
|
$
|
(1,653,971
|
)
|
|
44,463
|
|
|
$
|
(37.20
|
)
|
|
$
|
(283,427
|
)
|
|
43,795
|
|
|
$
|
(6.47
|
)
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
Restricted Stock Unit Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
Stock Option Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Assumed Share Conversions
|
$
|
(1,653,971
|
)
|
|
44,463
|
|
|
$
|
(37.20
|
)
|
|
$
|
(283,427
|
)
|
|
43,795
|
|
|
$
|
(6.47
|
)
|
Approximately
0.1 million
stock options to purchase shares were not included in the computation of Diluted EPS for the
period of April 23, 2016 through December 31, 2016 (successor)
, 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
and
1.4 million
stock options to purchase shares were not included in the computation of Diluted EPS for the years ended December 31,
2015
and
2014
(predecessor), respectively, 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 years ended December 31,
2015
and
2014
, respectively, were not included in the computation of Diluted EPS because they were antidilutive.
Approximately
0.2 million
shares related to restricted stock units for the
period of April 23, 2016 through December 31, 2016 (successor)
were not included in the computation of Diluted EPS 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
and
0.4 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 years ended December 31,
2015
and
2014
(predecessor), respectively, 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 previously discussed in Note 1B of these consolidated financial statements). They were not included in the computation of Diluted EPS for the period of April 23, 2016 through December 31, 2016, as they were antidilutive.
4. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Income (Loss) Before Income Taxes
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
|
$
|
(1,734,514
|
)
|
|
$
|
(433,470
|
)
|
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Current
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(410
|
)
|
|
$
|
314
|
|
Deferred
|
—
|
|
|
|
—
|
|
|
(80,133
|
)
|
|
(150,357
|
)
|
Total
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(80,543
|
)
|
|
$
|
(150,043
|
)
|
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
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Federal Statutory Rate
|
35.0
|
%
|
|
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State tax provisions (benefits), net of federal benefits
|
0.9
|
%
|
|
|
0.9
|
%
|
|
1.0
|
%
|
|
1.4
|
%
|
Reorganization Adjustments
|
—
|
%
|
|
|
(1.8
|
)%
|
|
—
|
%
|
|
—
|
%
|
Expiration/Write-off of NOL Carryovers
|
(74.9
|
)%
|
|
|
—
|
%
|
|
—
|
%
|
|
(0.1
|
)%
|
Valuation allowance adjustments
|
38.9
|
%
|
|
|
(35.1
|
)%
|
|
(31.3
|
)%
|
|
(1.1
|
)%
|
Other, net
|
0.2
|
%
|
|
|
1.0
|
%
|
|
(0.1
|
)%
|
|
(0.7
|
)%
|
Effective rate
|
—
|
%
|
|
|
—
|
%
|
|
4.6
|
%
|
|
34.5
|
%
|
The tax effects of temporary differences representing the net deferred tax asset (liability) at
December 31, 2016 and 2015
were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Year Ended December 31, 2016
|
|
|
Year Ended December 31, 2015
|
Deferred tax assets:
|
|
|
|
|
Federal net operating loss (“NOL”) carryovers
|
$
|
40,104
|
|
|
|
$
|
287,720
|
|
NOLs for excess stock-based compensation
|
—
|
|
|
|
(9,571
|
)
|
Oil and gas exploration and development costs
|
71,292
|
|
|
|
214,413
|
|
State NOL carryovers
|
—
|
|
|
|
18,384
|
|
Alternative minimum tax credits
|
2,092
|
|
|
|
2,092
|
|
Other Carryover Items
|
1,107
|
|
|
|
1,215
|
|
Asset Retirement Obligations
|
11,447
|
|
|
|
22,884
|
|
Derivative Contracts
|
5,802
|
|
|
|
—
|
|
Unrealized share-based compensation
|
648
|
|
|
|
9,953
|
|
Valuation allowance
|
(136,656
|
)
|
|
|
(553,283
|
)
|
Other
|
4,164
|
|
|
|
6,193
|
|
Total deferred tax assets
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
Oil and gas exploration and development costs
|
$
|
—
|
|
|
|
$
|
—
|
|
Other
|
—
|
|
|
|
—
|
|
Total deferred tax liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
|
|
|
Net deferred tax liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
|
|
|
Net current deferred tax assets
|
—
|
|
|
|
—
|
|
|
|
|
|
|
Net non-current deferred tax liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
The Company has evaluated the full impact of the reorganization on our carryover tax attributes and believes it will not incur an immediate cash income tax liability as a result of emergence from bankruptcy. The Company will be able to fully absorb cancellation of debt income (CODI), estimated to be
$854 million
, with NOL carryforwards. The remaining NOL carryforward will be severely limited under Sec. 382 due to the change in control annual limitation of
$5.8 million
. The NOL carryforward that will expire before utilization due to the IRC Sec. 382 limitation is estimated to be
$305 million
. The deferred tax asset associated with the NOLs expected to expire was written off as of
December 31, 2016
. The remaining NOL carryforward after CODI and excess Sec. 382 limitation is
$115 million
, which will expire between 2034 and 2035 if not utilized in earlier periods. The Company’s state NOL carryforwards and deferred tax benefits for excess stock-based compensation deductions were written off as part of the reorganization.
The Company’s amortizable tax basis exceeded the book carrying value of its assets at December 31, 2016 and December 31, 2015, leaving the Company in a net deferred tax asset position. 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
$137 million
and
$553 million
at December 31, 2016 and December 31, 2015, respectively.
As of December 31, 2016, 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 and state 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.
5. Long-Term Debt
Bankruptcy Filing.
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 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 DIP Credit Agreement (along with certain unsecured claims) were exchanged for
88.5%
of the common stock of the reorganized entity. Additional information regarding the bankruptcy proceedings is included in Note 1A of the consolidated financial statements.
Our debt balances as of
December 31, 2016 and 2015
, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
December 31, 2016
|
|
|
December 31, 2015
|
7.125% senior notes due in 2017
(1)
|
—
|
|
|
|
—
|
|
8.875% senior notes due in 2020
(1)
|
—
|
|
|
|
—
|
|
7.875% senior notes due in 2022
(1)
|
—
|
|
|
|
—
|
|
Bank Borrowings
|
$
|
198,000
|
|
|
|
$
|
324,900
|
|
Total Debt
|
198,000
|
|
|
|
324,900
|
|
Less: Current portion of long-term debt
(2)
|
$
|
—
|
|
|
|
$
|
(324,900
|
)
|
Long-Term Debt
|
$
|
198,000
|
|
|
|
$
|
—
|
|
(1) Classified as Liabilities Subject to Compromise as of December 31, 2015
|
|
|
|
|
(2) As a result of our Chapter 11 filing, we classified our credit facility borrowings as current at December 31, 2015.
|
New Credit Facility.
As discussed in Note 1A of these consolidated financial statements, on the Effective Date, the Prior First Lien Credit Facility was terminated and paid in full, and the Company entered the New Credit Facility among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto. The New Credit Facility matures on April 22, 2019 and provides for advancing loans of up to the maximum credit amount that the lenders, in the aggregate, make available, subject to the Company meeting certain financial requirements, including certain financial tests. As of the Effective Date, the maximum credit amount was
$500.0 million
with an initial borrowing base of
$320.0 million
. The obligations under the New Credit Facility are secured, subject to certain exceptions, by a first priority lien of the Company's, and certain of its subsidiaries, oil and natural gas properties containing at least
95%
of the Company's estimated proved producing reserves. The terms of the New Credit Facility also include the following, based on terms as defined in the New Credit Facility agreement:
|
|
•
|
As of the Effective Date and through
December 31, 2016
, the initial borrowing base of
$320.0 million
was allocated between a non-conforming borrowing base of
$70.0 million
which was originally scheduled to terminate on November 1, 2017, and a conforming borrowing base of
$250.0 million
. Effective January 26, 2017 the Company and the lenders agreed to terminate the non-conforming borrowing base leaving only the conforming borrowing base of
$250.0 million
. As of
December 31, 2016
, the Company had borrowings of
$198.0 million
drawn on the credit facility.
|
|
|
•
|
Borrowing base redeterminations are scheduled to occur semi-annually in November and May and are determined by the lenders in their discretion and in the usual and customary manner.
|
|
|
•
|
The interest rate for Alternative Base Rate ("ABR") loans will be based on the ABR plus the applicable margin, and the interest rate for Eurodollar loans will be based on the adjusted London Interbank Offered Rate (“LIBOR”), plus the applicable margin.
|
|
|
•
|
As of
December 31, 2016
, the applicable margins varied and had escalating rates of either (a)
500
to
600
basis points for ABR loans and
600
to
700
basis points for Eurodollar loans, during the non-conforming period, and depending on the level of the non-conforming borrowing base and the non-conforming borrowing base loans outstanding, or (b)
200
to
300
basis points for ABR loans and
300
to
400
basis points for Eurodollar loans depending on the borrowing base utilization percentage, after the non-conforming period or when the non-conforming borrowing base is zero. Given the termination of the non-conforming borrowing base effective January 26, 2017, the applicable margins going forward are
|
200
to
300
basis points for ABR loans and
300
to
400
basis points for Eurodollar loans. As of
December 31, 2016
, our average borrowing rate was
7.9%
.
|
|
•
|
Certain covenants, including (a) a ratio of total debt to EBITDA (as defined in the agreement) not to exceed
6.0
to 1.0 for the quarter ending
December 31, 2016
, declining gradually over time to
3.5
to 1.0 for the quarter ending March 31, 2019, and thereafter, (b) a current ratio of not less than
1.0
to 1.0 and (c) a minimum liquidity requirement of
$10.0 million
. As of
December 31, 2016
, the Company was in compliance with these covenants and liquidity requirements.
|
Interest expense on the New Credit Facility, including commitment fees and amortization of debt issuance costs, totaled
$15.3 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
. The amount of commitment fees amortization included in interest expense, net was
$0.2 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
.
Additionally, we capitalized interest on our unproved properties in the amount of
$0.5 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
.
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, totaling
$0.9 million
. 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
. Amounts outstanding under our pre-petition Prior First Lien Credit Facility due in 2017 of
$324.9 million
were classified as a current liability in the Consolidated Balance Sheet dated as of
December 31, 2015
due to cross-default provisions as a result of the bankruptcy filings. The interest rate on our Prior First Lien Credit Facility was either (a) the lead bank’s prime rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. However with respect to (a), if the lead bank’s prime rate was not higher than each of the federal funds rate plus
0.5%
, and the adjusted London Interbank Offered Rate (“LIBOR”) plus
1%
, the greatest of these three rates then applied. The applicable margins varied depending on the level of outstanding debt with escalating rates of
100
to
200
basis points above the Alternative Base Rate and escalating rates of
200
to
300
basis points for Eurodollar rate loans. The commitment fee terms associated with the Prior First Lien Credit Facility were
0.50%
. 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
,
$9.4 million
and
$7.5 million
for the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the years ended December 31, 2015 and 2014 (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
and
$0.8 million
for
the years ended December 31, 2015 and 2014 (predecessor)
, respectively.
Additionally, we have capitalized interest on our unproved properties in the amount of
$4.9 million
and
$5.0 million
for
the years ended December 31, 2015 and 2014 (predecessor)
, respectively. 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.
Senior Notes Liabilities
. Senior Notes due in 2017 of
$250.0 million
, Senior Notes due in 2020 of
$225.0 million
and Senior Notes due in 2022 of
$400.0 million
are included in Liabilities subject to compromise in the Consolidated Balance Sheet as of
December 31, 2015
. These notes were canceled upon emergence from bankruptcy.
Senior Notes Due In 2022.
These notes consist of
$400.0 million
of
7.875%
senior notes that were scheduled to mature on March 1, 2022. The filing of the petition for bankruptcy protection constituted an “event of default” under the indenture governing these senior notes. 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.
Senior Notes Due In 2020
. These notes consist of
$225.0 million
of
8.875%
senior notes issued at
98.389%
of par, which equates to an effective yield to maturity of
9.125%
. The filing of the petition for bankruptcy protection constituted an “event of default” under the indenture governing these senior notes. 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.
Senior Notes Due In 2017
. These notes consist of
$250.0 million
of
7.125%
senior notes due in 2017, which were issued on June 1, 2007 at
100%
of the principal amount and were scheduled to mature on June 1, 2017. The filing of the petition for bankruptcy protection constituted an “event of default” under the indenture governing these senior notes. 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.
Debt Issuance Costs
. Our policy is to capitalize legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with issuing debt. The costs associated with our senior notes were amortized on an effective interest basis over the term of the senior notes, while issuance costs related to our line of credit arrangement are capitalized and then amortized ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings.
Interest Expense on Senior Notes
. There was
no
interest expense on the senior notes, for the
period of January 1, 2016 through April 22, 2016 (predecessor)
due to 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
and
$70.7 million
for
the years ended December 31, 2015 and 2014 (predecessor)
, respectively.
6. 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 "Price-risk management and other, net" 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 price swaps and collars.
For the
period of April 23, 2016 through December 31, 2016 (successor)
we recognized a
$19.7 million
loss relating to our derivative activities. For
the years ended December 31, 2015 and 2014 (predecessor)
we recognized a
$0.2 million
and
$1.3 million
gain, respectively. The Company made net cash payments of
$1.9 million
for settled derivative contracts during the
period of April 23, 2016 through December 31, 2016 (successor)
. For
the years ended December 31, 2015 and 2014 (predecessor)
we received net cash payments of
$2.5 million
and made net cash payments of
$1.1 million
, respectively, for settled derivative contracts. There were no derivative instruments outstanding during the
period of January 1, 2016 through April 22, 2016 (predecessor)
.
At
December 31, 2016
we had
$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 2017. At
December 31, 2016
we had
$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 2017.
The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. At
December 31, 2016
there was
$0.5 million
in current unsettled derivative assets, while our long-term unsettled derivative assets were
no
t material. At
December 31, 2016
there was
$15.8 million
and
$1.0 million
in current and long-term unsettled derivative liabilities, respectively.
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
$16.4 million
net fair value
liability
at
December 31, 2016
. For further discussion related to the fair value of the Company's derivatives, refer to Note 11 of these consolidated financial statements.
The following table summarizes the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of December 31, 2016.
|
|
|
|
|
|
|
|
Oil Derivative Swaps
(NYMEX WTI Settlements)
|
Total Volumes (Bbls)
|
|
Weighted Average Price
|
2017 Contracts
|
|
|
|
1Q17
|
106,245
|
|
|
$
|
48.04
|
|
2Q17
|
97,401
|
|
|
$
|
48.13
|
|
3Q17
|
90,000
|
|
|
$
|
48.16
|
|
4Q17
|
84,798
|
|
|
$
|
48.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
|
Total Volumes (MMBtu)
|
|
Weighted Average Swap Price
|
|
Weighted Average Collar Floor Price
|
|
Weighted Average Collar Call Price
|
Swap Contracts
|
|
|
|
|
|
|
|
1Q18
|
4,395,000
|
|
|
$
|
3.47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q17
|
4,500,000
|
|
|
$
|
3.13
|
|
|
|
|
|
2Q17
|
5,420,005
|
|
|
$
|
2.96
|
|
|
|
|
|
3Q17
|
5,104,999
|
|
|
$
|
2.98
|
|
|
|
|
|
4Q17
|
3,725,001
|
|
|
$
|
2.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
1Q17
|
550,000
|
|
|
|
|
$
|
3.300
|
|
|
$
|
3.900
|
|
2Q17
|
2,400,000
|
|
|
|
|
$
|
3.050
|
|
|
$
|
3.545
|
|
3Q17
|
2,865,000
|
|
|
|
|
$
|
3.050
|
|
|
$
|
3.585
|
|
4Q17
|
3,102,000
|
|
|
|
|
$
|
3.100
|
|
|
$
|
3.715
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel Settlements)
|
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
2018 Contracts
|
|
|
|
1Q18
|
1,500,000
|
|
|
$
|
(0.08
|
)
|
|
|
|
|
2017 Contracts
|
|
|
|
1Q17
|
5,050,000
|
|
|
$
|
(0.08
|
)
|
2Q17
|
7,820,005
|
|
|
$
|
(0.03
|
)
|
3Q17
|
7,969,999
|
|
|
$
|
(0.02
|
)
|
4Q17
|
6,827,001
|
|
|
$
|
(0.04
|
)
|
7. Commitments and Contingencies
Rental and lease expenses were
$5.7 million
,
$4.5 million
,
$16.8 million
and
$21.0 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
,
period of January 1, 2016 through April 22, 2016 (predecessor)
and the years ended December 31, 2015 and 2014 (predecessor), respectively. The rental and lease expenses primarily relate 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. As of
December 31, 2016
, the minimum contractual obligations were approximately
$1.9 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
$5.5 million
for 2017,
$2.0 million
for 2018,
$0.6 million
for
2019
,
$0.5 million
for
2020
,
$0.2 million
for
2021
and approximately
$8.8 million
in the aggregate. The minimum annual obligations under non-cancelable operating lease commitments primarily relate to compressor rentals and office space for the Houston office.
We have gas transportation and processing minimum obligations amounting to
$8.3 million
for
2017
,
$13.5 million
for
2018
,
$12.8 million
for
2019
,
$10.8 million
for
2020
and
$45.4 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.
8. Share-Based Compensation
Emergence from Voluntary Reorganization
Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company’s common stock was canceled and new common stock was issued. The Company's previous share-based compensation awards were either vested or canceled upon the Company's emergence from bankruptcy.
Share-Based Compensation Plans
Upon the Company's emergence from bankruptcy on April 22, 2016, the new Swift Energy Company 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Under the previous share-based compensation plan the outstanding restricted stock awards and restricted stock unit awards 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 financing cash flows.
For 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 4 in our Form 10-K 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 years ended December 31, 2015 and 2014 (predecessor), we recognized an income tax shortfall in earnings as referenced in Note 4 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
$3.6 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
, while for the
period of January 1, 2016 through April 22, 2016 (predecessor)
and
the years ended December 31, 2015 and 2014 (predecessor)
the expense was
$0.9 million
,
$4.1 million
and
$6.7 million
, respectively.
We have
no
t capitalized 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 years ended December 31, 2015 and 2014 (predecessor)
we capitalized
$0.2 million
,
$1.4 million
and
$3.5 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.
Share-based compensation recorded in lease operating cost was
$0.2 million
for
the years ended December 31, 2015 and 2014 (predecessor)
. There was
no
share-based compensation recorded in lease operating cost for the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the
period of April 23, 2016 through December 31, 2016 (successor)
.
Our shares available for future grant under our Share-Based Compensation plans were
221,295
at
December 31, 2016
. Each restricted stock award and restricted stock unit granted reduces the shares available for future grant by
one
share.
Stock Option Awards
On June 8, 2016,
105,811
stock option awards were granted to various officers and directors with an exercise price of
$23.25
. 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
three
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
period of April 23, 2016 through December 31, 2016 (successor)
:
|
|
|
|
|
|
Stock Option Valuation Assumptions
|
Expected Dividend
|
—
|
|
Expected volatility
|
69.3
|
%
|
Risk-free interest rate
|
1.42
|
%
|
Expected life of stock option awards (in years)
|
4
|
|
Weighted average grant-date fair value
|
$
|
12.64
|
|
To estimate expected volatility of our 2016 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
4
year look-back period to estimate expected volatility of our stock option awards.
At
December 31, 2016
, we had
$0.4 million
unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the
year ended December 31, 2016
:
|
|
|
|
|
|
|
|
|
2016
|
|
Shares
|
|
Wtd. Avg.
Exer. Price
|
|
|
|
|
Options outstanding, beginning of period (Predecessor)
|
1,330,390
|
|
|
$
|
34.02
|
|
Options canceled/vested upon emergence from bankruptcy
|
(1,330,390
|
)
|
|
$
|
—
|
|
Options outstanding, as of April 22, 2016 (Successor)
|
—
|
|
|
$
|
—
|
|
Options granted
|
105,811
|
|
|
$
|
23.25
|
|
Options canceled
|
—
|
|
|
$
|
—
|
|
Options exercised
|
—
|
|
|
$
|
—
|
|
Options outstanding, end of period (Successor)
|
105,811
|
|
|
$
|
23.25
|
|
Options exercisable, end of period (Successor)
|
60,847
|
|
|
$
|
23.25
|
|
Our outstanding stock option awards at
December 31, 2016
had
$1.1 million
aggregate intrinsic value. At
December 31, 2016
the weighted average remaining contract life of stock option awards outstanding was
3.2
years and exercisable was
2.3
years. The total intrinsic value of stock option awards exercisable for the year ended
December 31, 2016
was
$0.6 million
.
The following table summarizes information about stock option awards outstanding at
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
Options Exercisable
|
Range of Exercise Prices
|
|
Number Outstanding at 12/31/16
|
|
Wtd. Avg. Remaining Contractual Life
|
|
Wtd. Avg. Exercise Price
|
|
Number Exercisable at 12/31/16
|
|
Wtd. Avg. Exercise Price
|
$1.00 to $25.00
|
|
105,811
|
|
|
3.2
|
|
$
|
23.25
|
|
|
60,874
|
|
|
$
|
23.25
|
|
Restricted Stock Awards
The following table represents restricted stock award activity for the
year ended December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
2016
|
|
Shares
|
|
Wtd. Avg.
Grant Price
|
Restricted awards outstanding, beginning of period (Predecessor)
|
1,487,076
|
|
|
$
|
8.94
|
|
Restricted awards canceled/vested upon emergence from bankruptcy
|
(1,487,076
|
)
|
|
$
|
8.94
|
|
Restricted awards, as of April 22, 2016 (Successor)
|
$
|
—
|
|
|
$
|
—
|
|
Restricted shares outstanding, end of period (Successor)
|
—
|
|
|
$
|
—
|
|
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
three
years).
On June 8, 2016,
254,905
restricted stock unit awards were granted to various officers and directors with a grant-date fair value of
$23.25
. These grants generally vest over a period of
one
to
three
years.
As of
December 31, 2016
, we had unrecognized compensation expense of
$3.2 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, 2016
:
|
|
|
|
|
|
|
|
|
Shares
|
|
Wtd. Avg.
Grant Price
|
Restricted units outstanding, beginning of period (Predecessor)
|
591,400
|
|
|
$
|
9.20
|
|
Restricted units canceled/vested upon emergence from bankruptcy
|
(591,400
|
)
|
|
$
|
9.20
|
|
Restricted units, as of April 22, 2016 (Successor)
|
—
|
|
|
$
|
—
|
|
Restricted stock units granted
|
254,905
|
|
|
$
|
23.25
|
|
Restricted stock units canceled
|
—
|
|
|
$
|
—
|
|
Restricted stock units vested
|
76,058
|
|
|
$
|
23.25
|
|
Restricted stock units outstanding, end of period (Successor)
|
178,847
|
|
|
$
|
23.25
|
|
In accordance with their employment agreements, the 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. For 2016 the Company contributed on behalf of the eligible employee an amount up to
100%
of the first
2%
of compensation based on the contributions made by the eligible employees. The Company's 2016 plan contribution of
$0.3 million
was paid in cash during the first quarter of 2017. The Company's contributions to the 401(k) savings plan were
$0.7 million
for the year ended December 31, 2015 and were
$1.9 million
for the year ended December 31, 2014. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations. The 2014 plan contributions were made with a combination of
$0.9 million
of cash and
352,476
shares of common stock, from treasury shares.
Predecessor Share-Based Compensation Awards
We previously had shares outstanding under multiple share-based compensation plans with outstanding awards including the 2005 Stock Compensation Plan, last amended by our Board of Directors in May 2013, which was approved by shareholders at the 2005 annual meeting of shareholders; the 2001 Omnibus Stock Compensation Plan, which was adopted by our Board of Directors in February 2001 and was approved by shareholders at the 2001 annual meeting of shareholders; the 1990 Non-Qualified Stock Option Plan solely for our independent directors. 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 2005 plan, stock option awards and other equity-based awards could be granted to employees, directors, and consultants, with directors only eligible to receive restricted awards. Under the 2001 plan, stock option awards and other equity based awards were granted to employees. Under the 1990 non-qualified plan, non-employee members of our Board of Directors were automatically granted stock option awards to purchase shares of common stock on a formula basis. 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 and
71,825
shares at a price of
$11.47
in 2014. As of December 31, 2015, this plan was terminated.
During the years ended December 31, 2015 and 2014, we did
no
t grant any stock option awards and there were
no
stock option exercises for the years ended December 31, 2015 and 2014. The total intrinsic value of stock option awards exercised for the years ended December 31, 2015 and 2014 was
no
t material.
For the years ended December 31, 2015 and 2014, the Company issued
609,238
shares and
747,400
shares, respectively, of restricted stock to employees, consultants, and directors. The weighted average fair values of these shares when issued, for the years ended December 31, 2015 and 2014 were
$2.64
and
$11.55
per share, respectively. The grant date fair values of shares vested for the years ended December 31, 2015 and 2014 were
$6.1 million
and
$11.8 million
, respectively. 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 years ended December 31, 2015 and 2014, the Company granted
216,450
and
185,250
performance-based restricted stock units, respectively. 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 years ended December 31, 2015 and 2014. The weighted average grant date fair value for the restricted stock units granted during the years ended December 31, 2015 and 2014 was
$1.98
and
$11.68
per unit, respectively. All of the remaining grants were canceled upon emergence from bankruptcy.
9. 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
and
$0.6 million
for the years ended 2015 and 2014 (predecessor), respectively. 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.
10. 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
received by the Company in this transaction, including deposits received prior to the closing date, 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.
In accordance with our Full Cost Accounting policy, no gains or losses were recognized on these disposition transactions. The sales proceeds were credited to our proved oil and gas property accounts.
11. Fair Value Measurements
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. 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 amount of the revolving long-term debt approximates fair value because the Company's current borrowing base rate does not materially differ from market rates for similar bank borrowings.
Based upon quoted market prices as of December 31, 2015 (predecessor), the fair value and carrying value of our senior notes was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Subject to Compromise
|
|
December 31, 2015
|
|
Fair Value
|
|
Carrying
(1)
Value
|
7.125% senior notes due in 2017
|
$
|
23.0
|
|
|
$
|
250.0
|
|
8.875% senior notes due in 2020
|
$
|
21.4
|
|
|
$
|
225.0
|
|
7.875% senior notes due in 2022
|
$
|
34.5
|
|
|
$
|
400.0
|
|
(1) Includes write-off of discount associated with the 2020 notes and premium associated with the 2022 notes due to the Company's bankruptcy proceedings.
|
Our senior notes due in 2017, 2020 and 2022 were stated at carrying value on our accompanying consolidated balance sheets until they were canceled as part of the Company's plan of reorganization and emergence from bankruptcy. If we recorded these notes at fair value they would have been Level 1 in our fair value hierarchy as they were traded in an active market with quoted prices for identical instruments until they were canceled.
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. We do not have any assets or liabilities in this category.
The following table presents our assets and liabilities that are measured at fair value on a recurring basis as of
December 31, 2016
for the Successor Company, and are categorized using the fair value hierarchy. As of December 31, 2015 all of the Predecessor Company's hedging agreements had settled. For additional discussion related to the fair value of the Company's derivatives, refer to Note 6 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, 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.
12. 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 1A, 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, 2014
|
$
|
72,831
|
|
Accretion expense
|
5,572
|
|
Liabilities incurred for new wells and facilities construction
|
151
|
|
Reductions due to sold and abandoned wells and facilities
|
(4,576
|
)
|
Revisions in estimates
|
(10,423
|
)
|
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
|
|
At
December 31, 2016 and 2015
, approximately
$10.0 million
and
$7.2 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.
Supplementary Information (unaudited)
Swift Energy Company 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, 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
|
|
|
|
December 31, 2015
|
|
Proved oil and gas properties
|
$
|
5,972,666
|
|
Unproved oil and gas properties
|
18,839
|
|
|
5,991,505
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(5,540,952
|
)
|
Net capitalized costs
|
$
|
450,553
|
|
There were
$33.4 million
of unproved property costs at
December 31, 2016
excluded from the amortizable base. The December 31, 2016 balance represents the fair value of the Company's unproved oil and gas properties upon emergence from bankruptcy and implementation of Fresh Start Accounting on April 22, 2016 less cost transferred to proved through December 31, 2016. 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, 2016 and 2015
.
Costs Incurred.
The following table sets forth costs incurred related to our oil and natural gas operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Lease acquisitions and prospect costs
|
$
|
6,466
|
|
|
|
$
|
2,695
|
|
|
$
|
28,571
|
|
|
$
|
44,162
|
|
Exploration
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
(1) (3)
|
40,908
|
|
|
|
24,082
|
|
|
74,948
|
|
|
327,878
|
|
Total acquisition, exploration, and development
(2)
|
$
|
47,374
|
|
|
|
$
|
26,777
|
|
|
$
|
103,519
|
|
|
$
|
372,040
|
|
(1) Facility construction costs and capital costs have been included in development costs, and totaled $6.0 million, $2.2 million, $5.5 million and $47.0 million for the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the years ended December 31, 2015 and 2014 (predecessor), respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately
$5.4 million
,
$2.9 million
,
$12.7 million
and
$26.3 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
, and the
years ended December 31, 2015 and 2014
(predecessor), respectively. In addition, the total includes
$0.5 million
,
$4.9 million
and
$5.0 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
and the years ended December 31, 2015 and 2014 (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 $8.0 million, $0.4 million, ($10.3 million) and ($3.7 million) for the
period of April 23, 2016 through December 31, 2016 (successor)
, the
period of January 1, 2016 through April 22, 2016 (predecessor)
and the years ended December 31, 2015 and 2014 (predecessor), respectively.
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
December 31, 2016
and Gruy audited
99%
and
97%
of our proved reserves as of December 31, 2015 and 2014, respectively. The decrease in reserves in 2015 were due to lower commodity prices and uncertainties, due in part to our bankruptcy filing, surrounding the availability of the financing that would be necessary to develop our proved undeveloped reserves, as disclosed in Note 1A of the consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimates of Proved Reserves
|
Total
|
|
Natural Gas
|
|
Oil
|
|
NGL
|
|
(Boe)
|
|
(Mcf)
|
|
(Bbls)
|
|
(Bbls)
|
Proved reserves as of December 31, 2014
(5)
|
193,826,433
|
|
|
686,747,086
|
|
|
49,706,258
|
|
|
29,662,327
|
|
Revisions of previous estimates
(1) (5)
|
(112,895,177
|
)
|
|
(334,147,002
|
)
|
|
(37,191,224
|
)
|
|
(20,012,785
|
)
|
Extensions, discoveries, and other additions
(3)
|
487,939
|
|
|
2,927,633
|
|
|
—
|
|
|
—
|
|
Production
(5)
|
(11,146,185
|
)
|
|
(43,839,319
|
)
|
|
(2,406,201
|
)
|
|
(1,433,431
|
)
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2015
(5)
|
70,273,010
|
|
|
311,688,398
|
|
|
10,108,833
|
|
|
8,216,111
|
|
Revisions of previous estimates
(1) (5)
|
54,446,615
|
|
|
270,749,891
|
|
|
1,821,443
|
|
|
7,500,190
|
|
Sales of minerals in place
(4)
|
(7,058,263
|
)
|
|
(7,915,022
|
)
|
|
(4,844,064
|
)
|
|
(895,030
|
)
|
Extensions, discoveries, and other additions
(3)
|
15,467,483
|
|
|
92,804,900
|
|
|
—
|
|
|
—
|
|
Production
(5)
|
(9,171,978
|
)
|
|
(40,539,807
|
)
|
|
(1,308,521
|
)
|
|
(1,106,822
|
)
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2016
(5)
|
123,956,867
|
|
|
626,788,360
|
|
|
5,777,691
|
|
|
13,714,449
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
(2)
:
|
|
|
|
|
|
|
|
December 31, 2014
|
66,285,034
|
|
|
232,806,911
|
|
|
14,989,353
|
|
|
12,494,529
|
|
December 31, 2015
|
56,334,309
|
|
|
238,355,707
|
|
|
10,108,833
|
|
|
6,499,524
|
|
December 31, 2016
|
63,038,972
|
|
|
312,125,091
|
|
|
4,512,842
|
|
|
6,505,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
(6)
|
|
|
|
|
|
|
|
December 31, 2014
|
127,541,399
|
|
|
453,940,175
|
|
|
34,716,905
|
|
|
17,167,798
|
|
December 31, 2015
|
13,938,701
|
|
|
73,332,691
|
|
|
—
|
|
|
1,716,587
|
|
December 31, 2016
|
60,917,935
|
|
|
314,663,510
|
|
|
1,264,849
|
|
|
7,209,167
|
|
(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 decrease in reserves in 2015 were due to lower commodity prices and uncertainties, due in part to our bankruptcy filing, surrounding the availability of the financing that would be necessary to develop our proved undeveloped reserves, as disclosed in Note 1A of the consolidated financial statements. Proved reserves, as of
December 31, 2016, 2015 and 2014
, 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
2016
average adjusted prices after differentials used in our calculations were
$2.43
per Mcf of natural gas,
$41.07
per barrel of oil, and
$16.13
per barrel of NGL compared to
$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 and
$4.32
per Mcf of natural gas,
$93.64
per barrel of oil, and
$33.00
per barrel of NGL for the 12-month average
2014
prices.
(2) At
December 31, 2016, 2015 and 2014
,
51%
, 80% and 34% of our reserves were proved developed, respectively.
(3) We have added proved reserves through our drilling activities, including, 0.5 MMBoe added in 2015. 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 2015 and 2016 extensions were all in the Fasken Eagle Ford area.
(4)
Includes the disposition of our Lake Washington, Masters Creek, Burr Ferry, South Bearhead Creek and Sun TSH fields. See Note 10 of the consolidated financial statements in our Form 10-K for more information.
(5) The Company's reserves volumes exclude gas consumed in operations. Effective in our December 31, 2014 reserves volumes, we excluded natural gas volumes expected to be consumed in future operations from our reserves volumes. The effect of this change is included in the table above under Revision of previous estimates during 2014, and all amounts shown during 2015 and 2016 exclude these natural gas volumes. This change does not impact our cash flow or PV10 projections as the prices are adjusted accordingly.
(6) The increase in proved undeveloped reserves during 2016 was 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 decrease in proved undeveloped reserves during 2015 were due to lower commodity prices and uncertainties, due in part to our bankruptcy filing, surrounding the availability of the financing that would be necessary to develop our proved undeveloped reserves, as disclosed in Note 1A of the consolidated financial statements in our Form 10-K.
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,
|
|
2016
|
|
2015
|
|
2014
|
Future gross revenues
|
$
|
1,980,642
|
|
|
$
|
1,434,931
|
|
|
$
|
8,597,119
|
|
Future production costs
|
(750,823
|
)
|
|
(688,427
|
)
|
|
(2,447,318
|
)
|
Future development costs
(1)
|
(365,064
|
)
|
|
(280,252
|
)
|
|
(2,256,328
|
)
|
Future net cash flows before income taxes
|
864,755
|
|
|
466,252
|
|
|
3,893,473
|
|
Future income taxes
|
(88,775
|
)
|
|
(297
|
)
|
|
(773,688
|
)
|
Future net cash flows after income taxes
|
775,980
|
|
|
465,955
|
|
|
3,119,785
|
|
Discount at 10% per annum
|
(368,987
|
)
|
|
(92,190
|
)
|
|
(1,468,111
|
)
|
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
|
$
|
406,993
|
|
|
$
|
373,765
|
|
|
$
|
1,651,674
|
|
(1) These amounts include future costs related to asset retirement obligations.
The standardized measure of discounted future net cash flows from production of proved reserves as of December 31, 2016, 2015 and 2014, 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, 2016, 2015 and 2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
Beginning balance
|
$
|
373,765
|
|
|
$
|
1,651,674
|
|
|
$
|
2,001,781
|
|
|
|
|
|
|
|
Revisions to reserves proved in prior years:
|
|
|
|
|
|
Net changes in prices, net of production costs
|
(46,553
|
)
|
|
(2,018,065
|
)
|
|
(208,597
|
)
|
Net changes in future development costs
|
(152,600
|
)
|
|
817,324
|
|
|
(19,651
|
)
|
Net changes due to revisions in quantity estimates
|
264,124
|
|
|
(599,342
|
)
|
|
(5,762
|
)
|
Accretion of discount
|
33,327
|
|
|
194,326
|
|
|
242,464
|
|
Other
|
28,888
|
|
|
119,483
|
|
|
(236,996
|
)
|
Total revisions
|
127,186
|
|
|
(1,486,274
|
)
|
|
(228,542
|
)
|
|
|
|
|
|
|
New field discoveries and extensions, net of future production and development costs
|
75,034
|
|
|
3,025
|
|
|
38,301
|
|
Sales of minerals in place
|
(76,327
|
)
|
|
—
|
|
|
(128,939
|
)
|
Sales of oil and gas produced, net of production costs
|
(93,945
|
)
|
|
(137,251
|
)
|
|
(396,399
|
)
|
Previously estimated development costs incurred
|
36,218
|
|
|
51,149
|
|
|
234,184
|
|
Net change in income taxes
|
(34,938
|
)
|
|
291,442
|
|
|
131,288
|
|
Net change in standardized measure of discounted future net cash flows
|
33,228
|
|
|
(1,277,909
|
)
|
|
(350,107
|
)
|
Ending balance
|
$
|
406,993
|
|
|
$
|
373,765
|
|
|
$
|
1,651,674
|
|
Selected Quarterly Financial Data (Unaudited).
The following table presents summarized quarterly financial information for the
period of January 1, 2016 through April 22, 2016 (predecessor), period of April 23, 2016 through December 31, 2016 (successor)
and the
year ended December 31, 2015
(predecessor) (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
Net Income (Loss) Before Taxes
|
|
Net Income (Loss)
|
|
Basic EPS
|
|
Diluted EPS
|
January 1 - April 22, 2016 (Predecessor)
|
|
|
|
|
|
|
|
|
|
First
(1)
|
$
|
34,272
|
|
|
$
|
(108,303
|
)
|
|
$
|
(108,303
|
)
|
|
$
|
(2.42
|
)
|
|
$
|
(2.42
|
)
|
April 1 - April 22, 2016
|
8,510
|
|
|
959,914
|
|
|
959,914
|
|
|
21.45
|
|
|
21.03
|
|
Total
|
42,782
|
|
|
851,611
|
|
|
851,611
|
|
|
19.06
|
|
|
18.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 23 - December 31, 2016 (Successor)
|
|
|
|
|
|
|
|
|
|
April 23 - June 30, 2016
(1)
|
20,653
|
|
|
(149,601
|
)
|
|
(149,601
|
)
|
|
(14.96
|
)
|
|
(14.96
|
)
|
Third
|
50,591
|
|
|
394
|
|
|
394
|
|
|
0.04
|
|
|
0.04
|
|
Fourth
|
30,293
|
|
|
(7,081
|
)
|
|
(7,081
|
)
|
|
(0.71
|
)
|
|
(0.71
|
)
|
Total
|
$
|
101,537
|
|
|
$
|
(156,288
|
)
|
|
$
|
(156,288
|
)
|
|
$
|
(15.61
|
)
|
|
$
|
(15.61
|
)
|
|
|
|
|
|
|
|
|
|
|
2015 (Predecessor)
|
|
|
|
|
|
|
|
|
|
First
|
$
|
68,337
|
|
|
$
|
(556,568
|
)
|
|
$
|
(477,077
|
)
|
|
$
|
(10.79
|
)
|
|
$
|
(10.79
|
)
|
Second
|
66,169
|
|
|
(293,509
|
)
|
|
(292,867
|
)
|
|
(6.58
|
)
|
|
(6.58
|
)
|
Third
|
60,116
|
|
|
(354,588
|
)
|
|
(354,588
|
)
|
|
(7.96
|
)
|
|
(7.96
|
)
|
Fourth
|
50,099
|
|
|
(529,849
|
)
|
|
(529,439
|
)
|
|
(11.88
|
)
|
|
(11.88
|
)
|
Total
(1)
|
$
|
244,721
|
|
|
$
|
(1,734,514
|
)
|
|
$
|
(1,653,971
|
)
|
|
$
|
(37.20
|
)
|
|
$
|
(37.20
|
)
|
(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)
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.
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.