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EX-99.1 - EXHIBIT 99.1 - SILVERBOW RESOURCES, INC.exhibit991.htm
EX-32 - EXHIBIT 32 - SILVERBOW RESOURCES, INC.exhibit32.htm
EX-31.2 - EXHIBIT 31.2 - SILVERBOW RESOURCES, INC.exhibit312.htm
EX-31.1 - EXHIBIT 31.1 - SILVERBOW RESOURCES, INC.exhibit311.htm
EX-23.3 - EXHIBIT 23.3 - SILVERBOW RESOURCES, INC.exhibit233.htm
EX-23.2 - EXHIBIT 23.2 - SILVERBOW RESOURCES, INC.exhibit232.htm
EX-23.1 - EXHIBIT 23.1 - SILVERBOW RESOURCES, INC.exhibit231.htm
EX-21 - EXHIBIT 21 - SILVERBOW RESOURCES, INC.exhibit21.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2016

Commission File Number 1-8754
logo03.jpg
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State of Incorporation)
20-3940661
(I.R.S. Employer Identification No.)
 
 
575 North Dairy Ashford, Suite 1200
Houston, Texas 77079
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:

Title of Class
Exchanges on Which Registered:
Common Stock, par value $.01 per share
OTCQX Best Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
o
No
þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes
o
No
þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.
Yes
þ
No
o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
þ
No
o



1


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
 
Accelerated filer
þ
 
Non-accelerated filer
 o
 
Smaller reporting company
 o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
o
No
þ

The aggregate public float of common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as quoted on the OTCQX Market as of June 30, 2016, the last business day of June 2016, was approximately $124,874,291.

The number of shares of common stock outstanding as of February 24, 2017 was 11,465,688.



2


Form 10-K
Swift Energy Company and Subsidiaries

10-K Part and Item No.
Part I
 
Page
 
 
 
Items 1 & 2
Business and Properties
 
 
 
Item 1A.
Risk Factors
 15
 
 
 
Item 1B.
Unresolved Staff Comments
 
 
 
Item 3.
Legal Proceedings
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
Part II
 
 
 
 
 
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
 
 
Item 6.
Selected Financial Data
 
 
 
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
Item 8.
Financial Statements and Supplementary Data
 
 
 
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
 
 
Item 9A.
Controls and Procedures
 
 
 
Item 9B.
Other Information
 
 
 
Part III
 
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
 
 
 
Item 11.
Executive Compensation
 
 
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
 
 
 
Item 13.
Certain Relationships and Related Transactions, and Director Independence
 
 
 
Item 14.
Principal Accountant Fees and Services
 
 
 
Part IV
 
 
 
 
 
Item 15.
Exhibits and Financial Statement Schedules
 
 
 




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Items 1 and 2. Business and Properties

As used in this Annual Report on Form 10-K, unless the context otherwise requires or indicates, references to “Swift Energy,” “the Company,” “we,” “our,” “ours” and “us” refer to Swift Energy Company. See pages 26 and 27 for explanations of abbreviations and terms used herein.

Overview

Swift Energy Company is an independent oil and gas company engaged in developing, exploring, acquiring, and operating oil and gas properties. Our primary focus is on the Eagle Ford trend of South Texas. We operate essentially all of the properties that we own and we have implemented leading edge technologies to maximize the discovery, development and production of our potential reserve base in the Eagle Ford and other geological trends where we operate. As a result of the significant resource potential from our properties in the Eagle Ford, we plan to invest nearly all of our total 2017 planned capital expenditures in this area.

At December 31, 2016, we had estimated proved reserves of 124.0 MMBoe with Standardized Measure of $407 million and PV-10 Value of $442 million (PV-10 Value is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” of this Form 10-K for a reconciliation of this non-GAAP measure to the standardized measure of discounted future net cash flows, the closest GAAP measure). This is an increase of approximately 54 MMBoe from year-end 2015 proved reserves quantities due to additions of undeveloped reserves which were previously not included in our year-end 2015 proved reserves because of the uncertainties surrounding the availability of the financing that would be necessary to develop them, due in part to our bankruptcy filing. This increase was partially offset by the loss of proved reserves from the sale of our Louisiana and other properties. Our total proved reserves at December 31, 2016 were approximately 5% crude oil, 84% natural gas, and 11% NGLs while 51% of our total proved reserves were developed. All of our proved reserves are located in Texas.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On December 31, 2015, we and eight of our 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"). 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. For a further description of these matters, see Note 1A in this Form 10-K in our Consolidated Financial Statements.

Business Strategy

Our business strategy is primarily focused on exploiting our unconventional reserves from our Fasken and other Eagle Ford fields.

Develop our Eagle Ford shale resource play. We have a long successful history operating oil and gas wells and finding reserves in South Texas. We first acquired producing Olmos properties in our AWP field in 1989. This area has remained a cornerstone of our operations since we first began drilling here in 1994. While the combination of proven drilling and completion technologies have allowed us to exploit the Eagle Ford shale, we have applied the same methods to further develop the “mature” Olmos sand. The application of horizontal drilling and multi-stage hydraulic fracturing technology has resulted in increases in production and decreases in completion and operating costs in our South Texas Olmos and Eagle Ford operations. Focusing on the Eagle Ford play allows us to use our operating, technical and regional expertise to interpret geological and operating trends, enhance production rates and maximize well recovery. We are focused on enhancing the value of our assets through operating improvements that utilize cost-effective technology to locate the highest quality intervals to drill and complete oil and gas wells. For instance, we are using proprietary 3D seismic techniques to identify a narrow high quality interval of the lower Eagle Ford within which to steer our laterals, resulting in marked improvement in our recent well results. Our 2017 plans include completing nine wells in our Fasken field in Webb County, drilling and completing two wells in our AWP acreage in McMullen County, and drilling and completing our first well in Oro Grande in LaSalle County.

Operate our properties as a low-cost producer. We believe our concentrated acreage position in the Eagle Ford and our experience as an operator of virtually all of our properties enables us to apply drilling and completion techniques and

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economies of scale that improve the returns that we are able to achieve. Operating control allows us to better manage timing and risk as well as the cost of infrastructure, drilling and ongoing operations. We generally drill multiple wells from a single pad, which reduces facilities costs and surface impact. Our operational control is critical to us being able to transfer successful drilling and completion techniques from one field to another.
 
Experienced technical team. We employ 19 oil and gas technical professionals, including geophysicists, geologists, drilling production and reservoir engineers, and other oil and gas professionals who have an average of approximately 21 years of experience in their technical fields and have been employed by us for an average of approximately eight years. In addition, we engage experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations.


5


Operating Areas

Our operations are focused in three fields located in South Texas. The following table sets forth information regarding our 2016 year-end proved reserves of 124.0 MMBoe and production of 9.2 MMBoe by area:
Fields
 
Proved Developed Reserves (MMBoe)
 
Proved Undeveloped Reserves
(MMBoe)
 
Total Proved Reserves
(MMBoe)
 
% of Total Proved Reserves
 
Oil and
NGLs as % of Proved Reserves
 
Total
Production (MBoe)
Artesia Wells
 
5.0

 
7.4

 
12.4

 
10.0
%
 
52.0
%
 
741

AWP
 
19.4

 
17.1

 
36.5

 
29.4
%
 
35.7
%
 
2,930

Fasken
 
38.5

 
36.4

 
74.9

 
60.4
%
 
%
 
4,675

Other (1)
 
0.2

 

 
0.2

 
0.2
%
 
23.0
%
 
826

Total
 
63.1

 
60.9

 
124.0

 
100.0
%
 
15.7
%
 
9,172

(1) Primarily fields sold during the year including our former Lake Washington, South Bearhead Creek and Burr Ferry fields.


Fasken During 2016, the Company completed 11 wells in Fasken targeting the Eagle Ford formation. All wells in this field are operated by Swift Energy. Our reserves in this Eagle Ford formation are 100% natural gas. At December 31, 2016, we had 4 wells that were drilled and waiting on completion and we were in the process of drilling an additional 5 well pad to be completed in 2017.

AWP All wells in this field are operated by Swift Energy. Our proved reserves are in the Olmos and lower Eagle Ford formations. Our reserves in the Eagle Ford formation are 65% natural gas, 25% NGLs, and 9% oil on a Boe basis while our reserves in the Olmos formation are approximately 61% natural gas, 28% NGLs, and 11% oil on a Boe basis.

Artesia Wells Our December 31, 2016 proved reserves in this formation are 48% natural gas, 34% NGLs, and 18% oil on a Boe basis.

Other The Company completed a series of transactions that resulted in the disposition of virtually all of our producing fields in Louisiana and non-core Texas properties during 2016. The Company retained the abandonment obligations for its Bay de Chene Field in Louisiana. All wells in this field are currently shut in. See Note 10 of the consolidated financial statements in this Form 10-K for further discussion of these transactions.

Oil and Natural Gas Reserves

The following tables present information regarding proved reserves of oil and natural gas attributable to our interests in producing properties as of December 31, 2016, 2015 and 2014. The information set forth in the tables regarding reserves is based on proved reserves reports prepared in accordance with SEC rules. H.J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers, prepared our proved reserves report as of December 31, 2016 and audited 99% and 97% of our proved reserves as of December 31, 2015 and 2014, respectively. Our 2015 and 2014 reserves reports were prepared internally under the supervision of our Chief Reservoir Engineer. The 2015 and 2014 reserves audits by H.J. Gruy and Associates, Inc. conformed to the meaning of the term “reserves audit” as presented in Regulation S-K, Item 1202. Reserve data used for interim reporting periods was prepared internally and was not audited.

The reserves estimation process involves members of the reserves and evaluation department who report to the Chief Reservoir Engineer. The staff includes engineers whose duty is to prepare estimates of reserves in accordance with the Commission's rules, regulations and guidelines. This team worked closely with H. J. Gruy and Associates to ensure the accuracy and completeness of the data utilized for the preparation of the 2016 reserve report. All information from our secure engineering database as well as geographic maps, well logs, production tests and other pertinent data was provided to the external engineers.

The Chief Reservoir Engineer supervises this process with multiple levels of review and reconciliation of reserves estimates to ensure they conform to SEC guidelines. Reserves data is also reported to and reviewed by senior management quarterly. The Board of Directors reviews the reserve data periodically and the independent Board members meet with H.J. Gruy and Associates, Inc. in executive session at least annually.

The technical person at H.J. Gruy and Associates, Inc. primarily responsible for overseeing preparation of the 2016 reserves report and the audits of prior year reports, is a Licensed Professional Engineer, holds a degree in petroleum engineering, is past

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Chairman of the Gulf Coast Section of the Society of Petroleum Engineers, is past President of the Society of Petroleum Evaluation Engineers and has over 30 years of experience in preparing reserves reports and overseeing reserves audits.

Our Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of our 2016 reserves estimates, holds a bachelor's degree in geology, is a member of the Society of Petroleum Engineers and the Society of Professional Well Log Analysts, and has over 25 years of experience in petrophysical analysis, reservoir engineering, and reserves estimation.

Estimates of future net revenues from our proved reserves, Standardized Measure and PV-10 (PV-10 is a non-GAAP measure defined below), as of December 31, 2016, 2015 and 2014 are made in accordance with SEC criteria, which is based on the preceding 12-months' average adjusted price after differentials based on closing prices on the first business day of each month, excluding the effects of hedging and are held constant, for that year's reserves calculation, throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of natural gas contracts, the use of fixed and determinable contractual price escalations. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following tables.

The following prices are used to estimate our SEC proved reserve volumes, year-end Standardized Measure and PV-10. The 12-month 2016 average adjusted prices after differentials 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 2015 and $4.32 per Mcf of natural gas, $93.64 per barrel of oil, and $33.00 per barrel of NGL for 2014.

As noted above, PV-10 Value is a non-GAAP measure. The most directly comparable GAAP measure to the PV-10 Value is the Standardized Measure. We believe the PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific properties without regard to the owner's income tax position. We use the PV-10 Value for comparison against our debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment in our oil and gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our proved oil and natural gas reserves.

The following table provides a reconciliation between the Standardized Measure and PV-10 Value of the Company's proved reserves.
 
As of December 31,
(in millions)
2016
 
2015
 
2014
Standardized Measure of Discounted Future Net Cash Flows
$
407

 
$
374

 
$
1,652

Future income taxes (discounted at 10%)
35

 

 
292

PV-10 Value
$
442

 
$
374

 
$
1,944


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The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC and presented on a Standardized Measure and PV-10 basis as of December 31, 2016, 2015 and 2014. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues.

At December 31, 2016, we had estimated proved reserves of 124.0 MMBoe with a Standardized Measure of $407 million and PV-10 Value of $442 million. This is a net increase of approximately 54 MMBoe from year-end 2015 proved reserves 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. This increase was partially offset by the loss of proved reserves resulting from the sale of our Louisiana and other properties. Our total proved reserves at December 31, 2016 were approximately 5% crude oil, 84% natural gas, and 11% NGLs, while 51% of our total proved reserves were developed. All of our proved reserves are located in Texas. The following amounts shown in MBoe below are based on a natural gas conversion factor of 6 Mcf to 1 Boe:
Estimated Proved Natural Gas, Oil and NGL Reserves
 
As of December 31,
 
 
2016
 
2015
 
2014
Natural gas reserves (MMcf):
 
 
 
 
 
 
   Proved developed
 
312,125

 
238,356

 
232,807

   Proved undeveloped (3)
 
314,664

 
73,332

 
453,940

      Total
 
626,789

 
311,688

 
686,747

Oil reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
4,513

 
10,109

 
14,989

   Proved undeveloped (3)
 
1,265

 

 
34,717

      Total
 
5,778

 
10,109

 
49,706

NGL reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
6,505

 
6,500

 
12,495

   Proved undeveloped (3)
 
7,209

 
1,716

 
17,168

      Total
 
13,714

 
8,216

 
29,663

 
 
 
 
 
 
 
Total Estimated Reserves (MBoe) (1)(3)
 
123,957

 
70,273

 
193,826

 
 
 
 
 
 
 
Standardized Measure of Discounted Future Net Cash Flows (in millions) (2)
 
$
407

 
$
374

 
$
1,652

 
 
 
 
 
 
 
PV-10 by reserve category
 
 
 
 
 
 
Proved developed
 
$
252

 
$
321

 
$
954

Proved undeveloped
 
190

 
53

 
990

Total PV-10 Value (2)
 
$
442

 
$
374

 
$
1,944


(1) The reserve volumes exclude natural gas consumed in operations.
(2) The Standardized Measure and PV-10 Values as of December 31, 2016, 2015 and 2014 are net of $33.1 million, $57.8 million and $85.5 million of plugging and abandonment costs, respectively.
(3) The decrease in 2015 reserves volumes was due to the impact of 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.

Proved reserves are estimates of hydrocarbons to be recovered in the future. Reserves estimation is a subjective process of estimating the sizes of underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and natural gas reserves.



8


Proved Undeveloped Reserves

The following table sets forth the aging of our proved undeveloped reserves as of December 31, 2016:
Year Added
 
Volume
(MMBoe)
 
% of PUD
Volumes
2016 (1)
 
60.9
 
100
%
2015
 
0.0
 
%
2014
 
0.0
 
%
2013
 
0.0
 
%
2012
 
0.0
 
%
Total
 
60.9
 
100
%
(1) The Company did not carry proved undeveloped reserves forward through bankruptcy except for locations that were converted to developed reserves early in 2016, therefore all proved undeveloped reserves were 2016 additions.

During 2016, our proved undeveloped reserves increased by approximately 47 MMBoe 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 2015 undeveloped reserves which were converted to proved developed reserves during 2016. We also incurred approximately $29 million in capital expenditures during the year which resulted in the conversion of 14 MMBoe of our December 31, 2015 proved undeveloped reserves to proved developed reserves, primarily in the Fasken field.

The PV-10 Value from our proved undeveloped reserves was $190 million at December 31, 2016, which was approximately 43% of our total PV-10 Value of $442 million. The PV-10 Value of our proved undeveloped reserves, by year of booking was 100% in 2016.

Sensitivity of Reserves to Pricing

As of December 31, 2016, a 5% increase in oil and NGL pricing would increase our total estimated proved reserves of 124.0 MMBoe by approximately 0.4 MMBoe, and would increase the PV-10 Value of $442 million by approximately $12 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.4 MMBoe and would decrease the PV-10 Value by approximately $12 million.

As of December 31, 2016, a 5% increase in natural gas pricing would increase our total estimated proved reserves by approximately 0.7 MMBoe and would increase the PV-10 Value by approximately $37 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated proved reserves by approximately 0.7 MMBoe and would decrease the PV-10 Value by approximately $37 million.


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Oil and Gas Wells

The following table sets forth the total gross and net wells in which we owned an interest at the following dates:
 
Oil Wells
 
Gas Wells
 
Total
Wells(1)
December 31, 2016
 
 
 
 
 
Gross
175

 
604

 
779

Net
172.1

 
558.7

 
730.8

December 31, 2015
 
 
 
 
 
Gross
327

 
729

 
1,056

Net
308.9

 
682.7

 
991.6

December 31, 2014
 
 
 
 
 
Gross
348

 
717

 
1,065

Net
330.3

 
673.9

 
1,004.2


(1)
Excludes 9, 48 and 49 service wells in 2016, 2015 and 2014.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2016:
 
Developed
 
Undeveloped
 
Gross
 
Net
 
Gross
 
Net
Texas (1)
63,054

 
58,970

 
32,249

 
30,605

Colorado(2)

 

 
30,897

 
29,971

Louisiana (3)
5,084

 
4,775

 
4,920

 
4,478

Wyoming

 

 
3,092

 
1,521

Total
68,138

 
63,745

 
71,158

 
66,575


(1)
In South Texas a substantial portion of our Eagle Ford and Olmos acreage overlaps. In most cases the Eagle Ford and Olmos rights are contracted under separate lease agreements. For the purposes of the above table, a surface acre where we have leased both the Eagle Ford and Olmos rights is counted as a single acre. Acreage which is developed in any formation is counted in the developed acreage above, even though there may also be undeveloped acreage in other formations. In the Eagle Ford, we have 38,254 gross and 30,874 net developed acres and 35,435 gross and 33,511 net undeveloped acres. A large portion of our undeveloped Eagle Ford acreage underlies developed Olmos acreage. In the Olmos, we have 44,812 gross and 41,700 net developed acres and 17,444 gross and 15,377 net undeveloped acres.
(2)
The Company's leasehold acreage in Colorado is exploration property which is evaluated, inactive and will expire in 2017 and 2018 unless otherwise drilled, sold or farmed out.
(3)
The above table includes acreage where Swift Energy is the fee mineral owner as well as a working interest owner. This fee mineral acreage included in the above table totals 3,644 gross and 1,535 net undeveloped acres and 942 gross and 532 net developed acres.

As of December 31, 2016, Swift Energy's net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 54% in 2017, 31% in 2018 and 6% in 2019. In most cases, acreage scheduled to expire can be held through drilling operations or we can exercise extension options. As of February 27, 2017, 3,155 net undeveloped acres have expired during 2017. The exploration potential of all undeveloped acreage is fully evaluated before expiration. In each fiscal year where undeveloped acreage is subject to expiration (except for Colorado acreage) our intent is to reduce the expirations through either development or extensions, if we believe it is commercially advantageous to do so.


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Drilling and Other Exploratory and Development Activities

The following table sets forth the results of our drilling activities during the years ended December 31, 2016, 2015 and 2014:
 
 
 
 
Gross Wells
 
Net Wells
Year
 
Type of Well
 
Total
 
Producing
 
Dry
 
Total
 
Producing
 
Dry
2016
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
8

 
8

 

 
5.1

 
5.1

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
24

 
24

 

 
17.1

 
17.1

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
36

 
36

 

 
31.5

 
31.5

 


Recent Activities

As of December 31, 2016, we were in the process of drilling five wells in our Fasken field where we have a 64% working interest. In the first quarter of 2017, we have begun the process of conducting completion operations for 3 wells (approximately 2 net wells) drilled during the fourth quarter of 2016. In addition, we have initiated production on 4 wells that were drilled and completed in the fourth quarter of 2016.

Operations

We generally seek to be the operator of the wells in which we have a significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide this equipment and personnel. We employ drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and natural gas properties.

Operations on our oil and natural gas properties are customarily accounted for in accordance with Council of Petroleum Accountants Societies' guidelines. We charge a monthly per-well supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or natural gas. The fees for these activities for the period of April 23, 2016 through December 31, 2016 (successor) and the period of January 1, 2016 through April 22, 2016 (predecessor) totaled $4.5 million and $2.7 million, respectively, and ranged from $242 to $2,029 per well per month.

Marketing of Production

We typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We usually sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. 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 the year ended December 31, 2015 (predecessor), respectively, and did not account for sales proceeds above 10% for the period of April 23, 2016 through December 31, 2016 (successor) or the year ended December 31, 2014 (predecessor). Southcross Energy accounted for approximately 11% of our sales proceeds during the period of January 1, 2016 through April 22, 2016 (predecessor) and did not account for sales proceeds above 10% during the period of April 23, 2016 through December 31, 2016 (successor) or the years ended December 31, 2015 and 2014 (predecessor).


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We have gas processing and gathering agreements with Southcross Energy for a majority of our natural gas production in the AWP area. Other gas production in the AWP area is processed or transported under arrangements with DCP Midstream and Enterprise Products. Oil production is transported to market by truck and sold at prevailing market prices.

We have a gas gathering agreement with Howard Energy providing for the transportation of our Eagle Ford production on the pipeline from Fasken to Kinder Morgan Texas Pipeline or Eagle Ford Midstream, where it is sold at prices tied to monthly and daily natural gas price indices. At Fasken, we also have a connection with the Navarro gathering system into which we may deliver natural gas from time to time.

We have an agreement with Eagle Ford Gathering LLC that provides for the gathering and processing for almost all of our natural gas production in the Artesia Wells area. Natural gas in the area can also be delivered to the Targa (formerly Atlas) system for processing and transportation to downstream markets. In the Artesia Wells area, our oil production is sold at prevailing market prices and transported to market by truck.

Prior to our disposition of the field, oil production from Lake Washington was either delivered into ExxonMobil's crude oil pipeline system or transported on barges for sales to various purchasers at prevailing market prices. Historically, our natural gas production from this field was either consumed on the lease or was delivered to High Point Gas Transmission (successor to El Paso's Southern Natural Gas Company) pipeline system and the processing of natural gas occurred at the Toca Plant.

The prices in the tables below do not include the effects of hedging. Quarterly prices are detailed under “Results of Operations – Revenues” in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K.

The following table summarizes sales volumes, sales prices, and production cost information for our net oil, NGL and natural gas production 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).

 
 
Successor
 
 
Predecessor
 
 
Period from April 23, 2016 through December 31, 2016
 
 
Period from January 1, 2016 through April 22, 2016
 
Year Ended December 31,
All Fields
 
 
 
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
 
 
 
   Oil (MBbls)
 
786

 
 
522

 
2,406

 
3,511

   Natural Gas Liquids (MBbls)
 
727

 
 
380

 
1,433

 
1,812

Natural gas (MMcf)
 
29,109

 
 
11,431

 
43,839

 
37,685

      Total (MBoe)
 
6,365

 
 
2,807

 
11,146

 
11,604

 
 
 
 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
 
 
 
   Oil (Per Bbl)
 
$
44.79

 
 
$
31.43

 
$
47.11

 
$
92.74

   Natural Gas Liquids (Per Bbl)
 
$
16.39

 
 
$
11.04

 
$
14.54

 
$
31.83

   Natural gas (Per Mcf)
 
$
2.55

 
 
$
1.96

 
$
2.56

 
$
4.36

   Total (Per Boe)
 
$
19.07

 
 
$
15.33

 
$
22.09

 
$
47.20

 
 
 
 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (1)
 
$
6.01

 
 
$
7.57

 
$
8.25

 
$
9.85


(1) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.


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The following table provides a summary of our sales volumes, average sales prices, and average production costs for our fields with proved reserves greater than 15% of total proved reserves. These fields account for approximately 90% of the Company's proved reserves based on total Boe as of December 31, 2016:
 
 
Successor
 
 
Predecessor
 
 
Period from April 23, 2016 through December 31, 2016
 
 
Period from January 1, 2016 through April 22, 2016
 
Year Ended December 31,
Fasken
 
 
 
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
 
 
 
   Natural Gas Liquids (MBbls)
 
1

 
 
1

 
2

 
3

   Natural gas (MMcf) (1)
 
20,762

 
 
7,274

 
28,598

 
21,080

      Total (MBoe)
 
3,462

 
 
1,213

 
4,768

 
3,516

 
 
 
 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
 
 
 
   Natural Gas Liquids (Per Bbl)
 
$
14.09

 
 
$
3.87

 
$
16.65

 
$
32.44

   Natural gas (Per Mcf)
 
$
2.55

 
 
$
1.96

 
$
2.53

 
$
4.14

   Total (Per Boe)
 
$
15.30

 
 
$
11.77

 
$
15.16

 
$
24.84

 
 
 
 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
3.34

 
 
$
3.47

 
$
3.20

 
$
3.70


(1) Excludes natural gas consumed in operations.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.

 
 
Successor
 
 
Predecessor
 
 
Period from April 23, 2016 through December 31, 2016
 
 
Period from January 1, 2016 through April 22, 2016
 
Year Ended December 31,
AWP
 
 
 
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
 
 
 
   Oil (MBbls)
 
388

 
 
206

 
1,047

 
1,655

   Natural Gas Liquids (MBbls)
 
519

 
 
235

 
843

 
968

   Natural gas (MMcf) (1)
 
6,438

 
 
3,061

 
10,372

 
10,057

Total (MBoe)
 
1,980

 
 
951

 
3,618

 
4,299

 
 
 
 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
 
 
 
   Oil (Per Bbl)
 
$
44.54

 
 
$
30.07

 
$
45.37

 
$
89.86

   Natural Gas Liquids (Per Bbl)
 
$
16.32

 
 
$
11.31

 
$
14.79

 
$
30.72

   Natural gas (Per Mcf)
 
$
2.59

 
 
$
1.90

 
$
2.62

 
$
4.61

   Total (Per Boe)
 
$
21.41

 
 
$
15.43

 
$
24.08

 
$
52.29

 
 
 
 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
6.20

 
 
$
7.85

 
$
8.64

 
$
9.23


(1) Excludes natural gas consumed in operations.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.


Risk Management

Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, fires, and adverse weather conditions, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil spills, natural gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. We maintain comprehensive insurance coverage, including general liability insurance, operators extra expense insurance, and property damage insurance. Our standing Insurable Risk Advisory Team, which includes individuals from operations, drilling,

13


facilities, legal, HSE and finance meets regularly to evaluate risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect us. Refer to “Item 1A. Risk Factors” of this Form 10-K for more details and for discussion of other risks.

Commodity Risk

The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The Company has derivative instruments in place to protect a significant portion of our production against declines in oil and natural gas prices through the first quarter of 2018. For additional discussion related to our price-risk policy, refer to Note 6 of the consolidated financial statements in this Form 10-K.

Competition

We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and natural gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Our ability to replace and expand our reserves base depends on our continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling and acquisition.

Employees

As of December 31, 2016, the Company employed 151 people. The Company is currently implementing a reduction-in-force under the Worker Adjustment and Retraining Notification ("WARN") Act. We expect to have slightly fewer than 100 employees after March 2017, which will be a result of the completion of the reduction-in-force and other unrelated terminations that have occurred since December 31, 2016. None of our employees were represented by a union and relations with employees are considered to be good.

Facilities

Prior to December 31, 2016, we executed a sub-lease agreement for 27,259 square feet of new office space at 575 N. Dairy Ashford Road, Houston, Texas. We relocated our headquarters to this location in January 2017. For discussion regarding the term and obligations of this sub-lease refer to Note 7 of the consolidated financial statements in this Form 10-K.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports, changes in and stock ownership of our directors and executive officers, together with other documents filed with the Securities and Exchange Commission under the Securities Exchange Act can be accessed free of charge on our web site at www.swiftenergy.com as soon as reasonably practicable after we electronically file these reports with the SEC. All exhibits and supplemental schedules to these reports are available free of charge through the SEC web site at www.sec.gov. In addition, we have adopted a Code of Ethics for Senior Financial Officers and the Principal Executive Officers. We have posted this Code of Ethics on our website, where we also intend to post any waivers from or amendments to this Code of Ethics.


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Item 1A. Risk Factors

Risks Related to our Emergence from Chapter 11 Bankruptcy

We emerged from bankruptcy on April 22, 2016, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:

key suppliers could terminate their relationship or require financial assurances or enhanced performance;
the ability to renew existing contracts and compete for new business may be adversely affected;
the ability to attract, motivate and/or retain key executives and employees may be adversely affected;
employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy will not be comparable to our historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, our future financial conditions and results of operations will not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

There is a limited trading market for our securities and the market price of our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued new common stock. Our common stock is currently quoted on the OTCQX Market. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the plan of reorganization, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part II, Item 1A of this Report. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

15



The Company entered into an agreement with certain purchasers of our common stock in a recent private placement offering to list on a national securities exchange by July 25, 2017. However, no assurances can be given regarding the Company’s ability to meet this deadline.

Upon our emergence from bankruptcy, the composition of our Board of Directors and our stockholders changed significantly.

Pursuant to the plan of reorganization, the composition of the Board and our stockholders changed significantly. The Board is now made up of six directors, none of whom served on the Board prior to emergence from bankruptcy. Our directors are also in large part nominated pursuant to a director nomination agreement among the Company and many of our large institutional stockholders that previously owned our unsecured high yield senior notes and received our common stock pursuant to the plan of reorganization. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.


There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with Strategic Value Partners LLC, ("SVP") and DW Partners, LP (“DW”) currently own approximately 38.9% and 14.4%, respectively, of our outstanding common stock. SVP currently has a right to nominate two of our directors under our director nominating agreement. DW, together with other former noteholders who received our common stock pursuant to our plan of reorganization, collectively hold the current right to nominate two additional directors. Our current board is limited to seven directors under the terms of the director nomination agreement. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. Furthermore, we have entered into a director nomination agreement with each of SVP, DW and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We do not expect to pay dividends in the near future.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

A small number of institutional investors controls significant percentage of our voting power and possess negative control or veto rights with respect to certain proposed Company transactions

A small group of institutional investors, who are parties to our director nomination agreement currently, beneficially own a percentage majority of our issued and outstanding common stock. Consequently, such investors are able to strongly influence all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents and approval of acquisition offers and other significant corporate transactions. This concentration of ownership limits our other stockholders’ ability to influence corporate matters. In addition, the institutional holders that are parties to the director nomination agreement possess negative control or veto rights under the Company’s Certificate of Incorporation with respect to certain transactions the Company may propose to undertake for so long as such parties collectively hold 50% or more of the Company’s issued and outstanding shares of common stock. Such parties are entitled to notice of certain proposed transactions which may be vetoed if such parties who collectively hold at least 50% of the issued and outstanding shares of common stock object to such action. These transactions the veto rights of the parties to the director nomination agreement include:

the sale or other disposition of assets of the Company or any of its subsidiaries, in any single transaction or series of related transactions, with a fair market value in the aggregate in excess of $75 million, other than certain intercompany ordinary course transactions;
any sale, recapitalization, liquidation, dissolution, winding up, bankruptcy event, reorganization, consolidation, or merger of the Company or any of its subsidiaries;

16


issuing or repurchasing any shares of our common stock or other equity securities (or securities convertible into or exercisable for equity securities) in an amount that is in the aggregate in excess of $5 million, other than pursuant to employee benefit and incentive plans (including certain repurchases of capital stock to satisfy withholding or similar taxes in connection with any exercise of equity rights) and the issuance of shares of common stock upon exercise of our outstanding warrants;
incurring any indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another person or entity), in any single transaction or series of related transactions, that is in the aggregate in excess of $75 million other than indebtedness incurred to refinance indebtedness issued for less than $75 million, intercompany indebtedness, and certain other obligations incurred in the ordinary course of business;
entering into any proposed transaction or series of related transactions involving a “Change of Control” of the Company (for purposes of this provision, “Change of Control” shall mean any transaction resulting in any person or group (as such terms are defined in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934) acquiring “beneficial ownership” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934) of more than 50% of the total outstanding equity interests of the Company (measured by voting power rather than number of shares);
entering into or consummating any material acquisition of businesses, companies or assets (whether through sales or leases) or joint ventures, in any single transaction or series of related transactions, in the aggregate in excess of $75 million;
increasing or decreasing the size of the Board;
amending the Certificate of Incorporation or the Bylaws of the Company; or
entering into any arrangements or transactions with affiliates of the Company.

Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation (the “Charter”) and our Bylaws and our existing director nomination agreement may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws and our existing director nomination agreement include, among other things, those that:

provide for a classified board of directors;
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;
provide SVP and certain other institutional stockholders the right to nominate up to four of our directors;
limit the persons who may call special meetings of stockholders; and
provide veto rights to certain stockholders as detailed in our Charter, including any transaction that may constitute a change of control, as defined in the Charter.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management. Furthermore, we have entered into a director nomination agreement with each of SVP, DW and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.


17


Risks Related to the Business:

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.

Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, oil and gas prices declined severely during 2015 with continued lower prices through 2016. The WTI crude oil price per barrel for the period from October 1, 2014 to December 31, 2016 ranged from a high of $91.02 to a low of $26.19, a decrease of 66.8%, and the NYMEX natural gas price per MMBtu for the period October 1, 2014 to December 31, 2016 ranged from a high of $4.41 to a low of $1.49, a decrease of 66.2%. As of December 31, 2016, the spot market price for WTI was $53.75 while the spot market price for natural gas was $3.71. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

domestic and foreign supplies of oil and natural gas;
price and quantity of foreign imports of oil and natural gas;
actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;
level of consumer product demand, including as a result of competition from alternative energy sources;
level of global oil and natural gas exploration and production activity;
domestic and foreign governmental regulations;
level of global oil and natural gas inventories;
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, Africa and Russia;
weather conditions;
technological advances affecting oil and natural gas production and consumption;
overall U.S. and global economic conditions; and
price and availability of alternative fuels.

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. The speed and severity of the decline in oil prices during our 2015 fiscal year and the continued lower prices through 2016 has materially affected our results of operations and our estimates of our proved oil and natural gas reserves. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position, the quantities of oil and natural gas reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds through the capital markets, if they are available at all.

Insufficient capital could lead to declines in our cash flow or in our oil and natural gas reserves, or a loss of properties.

The oil and natural gas industry is capital intensive. Our 2017 capital expenditure budget, including expenditures for leasehold acquisitions, drilling and infrastructure and fulfillment of abandonment obligations is expected to be in the range of $85.0 million and $95.0 million. Cash flow from operations is a principal source of our financing of our future capital expenditures. Insufficient cash flow from operations and inability to access capital could lead to losing leases that require us to drill new wells in order to maintain the lease. Lower liquidity and other capital constraints may make it difficult to drill those wells prior to the lease expiration dates, which could result in our losing reserves and production.

Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established or we exercise an extension option on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties.  We have leases on 71,158 gross acres (66,575 net acres) that could potentially expire during fiscal year 2017, representing approximately 54% of our net undeveloped acreage.

Our drilling plans for areas not currently held by production are subject to change based upon various factors.  Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.  On our acreage that we do not operate, we have less control over the timing of drilling; therefore there is additional risk of expirations occurring in those sections.

18



If low commodity prices continue for an extended period, our liquidity would be significantly reduced.

While substantially all of our $906 million of long-term unsecured indebtedness was discharged upon confirmation of our Plan, we will continue to have substantial capital needs following our emergence from bankruptcy, including in connection with our existing secured indebtedness and the continued development of our operations. As a result, we will need additional capital in the future to fund our operations, implement our business plan and fulfill our abandonment obligations. An extended period of low commodity prices would substantially reduce our cash flows and would likely reduce liquidity to a level that would make it increasingly difficult to operate our business.

We have written down the carrying values on our oil and gas properties in 2014, 2015 and 2016 and could incur additional write-downs in the future.

The SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment (the "ceiling test"). Any capital costs in excess of the ceiling amount must be permanently written down. For the period of April 23, 2016 through December 31, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), the year ended December 31, 2015 (predecessor) and year ended December 31, 2014 (predecessor), we reported non-cash write-downs on a before-tax basis of, $133.5 million, $77.7 million, $1.6 billion ($1.5 billion after-tax) and $445.4 million ($287.3 million after-tax) respectively, on our oil and gas properties. If oil and natural gas prices decline in the future we could be required to record additional non-cash write-downs of our oil and gas properties. Refer to Note 2 of the consolidated financial statements in this Form 10-K for further discussion of the ceiling test calculation.

Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.

The quantities and values of our proved reserves included in our 2016 estimates of proved reserves are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates and could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. These estimates may not accurately predict the present value of future net cash flows from our oil and natural gas reserves.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect the Company’s production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. The Company is expected to use hydraulic fracturing techniques in certain of its operations. Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in 2014, the U.S. Environmental Protection Agency (“EPA”) asserted regulatory authority pursuant to the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. The EPA also issued final federal Clean Air Act (“CAA”) regulations in 2012 that include New Source Performance Standards (“NSPS”) for completions of hydraulically fractured natural gas wells, compressors, controls, dehydrators, storage tanks, natural gas processing plants, and certain other equipment. In June 2016, the EPA published final rules establishing new emissions standards for methane and additional standards for volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, and is formally seeking additional information from oil and natural gas exploration and production operators as necessary to eventually expand these final rules to include existing equipment and processes. In addition, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”) published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That decision is currently being appealed by the federal government.

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The U.S. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, certain states, including Texas, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates the Company could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. While this EPA report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, any future studies relating to hydraulic fracturing, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Our operations include the need of water for use in oil and natural gas exploration and production activities. The Company’s access to water may be limited due to reasons such as prolonged drought, private third party competition for water in localized areas, or the Company’s inability to acquire or maintain water sourcing permits or other rights. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. Any such decrease in the availability of water could adversely affect the Company’s business and financial condition and operations. Moreover, any inability by the Company to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact the Company’s exploration and production operations and have a corresponding adverse effect on the Company’s business and financial condition.

Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays that could adversely affect the Company’s production of oil and natural gas.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These disposal wells are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of produced water or certain other oilfield fluids resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and produced water disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or may have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity: Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for produced water disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission adopted similar rules for the permitting of produced water disposal

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wells in 2014. These developments could result in additional regulation and restrictions on the use of injection wells in connection with Company activities to dispose of produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in the Company having to limit disposal well volumes, disposal rates or locations, or require third party disposal well operators the Company may engage to dispose of produced water generated by Company activities to shut down disposal wells, which development could adversely affect the Company’s production or result in the Company incurring increased costs and delays with respect to Company operations.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and gas the Company produces.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish certain permits and construction reviews designed to allow operations while ensuring the Prevention of Significant Deterioration of air quality by GHG emissions from large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. The Company’s operations could become subject to these permitting requirements and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs as well as criteria pollutants from such sources. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including onshore and offshore oil and gas production facilities, which may include certain Company operations. Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors and imposing leak detection and repair requirements for natural gas compressor and booster stations. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operations in the oil and natural gas industry. The EPA has indicated that it intends to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. Once adopted, these standards would not be imposed directly on regulated entities. Instead, they would become guidelines that the states must consider in developing their own rules for regulating sources within their borders. The EPA has indicated that this information may also be used to develop standards for certain kinds of new and modified equipment and facilities not currently covered under Subpart OOOOa. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that proposed an agreement requiring member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020 (the "Paris Agreement"). The Paris Agreement was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions.

The adoption and implementation of any international, federal or state legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from the Company’s equipment and operations could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on the Company’s business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for, or lower the value of, the oil and gas the Company produces. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s operations. At this time, the Company has not developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on the Company’s operations.

A worldwide financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot control or predict.


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Global economic conditions may adversely affect the financial viability of and increase the credit risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties to perform under the terms of contracts or financial arrangements we have with them. Although we have heightened our level of scrutiny of our contractual counterparties, our assessment of the risk of non-performance by various parties is subject to sudden swings in the financial and credit markets. This same crisis may adversely impact insurers and their ability to pay current and future insurance claims that we may have.

Our future access to capital could be limited due to tightening credit markets that could affect our ability to fund our future capital projects. In addition, long-term restriction upon or freezing of the capital markets and legislation related to financial and banking reform may affect short-term or long-term liquidity.

Our oil and natural gas exploration and production business involves high risks and we may suffer uninsured losses.

These risks include blowouts, explosions, adverse weather effects and pollution and other environmental damage, any of which could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and gas industry, it is not fully insured against certain of these risks, such as business interruption, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining and carrying such insurance.

Drilling wells is speculative and capital intensive.

Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

hurricanes, tropical storms or other natural disasters;
environmental hazards, such as natural gas leaks, oil spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
abnormally pressured formations;
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
fires and explosions; and
personal injuries and death.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.

Pollution and property contamination arising from the Company’s operations and the nearby operations of other oil and gas operators could expose the Company to significant costs and liabilities.

The performance of the Company’s operations may result in significant environmental costs and liabilities as a result of handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater or other fluid discharges related to operations, and due to historical industry operations and waste disposal practices. Spills or other unauthorized releases of regulated substances by or resulting from the Company’s operations, or the nearby operations of other oil and gas operators, could expose the Company to material losses, expenditures and liabilities under environmental laws and regulations. Certain of these laws may impose strict liability, which means that in some situations the Company could be exposed to liability as a result of the Company’s

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conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against the Company for personal injury or property damage allegedly caused by the release of pollutants into the environment. Moreover, environmental laws and regulations generally have become more stringent in recent years and are expected to continue to do so, which could result in the occurrence of delays or cancellation in the permitting or performance of new or expanded projects, or more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements. Any one or more of such developments could require the Company to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on the oil and gas exploration and production industry in general in addition to the Company’s own results of operations, competitive position or financial condition. The Company may not be able to recover some or any of its costs with respect to such developments from insurance.

Government regulation of the Company’s activities could adversely affect the Company and its operations.

The oil and gas business is subject to extensive governmental regulation under which, among other things, rates of production from oil and gas wells may be regulated. Governmental regulation also may affect the market for the Company’s production and operations. Costs of compliance with governmental regulation are significant, and the cost of compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect the results of the Company. We cannot predict the timing or impact of new or changed laws, regulations, or permit requirements or changes in the ways that such laws, regulations, or permit requirements are enforced, interpreted or administered.  For example, various governmental agencies, including the EPA and analogous state agencies, the BLM, and the Federal Energy Regulatory Commission can enact or change, begin to force compliance with, or otherwise modify their enforcement, interpretation or administration of, certain regulations that could adversely affect the Company.

The Company’s operations are subject to environmental and worker safety and health laws and regulations that may expose the Company to significant costs and liabilities and could delay the pace or restrict the scope of the Company’s operations.

The Company’s oil and gas exploration, production and development operations are subject to stringent federal, regional, state and local laws and regulations governing worker safety and health, the release or disposal of materials into the environment or otherwise relating to environmental protection. Numerous governmental entities, including the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations, which may require the Company to take actions resulting in costly capital and operating expenditures at its wells and properties. These laws and regulations may restrict or affect the Company’s business in many ways, including applying specific health and safety criteria addressing worker protection, requiring the acquisition of a permit before drilling or other regulated activities commence, restricting the types, quantities and concentration of substances that can be released into the environment, limiting or prohibiting construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and imposing substantial liabilities for pollution resulting from the Company’s operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigative, remedial or corrective action obligations, the occurrence of delays in the permitting or development or expansion of projects, and the issuance of orders enjoining performance of some or all of the Company’s operations in a particular area.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and changes in environmental laws and regulations or re-interpretation of enforcement policies may result in increased costs and liabilities, delays or restrictions in the Company’s operations. For example, during October 2015, the EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017, and states may implement more stringent regulations, which could apply to the Company’s operations. In a second example, in May of 2015, the EPA released a final rule outlining its position on federal jurisdiction over waters of the United States under the Federal Water Pollution Control Act. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts considered lawsuits opposing implementation of the rule. Litigation surrounding this rule is on-going. Any expansion to the Federal Water Pollution Control Act jurisdiction in areas where Company’s operations are conducted could, among other things, require installation of new emission controls on some of the Company’s equipment, result in longer permitting timelines, and increase the Company’s capital expenditures and operating costs, which could adversely impact the Company’s business. In a third example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its Resource Conservation and Recovery Act (“RCRA”) Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination

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that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the Company’s costs to manage and dispose of wastes generated from its operations, which could effect on the Company’s operations and financial position. The Company may be unable to pass on increased compliance costs arising out of its activities as a result of these developments to its customers.
Laws and regulations pertaining to threatened and endangered species or protective of environmentally sensitive areas could delay or restrict the Company’s operations and cause it to incur substantial costs.

The Company’s activities may be adversely affected by seasonal or permanent restrictions or costly mitigation measures imposed under various federal and state statutes in order to protect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. Federal statutes, as amended from time to time, that are protective of these species, birds and environmental sensitive areas include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”), the Federal Water Pollution Control Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, and the Oil Pollution Act of 1990. For example, to the extent that species are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where the Company’s activities are conducted, the Company’s ability to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, the Company’s activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could result in material restrictions to federal land use and private land use and could delay or prohibit land access or oil and natural gas development. Moreover, as a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous specified species as endangered or threatened under the ESA under specific timelines. The designation of previously unidentified endangered or threatened species could indirectly cause the Company to incur additional costs, cause the Company’s operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. If harm to protected species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and natural gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or time delays or limitations on the Company’s activities.

Enactment of executive, legislative or regulatory proposals under consideration could negatively affect our business.

Numerous executive, legislative and regulatory proposals affecting the oil and gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by the President, Congress, state legislatures and various federal and state agencies. Among these proposals are: (1) proposed legislation (none of which has passed) to repeal various tax deductions available to oil and gas producers as discussed in more detail below and (2) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties, grants new authority to impose damage prevention and incident notification requirements, and directs the PHMSA to prescribe minimum safety standards for CO2 pipelines.

The foregoing described proposals, including other applicable proposals, could affect our operations and the costs thereof. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on the Company, its operations, the demand for oil and natural gas, or the prices at which it can be sold. However, until such legislation or regulations are enacted or adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress

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could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows

Legal proceedings could result in liability affecting our results of operations.

Most oil and gas companies, such as us, are involved in various legal proceedings, such as title, royalty, environmental or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters, if appropriate.

Because we maintain a portfolio of assets in the various areas in which we operate, the complexity and types of legal proceedings with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business. Our technologies, systems and networks may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations, damage to our properties and/or injuries. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations.

To date we are not aware of any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber vulnerabilities.

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Item 1B. Unresolved Staff Comments

None.

Glossary of Abbreviations and Terms

The following abbreviations and terms have the indicated meanings when used in this report:

ASC - Accounting Standards Codification.
Bankruptcy Code - Refers to title 11 of the United States Code.
Bankruptcy Court - Refers to the United States Bankruptcy Court for the District of Delaware.
Bar Date - Refers to the deadline, set by the Bankruptcy Court, by which certain creditors must file proofs of claims in order to receive any distribution under the Plan.
Bbl - Barrel or barrels of oil.
Bcf - Billion cubic feet of natural gas.
Bcfe - Billion cubic feet of natural gas equivalent (see Mcfe).
Boe - Barrels of oil equivalent.
Chapter 11 - Means chapter 11 of the Bankruptcy Code.
Condensate - Liquid hydrocarbons that are found in natural gas wells and condense when brought to the well surface. Condensate is used synonymously with oil.
Developed Oil and Gas Reserves - Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods.
Development Well - A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Discovery Cost - With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions.
Dry Well - An exploratory or development well that is not a producing well.
Effective Date - The Company's date of emergence from bankruptcy April 22, 2016.
Exploratory Well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
FASB - The Financial Accounting Standards Board.
Gross Acre - An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
Gross Well - A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
MBbl - Thousand barrels of oil.
MBoe - Thousand barrels of oil equivalent.
Mcf - Thousand cubic feet of natural gas.
Mcfe - Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.
MMBbl - Million barrels of oil.
MMBoe - Million barrels of oil equivalent.
MMBtu - Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.
MMcf - Million cubic feet of natural gas.
MMcfe - Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre - A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Net Well - A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
NGL - Natural gas liquid.
OTC Pink - means OTC Pink, a centralized electronic quotation service for over-the-counter securities, operated by OTC Market Group Inc.
Petition Date - The date on which the Company and the Chapter 11 Subsidiaries filed for bankruptcy protection (December 31, 2015).
Producing Well - An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

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Proved Oil and Gas Reserves - Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. For reserves calculations economic conditions include prices based on either the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
Proved Undeveloped (PUD) Locations - A location containing proved undeveloped reserves.
PV-10 Value - The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices based on either the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. PV-10 Value is a non-GAAP measure and its use is explained under “Item 1& 2. Business and Properties - Oil and Natural Gas Reserves” above in this Form 10-K.
Standardized Measure - The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Sales prices were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date (except for consideration of price changes to the extent provided by contractual arrangements).
Undeveloped Oil and Gas Reserves - Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Item 3. Legal Proceedings

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 our 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.

Item 4. Mine Safety Disclosures

Not Applicable.


27


PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Successor Common Stock, period of April 23, 2016 through December 31, 2016

Our common stock, is quoted on the OTCQX Market under the symbol "SWTF". The high and low quarterly closing sale prices for the common stock for the period of April 23, 2016 through December 31, 2016 (successor) were as follows:
 
2016
 
Period from April 23, 2016 through June 30, 2016
Third Quarter
Fourth Quarter
Low
$22.00
$24.40
$26.77
High
$26.10
$31.00
$35.70

The high and low closing sale prices for the common stock reported on the OTCQX Market for the period of April 23, 2016 through December 31, 2016 (successor) were $22.00 and $35.70, respectively.

Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements, as discussed in Note 5 of the consolidated financial statements in this Form 10-K.

We had approximately 111 stockholders of record as of December 31, 2016.

Stock Repurchase Table

The following table summarizes repurchases of our common stock during the fourth quarter of 2016, all of which were shares withheld from employees to satisfy tax obligations arising upon the vesting of restricted shares:
Period
 
Total Number
of Shares
Purchased
 
Average Price
 Paid Per Share
 
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs
 
Approximate Dollar
Value of Shares that
May Yet Be Purchased
 Under the Plans or
Programs
(in thousands)
October 1 - 31, 2016
 
15,249

 
$
30.50

 

 
$---

November 1- 30, 2016
 
7,236

 
$
29.00

 

 

December 1 - 31, 2016
 

 
$

 

 

Total
 
22,485

 
$
30.02

 

 
$---


Equity Compensation Plan Information

For information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2016 see Note 8 of the consolidated financial statements included in this Form 10-K.


28


Item 6. Selected Financial Data
 
Successor
 
 
Predecessor
(data in thousands except per share, price and well amounts)
April 23, 2016 - December 31, 2016
 
 
January 1, 2016 - April 22, 2016
Years Ended December 31,
 
 
 
2015
2014
2013
2012
 
 
 
 
 
 
 
 
 
Total Revenues
$
101,537

 
 
$
42,782

$
244,721

$
549,456

$
584,401

$
561,486

Income (Loss) Before Income Taxes
$
(156,288
)
 
 
$
851,611

$
(1,734,514
)
$
(433,470
)
$
198

$
37,773

Net Income (Loss)
$
(156,288
)
 
 
$
851,611

$
(1,653,971
)
$
(283,427
)
$
(2,442
)
$
21,701

Net Cash Provided by Operating Activities
$
47,427

 
 
$
(41,466
)
$
42,274

$
306,371

$
311,447

$
314,606

Per Share and Share Data
 
 
 
 
 
 
 
 
Weighted Average Shares Outstanding - Basic
10,013

 
 
44,692

44,463

43,795

43,331

42,840

Earnings per Share - Basic
$
(15.61
)
 
 
$
19.06

$
(37.20
)
$
(6.47
)
$
(0.06
)
$
0.51

Earnings per Share - Diluted
$
(15.61
)
 
 
$
18.64

$
(37.20
)
$
(6.47
)
$
(0.06
)
$
0.50

 
 
 
 
 
 
 
 
 
Production (MMBoe equivalent)
6.4

 
 
2.8

11.1

11.6

11.4

11.4

 
 
 
 
 
 
 
 
 
Average Sales Price (1)
 
 
 
 
 
 
 
 
Natural Gas (per Mcf produced)
$
2.55

 
 
$
1.96

$
2.56

$
4.36

$
3.66

$
2.64

Natural Gas Liquids (per barrel)
$
16.39

 
 
$
11.04

$
14.54

$
31.83

$
31.39

$
35.07

Oil (per barrel)
$
44.79

 
 
$
31.43

$
47.11

$
92.74

$
103.42

$
106.17

Boe Equivalent
$
19.07

 
 
$
15.33

$
22.09

$
47.20

$
52.29

$
49.42

(1) These prices do not include the effects of our hedging activities which were recorded in “Price-risk management and other, net” on the consolidated statements of operations included in this Form 10-K.

29


 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31,
Balance Sheet Data
 
 
2015
2014
2013
2012
Assets
 
 
 
 
 
 
 
Current Assets
$
21,479

 
 
$
61,847

$
64,669

$
92,489

$
87,005

Property & Equipment, Net of Accumulated Depreciation, Depletion, and Amortization
347,195

 
 
457,903

2,095,037

2,588,817

2,367,954

Total Assets
377,299

 
 
524,998

2,173,347

2,698,505

2,473,463

Liabilities
 
 
 
 
 
 
 
Current Liabilities (1)
79,124

 
 
333,053

148,919

176,033

179,412

Long-Term Debt (1)
198,000

 
 

1,074,534

1,142,368

916,934

Total Liabilities
301,244

 
 
1,377,722

1,378,969

1,633,155

1,420,680

Stockholders' Equity (Deficit)
$
76,055

 
 
$
(852,724
)
$
794,378

$
1,065,350

$
1,052,783

 
 
 
 
 
 
 
 
Shares Outstanding at Year-End
10,054

 
 
44,592

43,918

43,402

42,930

Book Value per Share at Year-End
$
7.56

 
 
$
(19.12
)
$
18.09

$
24.55

$
24.52

 
 
 
 
 
 
 
 
Additional Information
 
 
 
 
 
 
 
Producing Wells
 
 
 
 
 
 
 
Swift Operated
$
774

 
 
$
1,030

$
1,040

$
1,039

$
1,069

Outside Operated
$
5

 
 
$
26

$
25

$
25

$
50

Total Producing Wells
$
779

 
 
$
1,056

$
1,065

$
1,064

$
1,119

Wells Drilled (Gross)
$
7

 
 
$
24

$
36

$
48

$
71

 
 
 
 
 
 
 
 
Proved Reserves
 
 
 
 
 
 
 
Natural Gas (Bcf) (2)
$
626.8

 
 
$
311.7

$
686.7

$
815.1

$
597.6

Oil Reserves (MBoe) (2)
$
5.8

 
 
$
10.1

$
49.7

$
53.0

$
43.3

NGL Reserves (MBoe) (2)
$
13.7

 
 
$
8.2

$
29.7

$
30.4

$
49.2

Total Proved Reserves (MMBoe equivalent)
$
124.0

 
 
$
70.3

$
193.8

$
219.2

$
192.1

(1) Reduction in Long-Term Debt is due to reclassifications of (a) the Company's Senior Notes to Liabilities Subject to Compromise and (b) borrowings under the credit facility to Current Liabilities in 2015, both as a result of the bankruptcy filing.
(2) Reserves decreased during 2015 due to the impact of 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.


30


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying Notes 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) included in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 46 of this report.


As discussed in Notes 1A and 1B to the consolidated financial statements included herein, the Company applied fresh start accounting upon emergence from bankruptcy on April 22, 2016, at which time it became a new entity for financial reporting purposes. The effects of the Plan of Reorganization (described below) and the application of fresh start accounting were reflected in our consolidated financial statements as of April 22, 2016 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the period April 1, 2016 to April 22, 2016 (predecessor). References to the Successor relate to the Company on and subsequent to the Effective Date. References to Predecessor refer to the Company prior to the Effective Date.

Company Overview

We are an independent oil and natural gas company engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from our South Texas properties. We hold a large acreage position in Texas prospective for Eagle Ford shale and Olmos tight sands development. Natural gas production accounted for 76% of our production and 61% of our oil and gas sales, while oil accounted for 12% of our production and 29% of our oil and gas sales for the reporting period of April 23, 2016 through December 31, 2016 (successor). Combined production of both oil and natural gas constituted 88% of our production and 90% of our oil and gas sales for the reporting period of April 23, 2016 through December 31, 2016 (successor).

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On December 31, 2015, we and the Chapter 11 Subsidiaries filed voluntary petitions seeking relief under Chapter 11 of Title 11 of 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.

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, the $75 million drawn under the Company's DIP Credit Agreement (described below) and certain other unsecured claims were exchanged for 88.5% of the post-emergence Company’s common stock;
the lenders under the DIP Credit Agreement (as defined and more fully described below) received a backstop fee consisting of 7.5% of the post-emergence Company’s common stock which was not included in the 88.5% distributed to creditors;
the Company’s pre-petition common stock was canceled and the previous shareholders received 4% of the post-emergence Company’s common stock and warrants to purchase up to 30% of the reorganized Company's equity;
the warrants (each for up to 15% of the reorganized Company's equity), are exercisable at prices that represent a substantial increase from the value at emergence, as follows:

31


Issue Date
Expiration Date
Shares
Strike Price
April 22, 2016
April 22, 2019
2,142,857
$80.00
April 22, 2016
April 22, 2020
2,142,857
$86.18

claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;
the Company entered into a registration rights agreement to provide customary registration rights to certain holders of the Company’s post-emergence common stock who, together with their affiliates received upon emergence 5% or more of the outstanding common stock of the Company;
the Company sold (effective April 15, 2016) a portion of its interest in its Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, for net proceeds of approximately $46.9 million including deposits received prior to the closing date; and
the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (the "New Credit Facility") with an initial $320 million borrowing base was established. For more information refer to Note 5 of the accompanying consolidated financial statements in this Form 10-K.

In accordance with the Plan, the post-emergence Company’s new board of directors was initially to be 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. During the bankruptcy, we had a debtor-in-possession credit facility (the “DIP Credit Agreement") that provided for a multi-draw term loan of up to $75 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 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 million borrowed under the DIP Credit Agreement was not required to be repaid in cash and terminated upon the Company’s emergence from bankruptcy. For more information refer to Note 5 the accompanying consolidated financial statements in this Form 10-K.
    
Fresh Start Accounting. Upon the Company’s emergence from Chapter 11 bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 852, "Reorganizations" which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheet. The effects of the Plan and the application of fresh start accounting were reflected in our consolidated financial statements as of April 22, 2016 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the period April 1, 2016 to April 22, 2016 (predecessor).
As a result, our consolidated balance sheets and consolidated statement of operations subsequent to the Effective Date are not comparable to our consolidated balance sheets and statements of operations prior to the Effective Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 22, 2016 and dates on or prior to April 22, 2016. Our financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material.

Financial Statement Classification of Liabilities Subject to Compromise. 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 the accompanying consolidated financial statements in this Form 10-K for more information.



32


Significant Developments during 2016

Management Changes: On October 7, 2016, the Company announced that Robert J. Banks (current Chief Operating Officer) would serve as interim Chief Executive Officer of the Company, filling the position vacated by the retirement of Terry E. Swift on the same date. Furthermore, on August 9, 2016 the Company announced the Chief Financial Officer of the Company would also be retiring but would serve in the same capacity until a replacement is named. The Company is actively engaged in finding full time replacements for both of these key positions. On September 27, 2016, the Company announced the appointment of Marcus C. Rowland as the non-executive Chairman of the Board, a position that was previously filled on an interim basis by another member of the Board since the Company’s emergence from its Chapter 11 restructuring.

Weak crude oil and natural gas prices continue to affect our business: Oil and gas prices declined during 2015 and continue to remain relatively low by historical measures. While we are negatively impacted by weak commodity prices, the resulting industry downturn has created a much more competitive environment among oil field service companies, providing an opportunity for us to bring our cost structure in line with lower revenues. The recent rebound of oil and gas prices from their 2016 lows has allowed the Company to enter into price and basis differential hedges for calendar year 2017 production and the first quarter of 2018 production, which could partially mitigate future commodity price weakness.

Operational activity: At our Fasken field in the Eagle Ford play, eight wells were completed and placed into the system in early 2016. Seven wells were placed into the system at rates between 15 - 20 MMcf per day of natural gas and one well had mechanical issues and was placed into the system at a restricted rate of 9 MMcf per day of natural gas. The Company resumed drilling operations at Fasken in October 2016 and drilled eight more wells by the end of the year.

2016 changes in reserve quantities and value: Our 76%, or 54 MMBoe, increase in proved reserves quantities from 2015 to 2016 was principally due to additions of undeveloped reserves which were previously not included in 2015 because of the uncertainties surrounding the availability of the financing that would be necessary to develop them, due in part to our bankruptcy filing.
 
2016 cost reduction initiatives: We are continuing the cost reduction efforts initiated in 2015, and have taken additional actions during 2016 to significantly reduce our operating and overhead costs. In conjunction with our reorganization through Chapter 11 bankruptcy, we have renegotiated a number of contracts with vendors and service providers to bring costs in line with current market conditions. Other initiatives include field staff reductions, intermittent production of marginal properties, disposition of uneconomic and higher cost properties, full utilization of existing facilities and elimination of redundant equipment. At the corporate level we have also undergone significant staff reductions, reduced the square footage of leased office space and are taking additional steps to further reduce overhead costs.

Strategic dispositions: Effective December 1, 2016, we closed our transaction with Hilcorp Energy I, L.P. for the sale of the Company's holdings in our Lake Washington field located in Southeast 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. No gain or loss was recorded on the sale of the property. In addition, 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. 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.

Stock listing: Trading in the Company’s former common stock on the NYSE was suspended on December 18, 2015, and the common stock was subsequently delisted from the NYSE. The common stock of the Company traded on the OTC Pink marketplace under the symbol “SFYWQ” until the former common stock was canceled on April 22, 2016, pursuant to the plan of reorganization confirmed by the bankruptcy court. On October 3, 2016, the Company announced the common stock of the Company issued pursuant to the plan of reorganization was approved for quoting on the OTCQX Market. The Company is traded under the ticker "SWTF". Effective January 25, 2017 , the Company entered into an agreement with certain purchasers of our common stock in a recent private placement offering to list on a national securities exchange by July 25, 2017.

33


Summary of 2016 Financial Results

2016 revenues and net loss: The Company's oil and gas revenues were $43.0 million and $121.4 million in the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through December 31, 2016 (successor), respectively. Full year 2015 revenues were $246.3 million. Revenues were lower primarily due to lower oil and natural gas pricing as well as overall lower production. The Company's net income of $851.6 million in the period of January 1, 2016 through April 22, 2016 (predecessor) was primarily due to the gain on reorganization adjustments as part of our emergence from bankruptcy while the net loss of $156.3 million in the period of April 23, 2016 through December 31, 2016 (successor) was primarily due to the $133.5 million non-cash write-down of our oil and gas properties and losses on derivative instruments of $19.7 million.

2016 capital expenditures: The Company maintained a limited capital budget for 2016 with a focus on balancing capital expenditures with cash flows. The Company's capital expenditures on a cash basis were $24.5 million and $45.7 million in the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through December 31, 2016 (successor), respectively. The expenditures for the period January 1, 2016 through April 22, 2016, were primarily devoted to completion of wells in South Texas that were drilled in 2015. These expenditures were funded by cash flows and borrowings under our DIP credit facility. Capital expenditures since April 23, 2016 were focused on drilling and completion activities in our Fasken field. These expenditures were primarily funded by operating cash flows and proceeds from property dispositions.    

Working capital: Working capital, as measured by current assets less current liabilities, is one of several measures the Company uses to track its short-term liquidity position. The Company had a working capital deficit of $57.6 million at December 31, 2016 and a deficit of $271.2 million at December 31, 2015, excluding any available borrowings under the Company's credit facility. These numbers are not comparable given the Company's bankruptcy filing on December 31, 2015. For example, the deficit at December 31, 2015 included the Company's Prior First Lien Credit Facility borrowings as a current liability while other current payables were reclassified as Liabilities Subject to Compromise, which were excluded from new working capital computation. For covenant purposes, the working capital computation includes available borrowings under the credit facility. For more information on our Current Ratio covenant see Note 5 of the accompanying consolidated financial statements in this Form 10-K.

Cash Flows: For the period of April 23, 2016 through December 31, 2016 (successor) the Company generated cash from Operating Activities of $47.4 million, of which $8.2 million was attributable to changes in working capital. Additionally we realized $46.0 million in net proceeds from asset sales during this period. Cash used for property additions was $45.7 million. This included $6.3 million attributable to net pay-down of capital related payables and accrued cost as the Company paid a significant portion of the well completion costs from earlier in the year during this period. The Company’s net payments on its line of credit were $55.0 million for this period.

For the period of January 1, 2016 through April 22, 2016 (predecessor) (which included the impact of cash transactions occurring upon emergence from bankruptcy) the Company’s operating cash flow deficit was $41.5 million, of which $16.3 million was attributable to working capital changes. During this period the Company incurred $25.6 million in legal and professional fees related to its bankruptcy and reorganization activities. While the Company paid $24.5 million for capital expenditures, it realized $48.7 million from asset sales (primarily from the sales of properties in Central Louisiana) and received $75 million in proceeds from its DIP credit facility. It utilized $71.9 million to pay down its bank credit facility from $324.9 million to $253.0 million prior to emergence from bankruptcy. The remaining $253.0 million was refinanced with the Company’s new credit facility. The Company also paid $10.4 million for interest during the period and $6.5 million for debt issuance costs associated with obtaining the new credit facility.

For the year ended December 31, 2015 the Company generated $42.3 million from operating activities but paid out $139.7 million for capital expenditures, including a net pay down of $27.6 million in payables and accrued capital for 2014 activity. The Company drew a net $127.6 million on its bank credit facility during the period.


34


Summary of Operational Achievements during 2016

Reductions in per well costs: We have seen significant improvements in drilling costs and drilling days for our Fasken wells in the fourth quarter of 2016 with average drilling costs per well decreasing to $1.8 million from $2.4 million during 2015 and drilling days per well decreasing from 20 days to 11 days over the same period.  We have also significantly lowered the frac and completion costs of the Fasken wells.  Our fourth quarter average completion costs per well are $2.3 million compared to an average completion cost of $3.2 million for the first two quarters of 2016.

Reductions in operating costs: In addition to the initiatives summarized above, during 2016 we implemented a number of operational initiatives to reduce lease operating expenses. This included a reconfiguration of the gathering system in Lake Washington to consolidate production into one platform. This effort significantly reduced operating expenses in this field which we believe enhanced the value we realized from the disposition. For 2017 in our South Texas area, we are continuing to implement additional operating cost reduction initiatives including a reduction in headcount, eliminating redundant equipment, and shutting in or divesting wells with marginal production or high operating costs.


35



2016 Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operations, borrowings under our Prior First Lien Credit Agreement and issuances of senior notes. Our primary use of cash flow has been to fund capital expenditures used to develop our oil and gas properties. Upon emergence from bankruptcy, our primary sources of liquidity were cash flows from operations, proceeds from asset sales and borrowings under the New Credit Facility. As of December 31, 2016, the Company’s liquidity consisted of approximately $0.3 million of cash-on-hand and $106.9 million in available borrowings (calculated as $122 million of borrowing availability less $5.1 million in letters of credit and a $10 million minimum liquidly requirement) on the $320 million borrowing base. 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 million available.

Disposition of Assets. 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 were $46.9 million for this transaction, including deposits received prior to the closing date. These proceeds were 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 our 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.

New Credit Facility and Prior First Lien Credit Agreement. Upon our emergence from bankruptcy, the Prior First Lien Credit Agreement was terminated and paid in full, and the Company entered into 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 in 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 our emergence from bankruptcy, the maximum credit amount was $500 million with an initial borrowing base of $320 million. The obligations under the New Credit Facility are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries including a first priority lien on properties attributed with at least 95% of estimated proved producing reserves of the Company and its subsidiaries. This borrowing base was affirmed in our first semi-annual borrowing base redetermination in November 2016. As of December 31, 2016, we had $198 million in outstanding borrowings under the New Credit Facility. The terms of the New Credit Facility included the following, based on terms as defined in the New Credit Facility agreement:

The initial borrowing base was initially allocated between a non-conforming borrowing base of $70 million, which was scheduled to terminate on November 1, 2017, and a conforming borrowing base of $250 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 million.
Borrowing base redeterminations are scheduled to occur semi-annually in November and May and are determined by the lenders at their discretion and in the usual and customary manner.

36


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 both 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, significantly reducing our future interest expense. 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 to 1 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, which includes the unused portion of our borrowing base, and (c) a minimum liquidity requirement of $10 million. As of December 31, 2016, the Company was in compliance with these covenants and liquidity requirements.

We expect to be in compliance with the covenants under this agreement during the next twelve months from the date of filing of this Form 10-K. Maintaining or increasing borrowing base under our New Credit Facility is dependent upon many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replace produced reserves.

2017 Private Placement of Common Stock. 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. The securities offered in the private placement have not been registered under the Securities Act of 1933 or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements of the Securities Act and applicable state laws.

2017 Capital Spending. The Company's net operational capital budget for 2017 is expected to be in the range of $85.0 million and $95.0 million. The Company plans to drill and complete 12 wells in the first half of 2017. Specifically, the Company expects to complete nine wells (not including 3 wells drilled and completed in late 2016) in its Fasken field in Webb County, drill and complete 2 wells on its AWP acreage in McMullen County, and drill and complete its first well in Oro Grande in LaSalle County. All drilling activities will target the Eagle Ford formation. The Company expects to spud the Oro Grande appraisal well in the second quarter of 2017. The anticipated capital budget is inclusive of the aforementioned completions as well as associated drilling activities, infrastructure, abandonment activities and other discretionary expenditures.


37


Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter are shown below as of December 31, 2016 (in thousands):
 
2017
2018
2019
2020
2021
Thereafter
Total
Non-cancelable operating leases (1)
$
5,460

$
2,016

$
621

$
487

$
204

$

$
8,788

Asset retirement obligation (2)
9,965

5,224

4,549

4,953

66

7,499

32,256

Drilling, Completion and Geoscience Contracts
1,320






1,320

Gas transportation and Processing (3)
8,254

13,542

12,782

10,846



45,424

Interest Cost (4)
8,415

7,920

2,462




18,797

Credit facility


198,000




198,000

Executive severance agreements
2,464

786





3,250

Total
$
35,878

$
29,488

$
218,415

$
16,286

$
271

$
7,499

$
307,835


(1) We signed a new sub-lease on our corporate headquarters commencing on January 1, 2017. For additional discussion regarding the terms and obligations of this lease refer to Note 7 of the consolidated financial statements in this Form 10-K.
(2) Amounts shown by year are the net present value at December 31, 2016. Approximately 81% of the 2017 through 2021 obligation is for the Bay de Chene Field in Louisiana
(3) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations.
(4) Interest is estimated using 4% APR after credit facility amendment, see Note 5 of these consolidated financial statements in this Form 10-K. Actual interest rate is variable over the term of the facility.

As of December 31, 2016, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

Proved Oil and Gas Reserves

During 2016, our reserves increased by approximately 54 MMBoe 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. As of December 31, 2016, 51% of our total proved reserves were proved developed, compared with 80% at year-end 2015 and 34% at year-end 2014.

At December 31, 2016, our proved reserves were 124.0 MMBoe with a Standardized Measure of $407 million, which is an increase of approximately $33 million, or 9%, from the prior year-end levels. In 2016, our proved natural gas reserves increased 315.1 Bcf, or 101%, while our proved oil reserves decreased 4.3 MMBbl, or 43%, and our NGL reserves increased 5.5 MMBbl, or 67%, for a total equivalent increase of 54 MMBoe, or 76%.

In prior years we have added proved reserves primarily through our drilling activities, including 18.2 MMBoe added in 2014. We obtained reasonable certainty regarding these reserve additions by applying the same methodologies that have been used historically in this area. We also sold approximately 7.1 MMBoe of reserves during 2016 in conjunction with our dispositions, as described further in Note 10 of our consolidated financial statements in this Form 10-K.

We use the preceding 12-month's average price based on closing prices on the first business day of each month, adjusted for price differentials, in calculating our average prices used in the Standardized Measure calculation. Our average natural gas price used in the Standardized Measure calculation for 2016 was $2.43 per Mcf. This average price decreased from the average price of $2.61 per Mcf used for 2015. Our average oil price used in the calculation for 2016 was $41.07 per Bbl. This average price decreased from the average price of $49.58 per Bbl used in the calculation for 2015.


38



Results of Operations

Revenues — 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)

The tables included below set forth financial information 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) which are distinct reporting periods as a result of our emergence from bankruptcy on April 22, 2016.

Certain reclassifications have been made to 2015 and 2014 sales volumes from previously reported volumes to conform to the current-year presentation. Previously disclosed production volumes included natural gas consumed in operations. All current and prior year production is now shown based on volumes sold rather than volumes produced.

2016 - Our oil and gas sales in 2016 decreased by 33% compared to revenues in 2015, primarily due to lower oil and natural gas prices and overall lower production volumes. Average oil prices we received were 16% lower than those received during 2015, while natural gas prices were 7% lower, and NGL prices were flat.

2015 - Our oil and gas sales in 2015 decreased by 55% compared to revenues in 2014, due to the impact of overall lower commodity prices and lower oil and NGL volumes, partially offset by higher natural gas production. Average oil prices we received were 49% lower than those received during 2014, while natural gas prices were 41% higher, and NGL prices were 54% higher.

Crude oil production was 12%, 19%, 22% and 30% of our production volumes while crude oil sales revenues were 29%, 38%, 46% and 59% of oil and gas sales revenue for the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor), the year ended December 31, 2015 (predecessor) and the year ended December 31, 2014 (predecessor), respectively. Natural gas production was 76%, 68%, 66% and 54% of our production volumes while natural gas sales revenues were 61%, 52%, 46% and 30% of oil and gas sales for the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor), the year ended December 31, 2015 (predecessor) and the year ended December 31, 2014 (predecessor), respectively.

The following tables provide information regarding the changes in the sources of our oil and gas sales and volumes 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):

Fields
 
Oil and Gas Sales (In Millions)
 
 
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
 
Year Ended December 31, 2014
Artesia Wells
 
$
9.9

 
 
$
3.5

 
$
19.3

 
$
62.2

AWP
 
42.4

 
 
14.7

 
87.1

 
224.8

Fasken
 
53.0

 
 
14.3

 
72.1

 
87.2

Other (1)
 
16.1

 
 
10.5

 
67.8

 
173.6

Total
 
$
121.4

 
 
$
43.0

 
$
246.3

 
$
547.8

(1) Primarily fields sold during 2016 including our former Lake Washington, South Bearhead Creek and Burr Ferry fields.

39


Fields
 
Net Oil and Gas Production Volumes (MBoe)
 
 
Successor
 
 
Predecessor
 
 
(a)
 
 
(b)
(a) + (b)
 
 
 
 
 
 
Period from April 23, 2016 through December 31, 2016
 
 
Period from January 1, 2016 through April 22, 2016
Year Ended December 31, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Artesia Wells
 
484

 
 
257

741

 
1,048

 
1,627

AWP
 
1,980

 
 
951

2,931

 
3,618

 
4,299

Fasken
 
3,462

 
 
1,213

4,675

 
4,769

 
3,516

Other (1)
 
439

 
 
386

825

 
1,711

 
2,162

Total
 
6,365

 
 
2,807

9,172

 
11,146

 
11,604

(1) Primarily fields sold during 2016 including our former Lake Washington, South Bearhead Creek and Burr Ferry fields.

Our production decrease from 2015 to 2016 was primarily due overall decreased production due to natural declines, reduced drilling and completion activity and strategic dispositions of our non-core fields during the year.

In 2016, our $81.9 million, or 33% decrease in oil, NGL, and natural gas sales resulted from:

Price variances that had a $17.0 million unfavorable impact on sales, with a decrease of $10.0 million due to the 16% decrease in oil prices received and a decrease of $7.0 million due to the 7% decrease in natural gas prices.
Volume variances that had a $64.9 million unfavorable impact on sales, with a $51.7 million decrease due to the 1.1 million Bbl decrease in oil production volumes, an $8.4 million decrease due to the 3.3 Bcf decrease in natural gas production volumes and a $4.7 million decrease due to the 0.3 million Bbl decrease in NGL production volumes.

In 2015, our $301.5 million, or 55% decrease in oil, NGL, and natural gas sales resulted from:

Price variances that had a $206.2 million unfavorable impact on sales, with a decrease of $109.8 million due to the 49% decrease in oil prices received, a decrease of $71.6 million due to the 39% decrease in natural gas prices and a decrease of $24.8 million due to the 54% decrease in NGL prices.
Volume variances that had a $95.4 million unfavorable impact on sales, with a $102.4 million decrease due to the 1.1 million Bbl decrease in oil production volumes and a $12.1 million decrease due to the 0.4 million Bbl decrease in NGL production volumes, partially offset by a $19.2 million increase due to the 4.9 Bcf increase in natural gas production volumes.


40


The following table provides additional information regarding our oil and gas sales, excluding any effects of our hedging activities, for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through December 31, 2016 (successor), and for the years ended December 2015 and 2014 (predecessor):

 
Production Volume
 
Average Price
 
Oil
 
NGL
 
Gas
 
Combined
 
Oil
 
NGL
 
Gas
 
(MBbl)
 
(MBbl)
 
(Bcf)
 
(MBoe)
 
(Bbl)
 
(Bbl)
 
(Mcf)
2014 (Predecessor)
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
931
 
478
 
8.7
 
2,853
 
$99.38
 
$36.27
 
$4.46
  Second Quarter
890
 
434
 
12.1
 
3,344
 
$101.67
 
$33.93
 
$4.37
  Third Quarter
870
 
482
 
7.3
 
2,565
 
$96.12
 
$33.39
 
$4.81
  Fourth Quarter
820
 
418
 
9.6
 
2,842
 
$71.94
 
$22.74
 
$3.93
    Total
3,511
 
1,812
 
37.7
 
11,604
 
$92.74
 
$31.83
 
$4.36
2015 (Predecessor)
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
685
 
426
 
10.7
 
2,902
 
$45.10
 
$16.09
 
$2.76
  Second Quarter
628
 
366
 
10.4
 
2,725
 
$56.65
 
$15.18
 
$2.61
  Third Quarter
581
 
344
 
10.8
 
2,734
 
$45.24
 
$12.94
 
$2.70
  Fourth Quarter
511
 
297
 
11.9
 
2,785
 
$40.22
 
$13.38
 
$2.20
    Total
2,405
 
1,433
 
43.8
 
11,146
 
$47.11
 
$14.54
 
$2.56
2016 (Predecessor)
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
427
 
310
 
9.2
 
2,269
 
$30.07
 
$10.83
 
$1.98
  April 1 - April 22
95
 
70
 
2.2
 
538
 
$37.49
 
$11.96
 
$1.90
    Total
522
 
380
 
11.4
 
2,807
 
$31.43
 
$11.04
 
$1.96