Attached files

file filename
EX-31.1 - EXHIBIT 31.1 - SILVERBOW RESOURCES, INC.a201510k-exhibit311.htm
EX-12 - EXHIBIT 12 - SILVERBOW RESOURCES, INC.a201510k-exhibit12.htm
EX-99.1 - EXHIBIT 99.1 - SILVERBOW RESOURCES, INC.a201510k-exhibit991.htm
EX-23.1 - EXHIBIT 23.1 - SILVERBOW RESOURCES, INC.a201510k-exhibit231.htm
EX-23.2 - EXHIBIT 23.2 - SILVERBOW RESOURCES, INC.a201510k-exhibit232.htm
EX-32 - EXHIBIT 32 - SILVERBOW RESOURCES, INC.a201510k-exhibit32.htm
EX-31.2 - EXHIBIT 31.2 - SILVERBOW RESOURCES, INC.a201510k-exhibit312.htm
EX-21 - EXHIBIT 21 - SILVERBOW RESOURCES, INC.a201510k-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, 2015

Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Texas
(State of Incorporation)
20-3940661
(I.R.S. Employer Identification No.)
 
 
17001 Northchase Drive, Suite 100
Houston, Texas 77060
(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
Not Applicable

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 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

1


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 market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold on the New York Stock Exchange as of June 30, 2015, the last business day of June 2015, was approximately $87,818,801.

The number of shares of common stock outstanding as of February 29, 2016 was 44,747,966.



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
 17
 
 
 
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
 
 
 



3


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 24 and 25 for explanations of abbreviations and terms used herein.

Overview

Swift Energy Company, a Texas corporation founded in 1979, 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 and, to a lesser extent, the onshore and inland waters of Louisiana. We operate approximately 97% 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 areas where we operate. As a result of the significant resource potential from our properties in the Eagle Ford, we plan to invest a significant portion from our total 2016 planned capital expenditures in this area.

At December 31, 2015, we had estimated proved reserves of 70.3 MMBoe with a PV-10 Value of $374.0 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 a decrease of approximately 124 MMBoe from year-end 2014 proved reserves quantities 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. Our total proved reserves at December 31, 2015 were approximately 14% crude oil, 74% natural gas, and 12% NGLs while 80% of our total proved reserves were developed. Approximately 90% of our proved reserves are located in Texas with the remainder in Louisiana.

Bankruptcy Proceedings under Chapter 11

On December 31, 2015, the Company and eight of its subsidiaries (the “Chapter 11 Subsidiaries”) filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (In re Swift Energy Company, et al, Case No. 15-12670). The Company and the Chapter 11 Subsidiaries are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted all motions filed by the Company and the Chapter 11 Subsidiaries that were designed primarily to minimize the impact of the Chapter 11 proceedings on the Company’s operations, customers and employees. As a result the Company is not only able to conduct normal business activities and pay all associated obligations for the period following its bankruptcy filing, it is also 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. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. As a result of the automatic stay, which became effective upon the commencement of the Chapter 11 case, 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 are stayed. 

On February 5, 2016, the Company and the Chapter 11 Subsidiaries filed with the Bankruptcy Court a joint plan of reorganization (the “Plan”), which is supported by an ad hoc committee of the Company’s noteholders. The Plan is subject to confirmation by the Bankruptcy Court. If the Plan is ultimately approved by the Bankruptcy Court, the Company and the Chapter 11 Subsidiaries would exit bankruptcy pursuant to the terms of the Plan.  Under the Plan, the holders of the Company’s senior notes and certain other unsecured creditors, together with the lenders under the debtor-in-possession credit agreement, are to receive 96% of the new common stock to be issued upon emergence of the Company from bankruptcy, with the remaining 4% to be issued to the Company’s then-current equity holders. Claims of other creditors would be paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors.

The Bankruptcy Court has approved the Company’s disclosure statement with respect to the Plan, and the Company is in the process of soliciting votes with respect to the Plan. A confirmation hearing on the Plan is scheduled on March 30, 2016 in the Bankruptcy Court.

     For a further description of these matters, see Note 1A to our Consolidated Financial Statements. 

As a consequence of depressed oil prices and our limited liquidity (See “2016 Liquidity and Capital Resources” in Management’s Discussion and Analysis in this Form 10-K report), as disclosed in our Bankruptcy Court filings, the Company’s current $78.0 million capital budget for 2016 is significantly reduced from 2015 levels, and includes $66 million for completion

4


costs for 12 previously drilled but not completed wells, drilling and completion of 4 wells, drilling but not completion of 8 additional wells, and recompletion of 8 wells. The budget also includes $12.0 million for anticipated regulatory, corporate and other capital costs.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 proceedings as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Pending Sale of Interests in South Bearhead Creek and Burr Ferry Louisiana Fields to Texegy LLC

On December 31, 2015 the Company entered into a purchase and sale agreement with Texegy LLC (Texegy) to sell a full participating 75% working interest of Swift Energy’s position in the South Bearhead Creek Field and Burr Ferry Field located in Allen, Avoyelles, Vernon, Sabine and Beauregard Parishes in central Louisiana. The Bankruptcy Court approved the sale on February 2, 2016. To date, Swift Energy has received two equal cash deposits aggregating $4.9 million from Texegy, the second of which was made upon Bankruptcy Court approval of the sale on February 2, 2016. The purchase agreement provides for Texegy to pay Swift Energy approximately $49.0 million in cash consideration, which is subject to closing adjustments and adjustments for interim operations between January 1, 2016 and the closing date. Upon closing, which the purchase and sale agreement provides will occur on or prior to March 15, 2016 unless a later date is agreed to by both parties, Swift will retain approximately $13.0 million of the closing proceeds (subject to the same adjustments), with the balance to be paid to the Company’s first-lien secured lenders under the Company’s credit facility. The properties being sold represent approximately 5% of the Company's total proved reserves as of December 31, 2015. 

In addition to paying for its share of costs, Texegy has agreed to carry a portion of the Company’s field development costs, which are limited to the Company’s 25% share of all costs for the drilling of two wells to casing point in the South Bearhead Creek Field. On the closing date, Swift Energy and Texegy plan to enter into a joint development agreement and a joint operating agreement (together, the “JV Agreements”) to continue operation and development of the Properties, with a Texegy affiliate serving as the operator of the Properties that will conduct all drilling, completion and production operations. Under the JV Agreements, future development plans for the field will be mutually agreed upon by the Company and Texegy.

Business Strategy

Our business strategy is primarily focused on exploiting our unconventional reserves from the Eagle Ford and, to a lesser extent, exploiting our more conventional reserves in Louisiana.

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, substantially increasing our Olmos production. 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. During 2015, we drilled 24 horizontal Eagle Ford wells. 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 2016 plans include completing 12 previously drilled (but not completed) wells and drilling (but not completing) an additional 8 new wells.

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 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.

5



Emerge from bankruptcy: Our current schedule is to emerge from bankruptcy within 110 days of our December 31, 2015 Chapter 11 filing. We expect that we will exit bankruptcy with an improved balance sheet and additional liquidity. This should allow us to access capital necessary to maintain, and in some cases, improve our asset base.
 
Experienced technical team. We employ 43 oil and gas technical professionals, including geophysicists, petrophysicists, geologists, petroleum engineers and production and reservoir engineers, 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.

Operating Areas

Our operations are primarily focused in three core areas identified as South Texas, Southeast Louisiana and Central Louisiana. The following table sets forth information regarding our 2015 year-end proved reserves of 70.3 MMBoe and production of 11.7 MMBoe by area:
Core Areas & Fields
 
Developed Reserves (MMBoe)
 
Undeveloped Reserves
(MMBoe)
 
Total Proved Reserves
(MMBoe)
 
% of Total Proved Reserves
 
Oil and
NGLs as % of Reserves
 
Total
Production (MBoe)
Artesia Wells
 
3.8

 

 
3.8

 
5.4
%
 
52.1
%
 
1,113

AWP
 
16.5

 
5.2

 
21.8

 
31.0
%
 
45.2
%
 
3,881

Fasken
 
27.9

 
8.7

 
36.6

 
52.1
%
 
%
 
4,841

Other South Texas
 
0.9

 

 
0.9

 
1.2
%
 
52.4
%
 
209

Total South Texas
 
49.2

 
13.9

 
63.1

 
89.8
%
 
 
 
10,044

 
 
 
 
 
 
 
 
 
 
 
 
 
Southeast Louisiana
 
3.5

 

 
3.5

 
5.0
%
 
97.6
%
 
1,061

 
 
 
 
 
 
 
 
 
 
 
 
 
Central Louisiana
 
3.6

 

 
3.6

 
5.1
%
 
73.3
%
 
583

 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
0.1

 

 
0.1

 
0.1
%
 
4.0
%
 
39

 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
56.3

 
13.9

 
70.3

 
100.0
%
 
26.1
%
 
11,727



6


South Texas

AWP. During 2015, the Company drilled 5 wells in AWP targeting the Eagle Ford formation. All wells in this field were drilled and are operated by Swift Energy. Our proved reserves in this formation are 54% natural gas, 26% NGLs, and 20% oil on a Boe basis. As of December 31, 2015 we had 4 wells drilled that were waiting on completion. These wells were subsequently completed in February of 2016.

In the Olmos formation, the wells are operated and owned by Swift Energy and our reserves in this formation are approximately 58% natural gas, 28% NGLs, and 14% oil on a Boe basis.

Artesia Wells. Our December 31, 2015 proved reserves in this formation are 48% natural gas, 37% NGLs, and 15% oil on a Boe basis.

Fasken. During 2015, the Company drilled 19 wells in Fasken targeting the Eagle Ford formation. All wells in this field were drilled and are operated by Swift Energy. Our reserves in this Eagle Ford formation are 100% natural gas. At December 31, 2015, we had drilled 8 proved undeveloped locations that are expected to be completed in the first and second quarters of 2016.

On July 15, 2014, we closed a transaction with Saka Energi to fully develop 8,300 acres of natural gas Eagle Ford shale properties in our Fasken field. Saka Energi purchased a 36% full participating interest in the properties. Refer to Note 9 of the consolidated financial statements in this Form 10-K for further discussion of this transaction.

Southeast Louisiana

Lake Washington. Since its discovery in the 1930's, the field has produced over 300 million Boe from multiple stacked Miocene sand layers radiating outward from a central salt dome which are heavily faulted, thereby creating a large number of potential hydrocarbon traps. Approximately 98% of our proved reserves in this field consisted of oil and NGLs which are gathered to several platforms located in water depths from 2 to 12 feet, with drilling and workover operations performed with rigs on barges.

In 2015 we did not drill any wells in Lake Washington, but we did perform numerous production enhancement operations including sliding sleeve changes, gas lift modifications and well stimulations.

Central Louisiana

Burr Ferry. This field is predominately located in Vernon Parish, Louisiana. The reserves are approximately 62% oil and NGLs.

South Bearhead Creek. This field is located in Beauregard Parish, Louisiana and is a large east-west trending anticline closure. Wells drilled in this field are completed in a multiple set of separate sands in the Wilcox formation.

On December 31, 2015, the Company entered into a purchase and sale agreement with Texegy LLC to sell to Texegy 75% of Swift Energy’s position in the South Bearhead Creek and Burr Ferry Fields. Refer to Note 9 of the consolidated financial statements in this Form 10-K for further discussion of this transaction.

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, 2015, 2014 and 2013. The information set forth in the tables regarding reserves is based on proved reserves reports we have prepared in accordance with SEC rules. Our Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of our 2015 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. H.J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers, has audited 99% of our proved reserves for the year ended December 31, 2015 and 97% of our proved reserves for the years ended December 31, 2014 and 2013. The audit by H.J. Gruy and Associates, Inc. conformed to the meaning of the term “reserves audit” as presented in Regulation S-K, Item 1202. The technical person at H.J. Gruy and Associates, Inc. primarily responsible for overseeing the audit, is a Licensed Professional Engineer, holds a degree in petroleum engineering, is past 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 overseeing reserves audits. Based on their

7


audit, it is the judgment of H.J. Gruy and Associates, Inc. that Swift Energy used appropriate engineering, geologic, and evaluation principles and methods that are consistent with practices generally accepted in the petroleum industry.

The reserves estimation process involves members of the reserves and evaluation department who report to the Chief Reservoir Engineer as well as engineers whose duty is to prepare estimates of reserves in accordance with the Commission's rules, regulations and guidelines, and who are part of multi-disciplinary teams responsible for each of the Company's major core asset areas. The multi-disciplinary teams consist of experienced reservoir engineers, geologists and other oil and gas professionals. A majority of our asset team reservoir engineers involved in the reserves estimation process have over 10 years of reservoir engineering experience. 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 and the Board of Directors on a periodic basis. At year-end, a reserves audit is performed by the third-party engineering firm, H.J. Gruy and Associates, Inc., to ensure the integrity and reasonableness of our reserves estimates. In addition, our independent Board members meet with H.J. Gruy and Associates, Inc. in executive session at least annually to review the annual reserves audit report and the overall reserves audit process.

A reserves audit and a financial audit are separate activities with unique and different processes and results. As currently defined by the U.S. Securities and Exchange Commission within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Estimates of future net revenues from our proved reserves and their PV-10 Value (a non-GAAP measure defined below), for the years ended December 31, 2015, 2014 and 2013 are made 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 year-end PV-10 Value. The 12-month 2015 average adjusted prices after differentials for operations were $2.61 per Mcf of natural gas, $49.58 per barrel of oil, and $14.64 per barrel of NGL, compared to $4.32 per Mcf of natural gas, $93.64 per barrel of oil, and $33.00 per barrel of NGL for 2014 and $3.41 per Mcf of natural gas, $104.38 per barrel of oil, and $31.68 per barrel of NGL for 2013.


8


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 their PV-10 Value as of December 31, 2015, 2014 and 2013. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in supplemental information to our consolidated financial statements (the "Standardized Measure"), which is calculated after provision for future income taxes.

At December 31, 2015, we had estimated proved reserves of 70.3 MMBoe with a PV-10 Value of $374 million. This is a decrease of approximately 124 MMBoe from year-end 2014 proved reserves 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. Our total proved reserves at December 31, 2015 were approximately 14% crude oil, 74% natural gas, and 12% NGLs, while 80% of our total proved reserves were developed. Approximately 90% of our proved reserves are located in Texas with the remainder in Louisiana. 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,
 
 
2015
 
2014
 
2013
Natural gas reserves (MMcf):
 
 
 
 
 
 
   Proved developed
 
238,356

 
232,807

 
197,816

   Proved undeveloped (3)
 
73,332

 
453,940

 
617,309

      Total
 
311,688

 
686,747

 
815,125

Oil reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
10,109

 
14,989

 
16,884

   Proved undeveloped (3)
 

 
34,717

 
36,110

      Total
 
10,109

 
49,706

 
52,994

NGL reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
6,500

 
12,495

 
13,059

   Proved undeveloped (3)
 
1,716

 
17,168

 
17,320

      Total
 
8,216

 
29,663

 
30,379

 
 
 
 
 
 
 
Total Estimated Reserves (MBoe) (1)(3)
 
70,273

 
193,826

 
219,227

 
 
 
 
 
 
 
Estimated Discounted Present Value of Proved Reserves (in millions)
 
 
 
 
 
 
Proved developed
 
$
321

 
$
954

 
$
1,028

Proved undeveloped
 
53

 
990

 
1,397

PV-10 Value (2)
 
$
374

 
$
1,944

 
$
2,425


(1) The 2015 and 2014 reserve volumes exclude natural gas consumed in operations. For additional discussion of this methodology refer to the Supplementary Reserves Information of this Form 10-K.
(2) The PV-10 Values as of December 31, 2015, 2014 and 2013 are net of $57.8 million, $85.5 million, and $87.0 million of asset retirement obligation liabilities, respectively.
(3) The decrease in 2015 reserves volumes is 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.

PV-10 Value is a non-GAAP measure. The closest 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

9


value of proved reserves on a comparative basis across companies or specific properties. We use the PV-10 Value in our ceiling test computations, 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 the Standardized Measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves.


10


The following table provides a reconciliation between the PV-10 Value and the Standardized Measure.
 
As of December 31,
(in millions)
2015
 
2014
 
2013
PV-10 Value
$
374

 
$
1,944

 
$
2,425

 
 
 
 
 
 
Future income taxes (discounted at 10%)

 
(292
)
 
(423
)
Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves
$
374

 
$
1,652

 
$
2,002


Proved Undeveloped Reserves

The following table sets forth the aging of our proved undeveloped reserves as of December 31, 2015:
Year Added
 
Volume
(MMBoe)
 
% of PUD
Volumes
2015
 
0.0
 
%
2014
 
5.2
 
38
%
2013
 
8.7
 
62
%
2012
 
0.0
 
%
2011
 
0.0
 
%
Total
 
13.9
 
100
%

During 2015, our proved undeveloped reserves decreased by approximately 114 MMBoe 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, as disclosed in Note 1A of the consolidated financial statements in this Form 10-K. We also incurred approximately $47 million in capital expenditures during the year which resulted in the conversion of 15 MMBoe of our December 31, 2014 proved undeveloped reserves to proved developed reserves, primarily in the Fasken field.

The PV-10 Value from our proved undeveloped reserves was $53.0 million at December 31, 2015, which was approximately 14% of our total PV-10 Value of $374.0 million. The PV-10 Value of our proved undeveloped reserves, by year of booking was 26% in 2014 and 74% in 2013.

Sensitivity of Reserves to Pricing

As of December 31, 2015, a 5% increase in oil and NGL pricing would increase our total estimated proved reserves of 70.3 MMBoe by approximately 0.7 MMBoe, and would increase the PV-10 Value of $374.0 million by approximately $18 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.8 MMBoe and would decrease the PV-10 Value by approximately $18 million.

As of December 31, 2015, a 5% increase in natural gas pricing would increase our total estimated proved reserves by approximately 1.0 MMBoe and would increase the PV-10 Value by approximately $22 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated proved reserves by approximately 1.1 MMBoe and would decrease the PV-10 Value by approximately $21 million.


11


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, 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

December 31, 2013
 
 
 
 
 
Gross
345

 
719

 
1,064

Net
325.1

 
701.2

 
1,026.3


(1)
Excludes 48, 49 and 60 service wells in 2015, 2014 and 2013.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2015:
 
Developed
 
Undeveloped
 
Gross
 
Net
 
Gross
 
Net
Colorado

 

 
47,713

 
42,509

Louisiana (1)
116,909

 
103,574

 
79,104

 
66,002

Texas (2)
68,518

 
64,147

 
38,360

 
35,466

Wyoming

 

 
3,092

 
1,521

Total
185,427

 
167,721

 
168,269

 
145,498


(1)
The Company holds the fee mineral (royalty) interest in a portion of the acreage located in Central Louisiana. The above table includes acreage where Swift Energy is the fee mineral owner as well as a working interest owner. This acreage included in the above table totals 66,073 gross and net undeveloped acres and 20,174 gross and net developed acres. The Company also owns fee mineral interest in approximately 16,295 acres that are currently unleased and not included in the table above. Swift owns a total of 86,247 mineral acres.
(2)
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 36,994 gross and 30,270 net developed acres and 47,308 gross and 39,310 net undeveloped acres. A large portion of our undeveloped Eagle Ford acreage underlies developed Olmos acreage. In the Olmos, we have 50,276 gross and 46,877 net developed acres and 26,169 gross and 22,801 net undeveloped acres.

As of December 31, 2015, Swift Energy's net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 14% in 2016, 26% in 2017 and 14% in 2018. In most cases, acreage scheduled to expire can be held through drilling operations or we can exercise extension options. As of February 29, 2016, 2,643 net undeveloped acres have expired during the current year. The exploration potential of all undeveloped acreage is fully evaluated before expiration. In each fiscal year where undeveloped acreage is subject to expiration our intent is to reduce the expirations through either development or extensions, if we believe it is commercially advantageous to do so. Due to the bankruptcy proceedings and depressed commodity prices, it is possible that we may not have the ability to do so.


12


Drilling and Other Exploratory and Development Activities

The following table sets forth the results of our drilling activities during the years ended December 31, 2015, 2014 and 2013:
 
 
 
 
Gross Wells
 
Net Wells
Year
 
Type of Well
 
Total
 
Producing
 
Dry
 
Total
 
Producing
 
Dry
2015
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
24

 
24

 

 
17.1

 
17.1

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
36

 
36

 

 
31.5

 
31.5

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
 
Exploratory
 
1

 

 
1

 
1.0

 

 
1.0

 
 
Development
 
47

 
46

 
1

 
45.0

 
44.0

 
1.0


Present Activities

As of December 31, 2015, we were in the process of drilling one development well in our Fasken field which has a 64% working interest. In the first quarter of 2016, we have begun the process of conducting completion operations for 12 wells (approximately 9 net wells) drilled during the third and fourth quarters of 2015.

We are also currently developing and implementing a number of operational cost reduction initiatives, including a plan to reconfigure the production gathering system in the Lake Washington field to consolidate production into one platform. We are also planning to temporarily shut in a number of our wells with marginal production. Implementation of these initiatives, in addition to other initiatives being planned, is expected to result in significant operating expense reductions.

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 conducted in accordance with COPAS 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 in 2015 totaled $9.2 million and ranged from $250 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 years ended December 31, 2015, 2014 and 2013, Shell Oil Company and affiliates accounted for 16%, 21% and 33% of our total oil and gas gross receipts, respectively. Kinder Morgan, Plains Marketing and Howard Energy accounting for approximately 27%, 18% and 13% of our total oil and gas gross receipts in 2015, respectively. Kinder Morgan and Plains Marketing accounted for approximately 20% and 11% of our total oil and gas gross receipts in 2014, while BP America accounted for approximately 21% of our total oil and gas gross receipts in 2013. Credit losses in each of the last three years were immaterial.

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. Oil production is transported to market by truck and sold at prevailing market prices.


13


We have a 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.

Oil production from the Lake Washington field is 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 is either consumed on the lease or is delivered to High Point Gas Transmission (successor to El Paso's Southern Natural Gas Company) pipeline system and the processing of natural gas occurs at the Toca Plant.

Oil production from the Burr Ferry and South Bearhead Creek fields is sold to various purchasers at prevailing market prices. Our natural gas production from the Burr Ferry field is processed under long term gas processing contracts with Energy Transfer (successor in interest to Eagle Rock Operating, LLC.) South Bearhead Creek natural gas production is sold into the interstate market on Trunkline Gas Company's pipeline at prevailing market prices.

The prices in the tables below do not include the effects of hedging. Quarterly prices and hedge adjusted pricing 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 years ended December 31, 2015, 2014 and 2013.

 
 
Year Ended December 31,
All Fields
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
   Oil (MBbls)
 
2,406

 
3,511

 
3,926

   Natural Gas Liquids (MBbls)
 
1,433

 
1,812

 
2,320

Natural gas (MMcf) (1)
 
43,839

 
38,499

 
29,672

      Total (MBoe)
 
11,146

 
11,740

 
11,191

 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
   Oil (Per Bbl)
 
$
47.11

 
$
92.74

 
$
103.42

   Natural Gas Liquids (Per Bbl)
 
$
14.54

 
$
31.83

 
$
31.39

   Natural gas (Per Mcf)
 
$
2.56

 
$
4.27

 
$
3.70

   Total (Per Boe)
 
$
22.09

 
$
46.66

 
$
52.29

 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
8.25

 
$
9.74

 
$
11.08


(1) Excludes natural gas consumed in operations that is included in reported production volumes of 3,487 MMcf in 2015, 3,884 MMcf in 2014 and 3,325 MMcf in 2013.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.


14


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 83% of the Company's proved reserves based on total Boe as of December 31, 2015:
 
 
Year Ended December 31,
Fasken
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
   Oil (MBbls)
 

 

 

   Natural Gas Liquids (MBbls)
 
2

 
3

 
3

   Natural gas (MMcf) (1)
 
28,598

 
20,738

 
8,457

      Total (MBoe)
 
4,769

 
3,459

 
1,413

 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
   Oil (Per Bbl)
 
$

 
$

 
$

   Natural Gas Liquids (Per Bbl)
 
$
16.66

 
$
32.44

 
$
35.59

   Natural gas (Per Mcf)
 
$
2.52

 
$
4.20

 
$
3.57

   Total (Per Boe)
 
$
15.12

 
$
25.22

 
$
21.46

 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
3.20

 
$
3.77

 
$
4.34


(1) Excludes natural gas consumed in operations that is included in reported production volumes of 434 MMcf in 2015, 636 MMcf in 2014 and 360 MMcf in 2013.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.

 
 
Year Ended December 31,
AWP
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
   Oil (MBbls)
 
1,047

 
1,655

 
1,421

   Natural Gas Liquids (MBbls)
 
843

 
968

 
1,068

   Natural gas (MMcf) (1)
 
10,372

 
10,753

 
10,359

Total (MBoe) (3)
 
3,618

 
4,415

 
4,216

 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
   Oil (Per Bbl)
 
$
45.37

 
$
89.86

 
$
100.42

   Natural Gas Liquids (Per Bbl)
 
$
14.79

 
$
30.72

 
$
30.72

   Natural gas (Per Mcf)
 
$
2.62

 
$
4.31

 
$
3.72

   Total (Per Boe)
 
$
24.07

 
$
50.91

 
$
50.78

 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
8.64

 
$
8.98

 
$
10.50


(1) Excludes natural gas consumed in operations that is included in reported production volumes of 1,574 MMcf in 2015, 1,327 MMcf in 2014 and 1,097 MMcf in 2013.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.
(3) AWP Eagle Ford sales accounted for approximately 69%, 67% and 48% of total BOE sales in 2015, 2014 and 2013, respectively.

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,

15


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. From time to time in the past, to a limited extent we have used derivative instruments to protect against declines in oil and natural gas prices. There were no unsettled derivative assets and no unsettled derivative liabilities at December 31, 2015 as all outstanding hedge agreements had settled as of year-end. For additional discussion related to our price-risk policy, refer to Note 5 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, 2015, the Company employed 228 people. None of our employees were represented by a union and relations with employees are considered to be good.

Facilities

At December 31, 2015, we occupied approximately 119,000 square feet of office space at 17001 Northchase Drive, Houston, Texas. For discussion regarding the term and obligations of this lease refer to Note 6 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.


16


Item 1A. Risk Factors

Risks Related to Bankruptcy:

We are subject to risks and uncertainties associated with our Chapter 11 proceedings.
On December 31, 2015, the Company along with eight of its subsidiaries, including Swift Energy International, Inc., Swift Energy Group, Inc., Swift Energy USA, Inc., Swift Energy Alaska, Inc., Swift Energy Operating, LLC, GASRS LLC, SWENCO-Western, LLC and Swift Energy Exploration Services, Inc., filed voluntary petitions seeking relief under Chapter 11 of the United States Bankruptcy Code. The Chapter 11 bankruptcy proceedings do not include our international subsidiaries, which are 100% owned by our domestic subsidiary Swift Energy International, Inc.
Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to the risks and uncertainties associated with our bankruptcy. These risks include the following:
our ability to prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;
the high costs of bankruptcy proceedings and related fees;
our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;
our ability to maintain contracts that are critical to our operations;
our ability to execute our business plan in the current depressed commodity price environment;
our ability to attract, motivate and retain key employees;
the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
the ability of third parties to seek and obtain court approval to convert the Chapter 11 proceedings to a Chapter 7 proceeding; and
the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans.

Delays in our Chapter 11 proceedings increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.
These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Plan. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 proceedings will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.
We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.
To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. Although the Bankruptcy Court has approved a disclosure statement with respect to the Plan and solicitation of the Plan has commenced, solicitation is not complete and other requirements and statutory conditions necessary for confirmation of the Plan have not yet been satisfied. While a confirmation hearing on the Plan has been scheduled on March 30, 2016, it is possible that hearing could be delayed. It is also possible that the Bankruptcy Court will not confirm the Plan.
Creditors may not vote in favor of our Plan, and certain parties in interest may file objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends

17


upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock).
If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.
Even if a Chapter 11 Plan of Reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.
Even if the Plan or another Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.
Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.
Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if the Plan is confirmed.
We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.
Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. While we entered into a Debtor-in-Possession (DIP) Credit Agreement in connection with the Chapter 11 filings, which provides for a multi-draw term loan in an aggregate amount of up to $75.0 million, as of the date hereof, we have not received a commitment for any additional interim financing or exit financing. Furthermore, our ability to access $45.0 million of the funds available under the DIP Credit Agreement is contingent on our ability to successfully amend and restate or refinance our current $330.0 million revolving credit facility and secure exit financing. Even if we are able to amend and restate or refinance our current revolving credit facility, we do not anticipate any additional liquidity we receive from such an amendment and restatement or refinancing to be substantial.
We do not believe that our borrowings under the DIP Credit Agreement, our cash on hand and our cash flow from operations will be sufficient to continue to fund our operations for any significant period of time. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the Chapter 11 proceedings, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.
In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.
Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.
We believe it is highly likely that the shares of our existing common stock will be canceled in our Chapter 11 proceedings.

18


The Plan provides, among other things, that upon our emergence from bankruptcy, our existing common stock will be canceled and the holders of our existing common stock will receive four percent of the our post-emergence common stock plus warrants. If the Plan confirmed by the Bankruptcy Court, the existing shareholders’ post-emergence shares of common stock and warrants may be subject to further dilution due to subsequent capital raising activities. Additionally, the Plan may not be confirmed by the Bankruptcy Court, in which case, the chance that the existing shareholders will receive little or no distribution in our Chapter 11 proceedings would increase. Accordingly, any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative.
We may be subject to claims that will not be discharged in our Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.
The Bankruptcy Code provides that the confirmation of a Chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a Chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.
Our financial results may be volatile and may not reflect historical trends.
During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.
In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.
Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards and depreciation, depletion and amortization deductions in future years.
Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have net operating loss carryforwards of approximately $822 million as of December 31, 2015. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards and amortizable tax basis in our properties may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Further, future deductions for depreciation, depletion and amortization could be limited if the fair value of our assets is determined to be less than the tax basis.
Risks Related to the Business:

Commodity prices have dropped substantially and rapidly since September 2014. Oil and natural gas prices are highly volatile. Continued low prices or their further downward movement could threaten our ability to emerge from bankruptcy and implement our business plan.

Our future revenues, net income, cash flow, and the value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Our borrowing capacity and ability to obtain additional capital is also

19


dependent on oil and natural gas prices. Oil and natural gas prices have dropped precipitously over the past year and have fallen to their lowest level in 13 years.

Continued low price levels or further decreases in price levels for oil and natural gas could negatively affect us in several ways, including:

impair our ability to obtain funds to operate our business and implement our business plan;
our cash flow would be reduced, decreasing funds available for capital, operating and administrative expenditures;
a substantial number of reserves would no longer be economic to produce, leading to both lower cash flow and lower proved reserves; and
require further future write-downs of our oil and gas properties.

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. Although our 2015 total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $104 million, our 2016 capital expenditure budget has been reduced to $78.0 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.

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

While we anticipate substantially all of our $906 million of long-term unsecured indebtedness will be discharged upon confirmation of our Plan, we will continue to have substantial capital needs upon 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 and implement our business plan. 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 2013, 2014 and 2015 and expect to 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 years ended December 31, 2015, 2014 and 2013, we reported non-cash write-downs on a before-tax basis of, $1.6 billion ($1.5 billion after-tax), $445.4 million ($287.3 million after-tax) and $46.9 million ($30.0 million after-tax) respectively, on our oil and gas properties. If oil and natural gas prices remain at their current low levels or decline further from the prices used in calculating the fourth quarter of 2015 ceiling test, we anticipate that we will be required to record additional non-cash write-downs of oil and gas properties in the first quarter of 2016. Refer to Note 1 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 2015 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 legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique's environmental effects and, in some

20


cases, a moratorium on the use of the technique. Various committees of Congress have been investigating hydraulic fracturing practices and several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Several states have adopted or are otherwise considering legislation to regulate hydraulic fracturing practices, including restrictions on its use in environmentally sensitive areas. Some municipalities have significantly limited or prohibited drilling activities, or are considering doing so.

Although it is not possible at this time to predict the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal or state, or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop oil and gas reserves.

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.

Drilling activities require the use of fresh water. In certain areas, there may be insufficient aquifer capacity to provide a local source of water for drilling activities, and water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas.

Moreover, compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

Our Southeast Louisiana core area can be affected by hurricane activity in the Gulf of Mexico, resulting in pipeline outages or damage to production facilities, causing production delays and/or significant repair costs.

Approximately 5% of our 2015 reserves, 9% of our 2015 production and 18% of our 2015 revenues were located in our Southeast Louisiana core area. Increased hurricane activity over the past ten years has resulted in production curtailments and physical damage to our Gulf Coast operations. For example, a significant percentage of our production was shut down by Hurricanes Gustav and Ike in 2008, and by Hurricane Isaac in 2012. Since we do not carry business interruption insurance (loss of production), if hurricanes damage the Gulf Coast region where we have a significant percentage of our operations, our cash flow would suffer. This decrease in cash flow, depending on the extent of the decrease, could reduce the funds we would have available for capital expenditures and reduce our ability to borrow money or raise additional capital.

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.

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.


21


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 uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater and shoreline contaminates
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.

Governmental laws and regulations relating to environmental protection are costly and stringent.

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing, among other things, the discharge of substances into the environment or otherwise relating to the protection of human health and the environment, including the protection of endangered species. These laws, regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators. Changes in, or additions to, environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or other environmental protection requirements could have a material adverse effect on our operations and financial position.

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) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; (2) Presidential proposals, along with legislation introduced in Congress (none of which have passed), to impose new fees or taxes on, or repeal various tax deductions available to, oil and gas producers, such as the current tax deductions for intangible drilling and development costs and qualified tertiary injectant expenses, which deductions, if eliminated, could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities; (3) legislation previously considered by Congress (but not adopted) that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act, and new, proposed or anticipated Department of Interior and EPA regulations to impose new and more stringent regulatory requirements on hydraulic fracturing activities, particularly those performed on federal lands, and to require disclosure of the chemicals used in the fracturing process; and (4) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties, grants new

22


authority to impose damage prevention and incident notification requirements, and directs the PHMSA to prescribe minimum safety standards for CO2 pipelines.

Any of 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 demand for oil and natural gas or 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 federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the increase of the amortization period of geological and geophysical expenses, (iii) the elimination of current deductions for intangible drilling and development costs and qualified tertiary injectant expenses; and (iv) the elimination of the deduction for certain U.S. production activities. It is currently unclear whether any such proposals will be enacted or what form they might possibly take or impact they may have; however, the passage of such legislation or any other similar change in U.S. federal income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.

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, or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters.

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.

23


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.
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.

24


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 2. 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. Most of our pending legal proceedings have been stayed by virtue of our voluntary petitions filed on December 31, 2015 seeking relief under Chapter 11 of the Bankruptcy Code. 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

None.


25


PART II

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

Common Stock, 2015 and 2014

Our common stock, which was traded on the New York Stock Exchange under the symbol “SFY" prior to being delisted on December 18, 2015, is currently traded on the OTC Pink marketplace under the symbol "SFYWQ". The high and low quarterly closing sale prices for the common stock on the New York Stock Exchange for 2015 and 2014 were as follows:
 
2015
 
2014
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Low
$2.01
$2.00
$0.36
$0.16
 
$9.62
$10.26
$9.60
$2.63
High
$3.86
$3.26
$1.89
$0.72
 
$13.70
$13.01
$12.86
$9.21

The high and low closing sale prices for the common stock on the OTC Pink marketplace for the period from December 18, 2015 through December 31, 2015 were $0.16 and $0.06, respectively. Further, the high and low closing sale prices for the common stock on the OTC Pink marketplace for the Period from January 1, 2016 through February 29, 2016 were $0.15 and $0.06, 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 4 of the consolidated financial statements in this Form 10-K.

We had approximately 156 stockholders of record as of December 31, 2015.

Stock Repurchase Table

The following table summarizes repurchases of our common stock during the fourth quarter of 2015, 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, 2015
 
1,259

 
$
0.70

 

 
$---

November 1- 30, 2015
 
990

 
$
0.40

 

 

December 1 - 31, 2015
 
14,869

 
$
0.24

 

 

Total
 
17,118

 
$
0.28

 

 
$---


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, 2015 see Note 7 of these consolidated financial statements of this Form 10-K.

26


Share Performance Graph

The following Share Performance Graph shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
The graph below presents a comparison of the annual change in the cumulative total return on our common stock over the period from December 31, 2010 to December 31, 2015, with the cumulative total return of the Dow Jones U.S. Exploration & Production Index and the S&P 500 Index, over the same period. The graph assumes an investment of $100 (with reinvestment of all dividends) was invested on December 31, 2010, in our common stock at the closing market price at the beginning of this period and in each of the other indexes.


27


Item 6. Selected Financial Data
(annual data in thousands except share & well amounts)
2015
2014
2013
2012
2011
 
 
 
 
 
 
Total Revenues from Continuing Operations
$
244,721

$
549,456

$
584,401

$
561,486

$
597,809

 
 
 
 
 
 
Income (Loss) from Continuing Operations, Before Income Taxes
$
(1,734,514
)
$
(433,470
)
$
198

$
37,773

$
131,125

 
 
 
 
 
 
Income (Loss) from Continuing Operations
$
(1,653,971
)
$
(283,427
)
$
(2,442
)
$
21,701

$
82,071

 
 
 
 
 
 
Net Cash Provided by Operating Activities - Continuing Operations
$
42,274

$
306,371

$
311,447

$
314,606

$
373,058

 
 
 
 
 
 
Per Share and Share Data
 
 
 
 
 
Weighted Average Shares Outstanding
44,463

43,795

43,331

42,840

42,394

Earnings per Share--Basic
$
(37.20
)
$
(6.47
)
$
(0.06
)
$
0.51

$
1.94

Earnings per Share--Diluted
$
(37.20
)
$
(6.47
)
$
(0.06
)
$
0.50

$
1.91

Shares Outstanding at Year-End
44,592

43,918

43,402

42,930

42,485

Book Value per Share at Year-End
$
(19.12
)
$
18.09

$
24.55

$
24.52

$
23.80

Market Price
 
 
 
 
 
High
$
3.86

$
13.70

$
17.10

$
35.00

$
47.32

Low
$
0.06

$
2.63

$
10.99

$
14.28

$
21.81

Year-End Close
$
0.09

$
4.05

$
13.50

$
15.39

$
29.72

 
 
 
 
 
 
Assets
 
 
 
 
 
Current Assets
$
61,847

$
64,669

$
92,489

$
87,005

$
334,594

Property & Equipment, Net of Accumulated
 
 
 
 
 
Depreciation, Depletion, and Amortization
$
457,903

$
2,095,037

$
2,588,817

$
2,367,954

$
1,892,866

Total Assets
$
524,998

$
2,173,347

$
2,698,505

$
2,473,463

$
2,244,012

 
 
 
 
 
 
Liabilities
 
 
 
 
 
Current Liabilities (1)
$
333,053

$
148,919

$
176,033

$
179,412

$
216,605

Long-Term Debt (1)
$

$
1,074,534

$
1,142,368

$
916,934

$
719,775

Total Liabilities
$
1,377,722

$
1,378,969

$
1,633,155

$
1,420,680

$
1,232,661

 
 
 
 
 
 
Stockholders' Equity
$
(852,724
)
$
794,378

$
1,065,350

$
1,052,783

$
1,011,351

 
 
 
 
 
 
Producing Wells
 
 
 
 
 
Swift Operated
1,030

1,040

1,039

1,069

1,025

Outside Operated
26

25

25

50

46

Total Producing Wells
1,056

1,065

1,064

1,119

1,071

 
 
 
 
 
 
Wells Drilled (Gross)
24

36

48

71

44

 
 
 
 
 
 
Proved Reserves
 
 
 
 
 
Natural Gas (Bcf) (2)
311.7

686.7

815.1

597.6

616.8

Oil Reserves (MBoe) (2)
10.1

49.7

53.0

43.3

30.9

NGL Reserves (MBoe) (2)
8.2

29.7

30.4

49.2

25.8

Total Proved Reserves (MMBoe equivalent) (3)
70.3

193.8

219.2

192.1

159.6

 
 
 
 
 
 
Production (MMBoe equivalent)
11.7

12.4

11.7

11.7

10.5

 
 
 
 
 
 
Average Sales Price (3)
 
 
 
 
 
Natural Gas (per Mcf produced)
$
2.37

$
3.88

$
3.32

$
2.42

$
3.70

Natural Gas Liquids (per barrel)
$
14.54

$
31.83

$
31.39

$
35.07

$
52.13

Oil (per barrel)
$
47.11

$
92.74

$
103.42

$
106.17

$
107.00

Boe Equivalent
$
21.00

$
44.22

$
50.11

$
47.37

$
57.22

(1) Reduction in Long-Term Debt is due to reclassifications of (a) the Company's Senior Notes to Liabilities Subject to Compromise and (2) 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. See Note 1A in this Form 10-K for more information.
(3) These prices do not include the effects of our hedging activities which were recorded in “Price-risk management and other, net” on the accompanying statements of operations. The hedge adjusted prices are detailed in the “Management's Discussion and Analysis of Financial Condition and Results of Operations” section of this Form 10-K.

28


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 years ended December 31, 2015, 2014 and 2013 included with this report. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 41 of this report.

Company Overview

We are an independent oil and natural gas company formed in 1979 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 as well as onshore and inland waters of Louisiana. We hold a large acreage position in Texas prospective for Eagle Ford shale and Olmos tight sands development. Natural gas production accounted for 67% of our 2015 production and 46% of our oil and gas sales, while oil accounted for 21% of our 2015 production and 46% of our oil and gas sales. Combined production of both oil and natural gas constituted 88% of our 2015 production and 92% of our oil and gas sales.

Bankruptcy Proceedings under Chapter 11

Chapter 11 Proceedings. On December 31, 2015, the Company and eight of its subsidiaries (the “Chapter 11 Subsidiaries”) filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (In re Swift Energy Company, et al, Case No. 15-12670).

Debtor-In-Possession. The Company and the Chapter 11 Subsidiaries are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted all motions filed by the Company and the Chapter 11 Subsidiaries that were designed primarily to minimize the impact of the Chapter 11 proceedings on the Company’s operations, customers and employees. As a result, the Company is not only able to conduct normal business activities and pay all associated obligations for the period following its bankruptcy filing, but it is also 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. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court.

Automatic Stay. 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.

Restructuring Support Agreement. Immediately prior to the Chapter 11 filings, a majority of the holders of the Company’s senior notes agreed, pursuant to a restructuring support agreement (the “RSA”), to support a plan under which all of the Company’s senior notes are converted to equity. Under the RSA, holders of the senior notes, certain unsecured creditors, and lenders under the DIP Credit Agreement (see below “Debtor-in-Possession Financing”) are to receive ninety-six percent (96%) of the reorganized company's common stock in exchange for the senior notes, and the existing equity holders are entitled to receive the remaining four percent (4%) of the reorganized company's common stock on a fully diluted basis, subject only to dilution as a result of a proposed new management incentive program. Existing equity holders are also entitled to receive warrants for up to 30% of the reorganized company's equity. Under the RSA, Dean Swick, Managing Director at Alvarez & Marsal North America, LLC, has been appointed to act as Chief Restructuring Officer during the reorganization process.

The RSA includes an agreed timeline for the Chapter 11 proceedings that, if met, would result in the Company emerging from bankruptcy within 110 days of the Chapter 11 filings.

Plan of Reorganization. On February 5, 2016, the Company and the Chapter 11 Subsidiaries filed with the Bankruptcy Court a joint plan of reorganization (the “Plan”), which is supported by an ad hoc committee of the Company’s noteholders, and a related disclosure statement. The Plan is subject to approval by the Bankruptcy Court. The Bankruptcy Court has approved the Company’s disclosure statement with respect to the Plan, and the Company is in the process of soliciting votes with respect to the Plan. A confirmation hearing on the Plan is scheduled on March 30, 2016 in the Bankruptcy Court.

If the Plan is ultimately approved by the Bankruptcy Court, the Company and the Chapter 11 Subsidiaries would exit bankruptcy pursuant to the terms of the Plan. Under the Plan, the claims against and interests in the Company and the Chapter 11 Subsidiaries are grouped into classes based, in part, on their respective priority. The Plan provides that, upon emergence from bankruptcy:

29



the approximately $906 million of indebtedness outstanding on account of the Company’s senior notes and certain other unsecured claims will be exchanged for 88.5% of the post-emergence Company’s common stock;
the lenders under the DIP Credit Agreement (as more fully described below under “Debtor-In-Possession Financing”) will receive a backstop fee consisting of 7.5% of the post-emergence Company’s common stock;
the Company’s current common stock will be canceled and the current shareholders will be entitled to receive the remaining 4% of the post-emergence Company’s common stock and certain warrants; and
claims of other creditors will be paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors.

The Plan also provides that the post-emergence Company’s new board of directors will be made up of seven directors consisting of the Chief Executive Officer of the post-emergence Company, two directors appointed by Strategic Value Partners LLC, a current holder of the Company’s senior notes, two directors appointed by other current holders of the Company’s senior notes, and two independent directors (one of whom will be the new Chairman of the Board).

The Plan is subject to acceptance by certain holders of claims against the Company and the Chapter 11 Subsidiaries and confirmation by the Bankruptcy Court. The Plan is deemed accepted by a class of claims entitled to vote if at least one-half in number and two-thirds in dollar amount of claims actually voting in the class has voted to accept the Plan.

Under certain circumstances set forth in the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. In particular, a plan may be compelled on a rejecting class if the proponent of the plan demonstrates that (1) no class junior to the rejecting class is receiving or retaining property under the plan and (2) no class of claims or interests senior to the rejecting class is being paid more than in full.

Executory Contracts. Subject to certain exceptions, under the Bankruptcy Code, the Company and the Chapter 11 Subsidiaries may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company and the Chapter 11 Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach.

Chapter 11 Filing Impact on Creditors and Stockholders. Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common stock are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. The outcome of the Chapter 11 case remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors and stockholders may receive. It is possible that stockholders will receive no distribution on account of their interests.

Debtor-In-Possession Financing. Pursuant to the RSA, certain holders of the Company’s senior notes agreed to provide the Company and the Chapter 11 Subsidiaries a debtor in possession facility (the “DIP Facility”) pursuant to the terms of a Debtor-in-Possession (“DIP”) Credit Agreement. The DIP Facility has been approved by the Bankruptcy Court. The DIP Credit Agreement provides for a multi-draw term loan in the aggregate amount of up to $75 million, of which the Company has $30 million currently available. The remaining $45 million under the DIP Facility will become available to the Company upon the satisfaction of certain contingencies, including our ability to amend and restate or refinance the indebtedness under the Company’s current first lien credit facility and to obtain exit financing. Pursuant to the Plan, the DIP Facility will be either paid in full in cash or, at the option of the lenders under the DIP Credit Agreement, converted, in full or in part, into the post-emergence Company’s common stock, which common stock will only come from the 88.5% of the common stock to be distributed to the current holders of the senior notes and certain unsecured creditors. For more information refer to Note 4 of these consolidated financial statements.

Financial Statement Classification of Liabilities Subject to Compromise. Our financial statements include amounts classified as Liabilities Subject to Compromise (refer to Note 1A of the consolidated financial statements in this Form 10-K for more information), which represent liabilities that we anticipate will be allowed as claims in our bankruptcy case. These amounts include amounts related to the anticipated rejection of various executory contracts and unexpired leases. Additional amounts may be included in Liabilities Subject to Compromise in future periods if additional executory contracts and unexpired leases are rejected. Conversely, to the extent that such executory contracts or unexpired leases are not rejected and are instead assumed, certain liabilities characterized as subject to compromise may be converted to post-petition liabilities. Because the nature of many of the potential claims has not been determined at this time, the magnitude of such claims is not reasonably estimable at this time. Such claims may be material.


30


Reorganization Expenses. The Company and the Chapter 11 Subsidiaries have incurred and will continue to incur significant costs associated with the reorganization, principally professional fees. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations. In accordance with ASC 852, we have recorded certain costs associated with the bankruptcy proceedings as Reorganization Items within our Consolidated Statement of Operations. For additional information, see “Reorganization Items” below.

Risks Associated with Chapter 11 Proceedings. For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” Because of these risks and uncertainties, the description of our operations, properties and capital plans included in this Form 10-K may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Significant Developments during 2015

Significant decline in crude oil and natural gas prices: Oil prices throughout 2015 were significantly lower than 2014 prices, with our average oil prices received falling from approximately $72 per barrel during the fourth quarter of 2014 to approximately $40 per barrel in the fourth quarter of 2015 (approximately a 44% lower). Natural gas prices were also lower during the same period, with our average natural gas prices received falling from $3.58 per Mcf during the fourth quarter of 2014 to $2.05 per Mcf in the fourth quarter of 2015 (approximately 43% lower).

2015 changes in reserve quantities and value: Our 64%, or 124 MMBoe, decrease in proved reserves quantities from 2014 to 2015 was principally 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, as disclosed in Note 1A of the consolidated financial statements in this Form 10-K. The 81% decrease in our PV-10 Value from 2014 and 2015 reflected not only these quantity decreases, but also the impact of lower commodity prices during 2015.

2015 revenues and net loss: Our 2015 revenues decreased 55% or $304.7 million, when compared to 2014, primarily due to the impact of lower commodity prices and lower oil production volumes, partially offset by higher natural gas production. Revenues decreased due to lower overall commodity pricing as oil prices were 49% lower in 2015, when compared to 2014, natural gas prices were 39% lower in 2015, when compared to 2014, and NGL prices were 54% lower in 2015, when compared to 2014. Revenues also decreased due to lower oil production in our AWP and Lake Washington fields and lower NGL production in our Artesia and AWP fields, partially offset by increased natural gas production volumes from our Fasken field. Our net loss of $1.7 billion for 2015 is primarily due to the $1.6 billion non-cash write-down of our oil and gas properties.

Net cash provided by operating activities: Our net cash provided by operating activities during 2015 was $42.3 million, representing a $264.1 million or 86% decrease, compared to $306.4 million generated during 2014, primarily due to the impacts of lower commodity prices and lower oil and NGL production, partially offset by higher natural gas production and reduced operating and administrative costs excluding non-recurring costs as discussed in the "Cost reduction initiatives" section below.

Capital expenditures: Recent lower oil and natural gas prices have significantly reduced operating cash flows and, as a result, we significantly reduced our capital spending in 2015 compared to 2014 levels. Our capital expenditures on a cash flow basis were $139.7 million during 2015, compared to $386.3 million during 2014. The expenditures were devoted to developmental drilling and completion activity in our South Texas core region as we drilled 5 wells in our AWP Eagle Ford field and 19 wells in our Fasken field during the year. These expenditures were funded by $42.3 million of cash provided by operating activities along with borrowings under our credit facility.
 
Cost reduction initiatives: We have taken significant actions to reduce our future capital, operating and overhead costs. During 2015 we reduced drilling and completion costs and terminated one of our drilling contracts. In conjunction with the reduction in our capital spending plans for 2015, we continued to negotiate with all of our primary suppliers and service companies to reduce our capital and operating cost structures. These initiatives helped us recognize a meaningful reduction of costs during 2015, with our lease operating expenses, excluding workover costs, decreasing from $88.6 million during 2014 to $68.7 million in 2015. By focusing operations in our high quality Fasken and AWP areas we will continue to reduce our development costs by taking advantage of existing infrastructure and experienced operating personnel. During 2015, the Company also implemented various administrative cost savings efforts including a significant headcount reduction and the signing of a new lease agreement for reduced corporate office space. Excluding non-recurring costs incurred during 2015 of approximately $7.2 million for professional and legal fees related to our restructuring efforts and $2.8 million related to the initial

31


implementation of these cost reduction initiatives, our net general and administrative costs decreased by approximately $7.0 million, or 18%, during 2015.

NYSE notice of delisting due to non-compliance with continued listing standards. Trading in the Company’s common stock on the NYSE was suspended intra-day on December 18, 2015, and the common stock was subsequently delisted. The common stock of the Company is currently trading on the OTC Pink marketplace under the symbol “SFYWQ.” The Company can provide no assurance that its common stock will continue to trade on this market, whether broker-dealers will continue to provide public quotes of the Company’s common stock on this market, whether the trading volume of the Company’s common stock will be sufficient to provide for an efficient trading market or whether quotes for the Company’s common stock may be blocked by OTC Markets Group in the future.

Section 382 Rights Agreement.  On November 15, 2015, the Company entered into a Section 382 Rights Agreement (the “Rights Agreement”) with American Stock Transfer & Trust Company, LLC, as rights agent.  The Rights Agreement was adopted in an effort to prevent potential significant limitations under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), on the Company’s ability to utilize its current net operating loss carryforwards (NOLs) to reduce its future tax liabilities. If the Company experiences an "ownership change," as defined in Section 382 of the Code, among 5% shareholders, the Company's ability to fully utilize its NOLs on an annual basis could be substantially limited, which could accordingly significantly impair the value of those tax benefits. The Rights Agreement works by imposing a significant penalty upon any person or group that acquires 4.99% or more of the Company’s common stock or any other class or series of the stock of the Company without the approval of the board of directors of the Company. Subject to certain exceptions set forth in the Rights Agreement, shareholders (i) who currently own 4.99% or more of any class of the Company’s stock, (ii) who inadvertently acquires 4.99% or more of any class of the Company’s stock, or (iii) whose percentage ownership of any class of the Company’s stock increases to 4.99% or more as a result of the Company’s acquisition of the Company’s stock, will not trigger the rights unless they acquire additional shares of such class of the Company’s stock. For more information, see the Company’s Form 8-K filed on November 23, 2015.

Summary of Operational Achievements during 2015

Increasing capacity in the Eagle Ford: During 2015 the Company secured an additional 30 MMcf per day of firm pipeline capacity out of the Fasken area. The Company now has total firm capacity of 190 MMcf per day to support continued development of the Eagle Ford in its Webb County acreage. During the third quarter of 2015, the Company also drilled and completed its first upper Eagle Ford well in Fasken.

Reductions in per well costs: We have seen improved performance this year in our initial production (IP) rates for Eagle Ford wells and have also seen our 2015 average per well drilling costs decreasing, with the average per well drilling cost for our Fasken wells decreasing to $2.4 million during the fourth quarter 2015 from $3.1 million during 2014. We have also experienced efficiency gains in our hydraulic fracturing activities (including the testing of a new enhanced completion design during the third quarter of 2015). We have lowered the overall frac cost per stage while performing more frac stages per well, using additional proppant in each stimulated stage and achieved better overall results as measured by rates of return and net present value. We did not perform any completions during the fourth quarter of 2015, however our third quarter 2015 average completion costs were $3.4 million whereas the average completion costs during 2014 were $4.6 million.

Reductions in operating costs: In addition to the cost reduction initiatives summarized above, during 2016 we are implementing a number of operational cost reduction initiatives, including a reconfiguration of the production gathering system in the Lake Washington field to consolidate production into one platform, and also to temporarily shut in many of our wells with marginal production. Implementation of both of these initiatives is expected to result in significant operating expense reductions.



32


2016 Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operations, borrowings under our credit facility 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.  Our liquidity was severely constrained in 2015, principally due to the deep and precipitous fall of both natural gas and crude oil prices from levels in mid-2014. 

As of February 29, 2016, the Company’s liquidity consists of approximately $22 million of cash-on-hand, plus $30 million of availability under the debtor-in-possession financing provided by certain of the Company’s senior note holders.  As summarized in the "Overview" section above, the DIP Credit Agreement, approved by the Bankruptcy Court on February 2, 2016, provides for a multi-draw term loan in the aggregate amount of up to $75 million, subject to satisfaction of certain conditions set forth in the DIP Credit Agreement as detailed in Note 4 of the consolidated financial statements in this Form 10-K.  The Company anticipates supplementing these amounts, with approximately $13 million of the total proceeds of approximately $49 million, upon closing of the pending Texegy sale of interests in our South Bearhead Creek and Burr Ferry fields. The purchase agreement provides that closing must take place on or prior to March 15, 2016 unless a later date is agreed to mutually. Additionally the Company is seeking incremental borrowing capacity of up to $35 million as part of a renewal, replacement or refinancing of our first-lien secured credit facility, which is currently being negotiated to be put in place as part of the Company’s emergence from bankruptcy.  The timing, terms and incremental borrowing amounts of any such replacement financing cannot be predicted at this time and there is no assurance that we will be able to successfully negotiate such financing.   

As a consequence, as disclosed in our Bankruptcy Court filings, the Company’s current $78.0 million capital budget for 2016 is significantly reduced from 2015 levels, and includes $66 million for completion costs for 12 previously drilled but not completed wells, drilling and completion of 4 wells, drilling but not completion of 8 additional wells, and recompletion of 8 wells. The budget also includes $12.0 million for anticipated regulatory, corporate and other capital costs. During 2016 we intend to focus on drilling activity in our dry gas Fasken area in Webb County and our South AWP area in McMullen County. A portion of our capital expenditure program is discretionary and may be further deferred, if necessary. Our 2016 capital budget and level of operations may be impacted by a variety of factors related to our bankruptcy proceedings, including borrowing availability under our DIP credit agreement, funds received from our disposition of assets in our South Bearhead Creek and Burr Ferry fields, and our ability to obtain (and the amount of) additional financing or exit financing.

Effective November 2, 2015, we executed an amendment to our credit facility, lowering our borrowing base and commitment amount from $375.0 million to $330.0 million.  As of December 31, 2015, we had approximately $324.9 million in outstanding borrowings under our credit facility (excluding $5.1 million in letters of credit). Our first-lien secured credit facility is fully drawn, and we have no availability for further borrowings under the facility.  In 2016, we are paying interest under that facility on a current basis.  Upon a closing of the sale of central Louisiana properties to Texegy discussed above, our outstanding borrowings under the credit facility would be reduced by approximately $35 million through use of proceeds from the sale. 


33


Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter are shown below as of December 31, 2015 prior to filing our bankruptcy petition (in thousands). The amounts of our contractual commitments will likely be significantly different than those shown below following our emergence from bankruptcy. If we obtain the required acceptances and our plan of reorganization is confirmed, our senior notes will be exchanged for equity, some of our contractual obligations will be paid in full or reinstated, and some of our contractual obligations may be amended or rejected. For more information, see "Bankruptcy Proceedings under Chapter 11".
 
2016
2017
2018
2019
2020
Thereafter
Total
Non-cancelable operating leases (1)
$
4,140

$
3,288

$
3,688

$
3,872

$
5,481

$
3,613

$
24,083

Asset retirement obligation (2)
7,165

2,430

2,403

781

60

50,715

63,555

Drilling, Completion and Geoscience Contracts
1,005






1,005

Gas transportation and Processing (3)
14,523

17,750

17,225

16,856

14,336


80,689

7-1/8% senior notes due 2017  

250,000






250,000

8-7/8% senior notes due 2020  




225,000


225,000

7-7/8% senior notes due 2022





400,000

400,000

Interest Cost (4)
78,188

60,375

51,469

51,469

41,484

47,250

330,234

Credit facility (5)

324,900





324,900

Total
$
105,020

$
658,742

$
74,785

$
72,977

$
286,362

$
501,579

$
1,699,466


(1) We signed a new lease commencing on March 1, 2015. For additional discussion regarding the terms and obligations of this lease refer to Note 6 of the consolidated financial statements in this Form 10-K.
(2) Amounts shown by year are the net present value at December 31, 2015.
(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) Amounts shown for 2016 include missed interest payment related to the 2017 Senior Notes originally payable in December 2015 for $8.9 million.
(5) The maturity shown is the credit facility’s original expiration date of November 2017, and does not reflect any acceleration due to filing of our Chapter 11 proceedings. If not for the automatic stay, which came into effect upon the filing of the bankruptcy cases, the credit facility would be due and payable currently. These amounts exclude $5.1 million standby letters of credit outstanding under this facility.

As of December 31, 2015, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

Proved Oil and Gas Reserves

During 2015, our reserves decreased by approximately 124 MMBoe 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, as disclosed in Note 1A of the consolidated financial statements in this Form 10-K. As a result of this reduction, 80% of our total proved reserves as of December 31, 2015 were proved developed, compared with 34% at year-end 2014 and 29% at year-end 2013.

At December 31, 2015, our proved reserves were 70.3 MMBoe with a PV-10 Value of $374.0 million (PV-10 Value is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure), a decrease in the PV-10 Value of approximately $1.6 billion, or 81%, from the prior year-end levels. In 2015, our proved natural gas reserves decreased 375.1 Bcf, or 55%, while our proved oil reserves decreased 39.6 MMBbl, or 80%, and our NGL reserves decreased 21.4 MMBbl, or 72%, for a total equivalent decrease of 124 MMBoe, or 64%.

In prior years we have added proved reserves primarily through our drilling activities, including 18.2 MMBoe added in 2014 and 76.3 MMBoe added in 2013. We obtained reasonable certainty regarding these reserves additions by applying the same methodologies that have been used historically in this area. We also sold approximately 30.9 MMBoe of reserves during 2014 in conjunction with our Fasken joint venture with Saka, as noted in Note 9 of our consolidated financial statements in this Form 10-K.

We use the preceding 12-months' 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 PV-10 Value calculation. Our average natural gas price used in the PV-10 Value calculation for 2015 was $2.61 per Mcf. This average price decreased from the average price of $4.32 per Mcf used

34


in the PV-10 calculation for 2014. Our average oil price used in the PV-10 Value calculation for 2015 was $49.58 per Bbl. This average price decreased from the average price of $93.64 per Bbl used in the PV-10 calculation for 2014.


35



Results of Operations

Revenues — Years Ended December 31, 2015, 2014 and 2013

2015 - Our revenues in 2015 decreased by 55% compared to revenues in 2014, primarily 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 39% lower, and NGL prices were 54% lower.

2014 - Our revenues in 2014 decreased by 6% compared to revenues in 2013, due to the impact of lower oil prices and production volumes, partially offset by higher natural gas production volumes and pricing. Average oil prices we received were 10% lower than those received during 2013, while natural gas prices were 17% higher, and NGL prices were 1% higher.

Crude oil production was 21%, 28% and 33% of our production volumes while crude oil sales were 46%, 59% and 69% of oil and gas sales for the years ended December 31, 2015, 2014 and 2013, respectively. Natural gas production was 67%, 57% and 47% of our production volumes while natural gas sales were 46%, 30% and 19% of oil and gas sales for the years ended December 31, 2015, 2014 and 2013, respectively. The remaining production in each year was from NGLs.

The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2015, 2014 and 2013:
Core Areas
 
Oil and Gas Sales
(In Millions)
 
Net Oil and Gas Production
Volumes (MBoe)
 
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Artesia Wells
 
$
19.3

 
$
62.2

 
$
106.3

 
1,113

 
1,786

 
2,850

AWP
 
87.1

 
224.8

 
214.1

 
3,881

 
4,636

 
4,399

Fasken
 
72.1

 
87.2

 
30.3

 
4,841

 
3,565

 
1,473

Other South Texas
 
3.6

 
8.2

 
9.5

 
209

 
252

 
287

Total South Texas
 
$
182.0

 
$
382.4

 
$
360.2

 
10,044

 
10,239

 
9,009

 
 
 
 
 
 
 
 
 
 
 
 
 
Southeast Louisiana
 
45.4

 
124.2

 
168.0

 
1,061

 
1,459

 
1,797

 
 
 
 
 
 
 
 
 
 
 
 
 
Central Louisiana
 
17.7

 
39.5

 
54.9

 
583

 
656

 
897

 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
1.1

 
1.7

 
2.1

 
39

 
33

 
43

 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
246.3

 
$
547.8

 
$
585.2

 
11,727

 
12,387

 
11,746


Our production decrease from 2014 to 2015 was primarily due to decreased oil production from our AWP and Lake Washington fields and decreased NGL production from our Artesia and AWP fields, partially offset by increased natural gas production at our Fasken field.

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 attributable 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 $102.5 million decrease attributable 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.

In 2014, our $37.4 million, or 6% increase in oil, NGL, and natural gas sales resulted from:

Price variances that had a $9.7 million unfavorable impact on sales, with a decrease of $35.4 million due to the 10% decrease in oil prices received, partially offset by an increase of $24.9 million attributable to the 18% increase in natural gas prices and an increase of $0.8 million due to the 1% increase in NGL prices.

36


Volume variances that had a $27.7 million unfavorable impact on sales, with a $42.7 million decrease attributable to the 0.4 million Bbl decrease in oil production volumes and a $15.9 million decrease due to the 0.5 million Bbl decrease in NGL production volumes, partially offset by a $30.9 million increase due to the 9.4 Bcf increase in natural gas production volumes.

The following table provides additional information regarding our oil and gas sales, excluding any effects of our hedging activities, by quarter, for the years ended December 31, 2015, 2014 and 2013:

 
Production Volume
 
Average Price
 
Oil
 
NGL
 
Gas
 
Combined
 
Oil
 
NGL
 
Gas
 
(MBbl)
 
(MBbl)
 
(Bcf)
 
(MBoe)
 
(Bbl)
 
(Bbl)
 
(Mcf)
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
988
 
557
 
7.6
 
2,819
 
$108.45
 
$29.90
 
$2.96
  Second Quarter
911
 
549
 
7.9
 
2,778
 
$103.15
 
$29.74
 
$3.86
  Third Quarter
1,004
 
600
 
8.7
 
3,057
 
$108.17
 
$31.67
 
$3.15
  Fourth Quarter
1,023
 
615
 
8.7
 
3,092
 
$94.14
 
$33.93
 
$3.32
    Total
3,926
 
2,320
 
32.9
 
11,746
 
$103.42
 
$31.39
 
$3.32
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
931
 
478
 
9.2
 
2,944
 
$99.38
 
$36.27
 
$4.20
  Second Quarter
890
 
434
 
12.7
 
3,449
 
$101.67
 
$33.93
 
$4.16
  Third Quarter
870
 
482
 
9.9
 
2,994
 
$96.12
 
$33.39
 
$3.55
  Fourth Quarter
820
 
418
 
10.6
 
3,000
 
$71.94
 
$22.74
 
$3.58
    Total
3,511
 
1,812
 
42.4
 
12,387
 
$92.74
 
$31.83
 
$3.88
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
685
 
426
 
11.7
 
3,064
 
$45.10
 
$16.09
 
$2.53
  Second Quarter
628
 
366
 
11.3
 
2,875
 
$56.65
 
$15.18
 
$2.40
  Third Quarter
581
 
344
 
11.6
 
2,865
 
$45.24
 
$12.94
 
$2.51
  Fourth Quarter
511
 
297
 
12.7
 
2,923
 
$40.22
 
$13.38
 
$2.05
    Total
2,405
 
1,433
 
47.3
 
11,727
 
$47.11
 
$14.54
 
$2.37

For the years ended December 31, 2015, 2014 and 2013, we recorded net gains (losses) of $0.2 million, $1.3 million and ($0.9) million, respectively, related to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying consolidated statements of operations. Had these amounts been recognized in the oil and gas sales account, our average oil price would have been $47.11, $92.52 and $102.93 for the years ended December 31, 2015, 2014 and 2013, respectively, and our average natural gas price would have been $2.37, $3.93 and $3.35 for the years ended December 31, 2015, 2014 and 2013, respectively.

Costs and Expenses

2015 - Our expenses in 2015 decreased $126.9 million when compared to those in 2014 (excluding the 2015 and 2014 ceiling test write-downs and 2015 reorganization items resulting from the Company's bankruptcy proceedings), for the reasons noted below. During 2015, we saw a decrease in the cost of services and supplies due to the decline in commodity prices.

Lease Operating Cost. These expenses decreased $23.0 million, or 25%, compared to the level of such expenses for the year ended December 31, 2014, primarily due to lower labor costs, maintenance costs, salt water disposal costs and lower supervision fees (i.e. overhead rates) charged to LOE. Our lease operating costs per Boe produced were $5.99 and $7.52 for the years ended December 31, 2015 and 2014, respectively.

Transportation and gas processing. These expenses increased $0.6 million, or 3%, compared to the level of such expenses for the year ended December 31, 2014. Our transportation and gas processing costs per Boe produced were $1.85 and $1.71 for the years ended December 31, 2015 and 2014, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses decreased $90.1 million, or 34%, from those during the year ended December 31, 2014, due to decreased production and a lower depletable base. Our DD&A rate per Boe of production was $15.14 and $21.60 for the years ended December 31, 2015 and 2014, respectively.

General and Administrative Expenses, Net. These expenses increased $3.0 million or 8%, compared to the level of such expenses for the year ended December 31, 2014, due to higher legal and professional fees and lower capitalized costs, partially

37


offset by lower salaries and burdens, lower temporary labor and lower stock compensation . For the years ended December 31, 2015 and 2014, our capitalized general and administrative costs totaled $12.7 million and $26.3 million, respectively. Our net general and administrative expenses per Boe produced were $3.63 and $3.20 for the years ended December 31, 2015 and 2014, respectively. The supervision fees recorded as a reduction to general and administrative expenses were $9.2 million and $12.7 million for the years ended December 31, 2015 and 2014, respectively.

Severance and Other Taxes. These expenses decreased $19.9 million, or 54%, from the year ended December 31, 2014. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.9% and 6.8% for the years ended December 31, 2015 and 2014, respectively.
 
Interest. Our gross interest cost for the year ended December 31, 2015 was $80.8 million, of which $4.9 million was capitalized. Our gross interest cost for the year ended December 31, 2014 was $78.2 million, of which $5.0 million was capitalized. The increase in interest came from increased credit facility borrowings during 2015.

Write-down of oil and gas properties. Due to the effects of pricing, timing of projects, changes in our reserves product mix, and our bankruptcy filing as discussed in Note 1A, in 2015 and 2014 we reported non-cash write-downs on a before-tax basis of $1.6 billion ($1.5 billion after tax) and $445.4 million ($287.3 million after tax), respectively, for our oil and natural gas properties.

Reorganization Items. Incurred $6.6 million expense for the year ended December 31, 2015 due to the write-off of debt issuance costs, premiums and discounts associated with our senior notes as a result of our bankruptcy filing.

Income Taxes. Our effective income tax rate was 4.6% for the year ended December 31, 2015. For the year ended December 31, 2014 the rate was 34.6% due to valuation allowances offsetting tax benefits of recorded losses.

2014 - Our expenses for the year ended December 31, 2014 increased $398.7 million, or 68%, compared to the prior year levels, for the reasons noted below. Our expenses in 2014 increased $0.3 million when compared to those in 2013 (excluding the 2014 and 2013 ceiling test write-downs). During 2014, we saw some tightening in the availability of services and supplies including some upward pressure on service costs.

Lease Operating Cost. These expenses decreased $6.5 million, or 7%, compared to the level of such expenses for the year ended December 31, 2013, primarily due to lower salt water disposal, labor and maintenance costs, partially offset by higher utilities costs. Our lease operating costs per Boe produced were $7.52 and $8.49 for the years ended December 31, 2014 and 2013, respectively.

Transportation and gas processing. These expenses were comparable to the level of such expenses for the year ended December 31, 2013. Our transportation and gas processing costs per Boe produced were $1.71 and $1.79 for the years ended December 31, 2014 and 2013, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses increased $14.8 million, or 6%, from those during the year ended December 31, 2013, due to increased production and a higher depletable base. Our DD&A rate per Boe of production was $21.60 and $21.52 for the years ended December 31, 2014 and 2013, respectively.

General and Administrative Expenses, Net. These expenses decreased $5.8 million or 13%, compared to the level of such expenses for the year ended December 31, 2013, due to lower stock compensation, a lower benefit accrual and lower salaries, partially offset by higher legal fees and lower capitalized costs. For the years ended December 31, 2014 and 2013, our capitalized general and administrative costs totaled $26.3 million and $31.8 million, respectively. Our net general and administrative expenses per Boe produced were $3.20 and $3.87 for the years ended December 31, 2014 and 2013, respectively. The supervision fees recorded as a reduction to general and administrative expenses were $12.7 million and $11.6 million for the years ended December 31, 2014 and 2013, respectively.

Severance and Other Taxes. These expenses decreased $5.7 million, or 13%, from the year ended December 31, 2013. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.8% and 7.3% for the years ended December 31, 2014 and 2013, respectively. The change in rate was primarily driven by higher production in South Texas which carried a lower severance tax rate than in Louisiana.
 
Interest. Our gross interest cost for the year ended December 31, 2014 was $78.2 million, of which $5.0 million was capitalized. Our gross interest cost for the year ended December 31, 2013 was $76.6 million, of which $7.2 million was capitalized. The increase in interest came from increased credit facility borrowings during 2014.


38


Write-down of oil and gas properties. Due to the effects of pricing, timing of projects and changes in our reserves product mix, in 2014 and 2013 we reported non-cash write-downs on a before-tax basis of $445.4 million ($287.3 million after tax) and $46.9 million ($30.0 million after tax), respectively, for our oil and natural gas properties.

Income Taxes. Our effective income tax rate was 34.6% for the year ended December 31, 2014. For the year ended December 31, 2013 the rate was over 100% due to the proportional effect of non-deductible expenses compared to pre-tax book income that was close to break-even.

Critical Accounting Policies and New Accounting Pronouncements

Bankruptcy Proceedings. We have applied ASC 852 “Reorganizations” in preparing our consolidated yearly financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in Reorganization items, in the accompanying Consolidated Statements of Operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our consolidated balance sheets at December 31, 2015 in "Liabilities Subject to Compromise". These liabilities are reported at the amounts we anticipate will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 1A in this Form 10-K for more information regarding Liabilities Subject to Compromise and Reorganization items.

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method.

The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.

The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of unproved properties. The estimation process for both reserves and the impairment of unproved properties is subjective, and results may change over time based on current information and industry conditions. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects ("Ceiling Test").

Principally due to the effects of pricing, and also due to the timing of projects, changes in our reserves product mix, and the effect of our bankruptcy filing as discussed in Note 1A, in 2015 and 2014 we reported non-cash write-downs on a before-tax basis of $1.6 billion ($1.5 billion after tax) and $445.4 million ($287.3 million after tax), respectively, on our oil and natural gas properties.

We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.

If oil and natural gas prices remain low or decline from the prices used in the Ceiling Test, it is likely that additional non-cash write-downs of oil and gas properties will occur in the future. If future capital expenditures out pace future discounted net cash flows in our reserve calculations or if we have significant declines in our oil and natural gas reserves volumes, which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves, non-cash write-downs of our oil and

39


natural gas properties would occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties if a decrease in oil and/or natural gas prices were to occur. However, due to current trends in commodity pricing it is likely that we will record additional ceiling test write-downs in future periods.

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09 which provides a single, comprehensive revenue recognition model for all contracts with customers across various industries. The guidance is effective for annual and interim reporting periods beginning after December 15, 2016. We have not completed our review of these new requirements to determine the impact of this guidance on our financial statements.

In April 2015, the FASB issued ASU 2015-03, providing guidance on the presentation of debt issuance costs. The guidance requires debt issuance costs related to our debt to be presented on the balance sheet as a reduction of the carrying amount of the debt liability. This guidance is effective for fiscal years beginning after December 15, 2015 and for interim periods within those fiscal years, with early adoption permitted and retrospective application required. This guidance, which we plan to adopt beginning with the first quarter of 2016, is not expected to have a material impact on our financial statements.

In July 2015, the FASB issued ASU 2015-11, which changes the measurement principle for inventory from the lower of cost or market to “lower of cost and net realizable value.” The standard simplifies the current guidance under which an entity must measure inventory at the lower of cost or market (market in this context is defined as one of three different measures, one of which is net realizable value). Net realizable value is defined as the “estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation.” The guidance is effective for fiscal years beginning after December 15, 2016, including interim periods thereafter, and must be applied prospectively after the date of adoption. We are currently reviewing the new requirement to determine the impact of this guidance on our financial statements.

In November 15, the FASB issued ASU 2015-17, which requires companies to classify all deferred tax assets and liabilities as non-current on the balance sheet instead of separating deferred taxes into current and non-current amounts. The guidance is effective for fiscal years beginning after December 15, 2016, including interim periods thereafter, with early adoption permitted and either with prospective or retrospective application permitted. We do not expect this new guidance to have a material impact on our financial statements.
  



40


Forward-Looking Statements

This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated production levels, reserve increases, capital expenditures, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words "could," "believe," "anticipate," "intend," "estimate," “budgeted”, "expect," "may," continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

• expectations regarding the outcome of our bankruptcy proceedings, including our ability to confirm our plan of
reorganization and emerge from bankruptcy;
• future cash flows and their adequacy to fund the costs of our bankruptcy proceedings and our ongoing operations;
• our plan of reorganization filed in connection with our bankruptcy proceedings;
• oil and natural gas pricing expectations;
• liquidity, including our ability to satisfy our short- or long-term liquidity needs;
• business strategy, including our business strategy post-emergence from bankruptcy;
• estimated oil and natural gas reserves or the present value thereof;
• our borrowing capacity, future covenant compliance, cash flows and liquidity;
• financial strategy, budget, projections and operating results;
• asset disposition efforts or the timing or outcome thereof;
• prospective joint ventures, their structure and substance, and the likelihood of their finalization or the timing thereof;
• the amount, nature and timing of capital expenditures, including future development costs;
• timing, cost and amount of future production of oil and natural gas;
• availability of drilling and production equipment or availability of oil field labor;
• availability, cost and terms of capital;
• drilling of wells;
• availability and cost for transportation of oil and natural gas;
• costs of exploiting and developing our properties and conducting other operations;
• competition in the oil and natural gas industry;
• general economic conditions;
• opportunities to monetize assets;
• effectiveness of our risk management activities;
• environmental liabilities;
• counterparty credit risk;
• governmental regulation and taxation of the oil and natural gas industry;
• developments in world oil markets and in oil and natural gas-producing countries;
• uncertainty regarding our future operating results; and
• plans, objectives, expectations and intentions contained in this report that are not historical.

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk factors" in Item 1A of our annual report on Form 10-K for the year ended December 31, 2015. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.


41


All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

42


Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. 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. This commodity pricing volatility has continued with unpredictable price swings in recent periods.

Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our credit facility. For additional discussion related to our price-risk management policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.

Income Tax Carryforwards. As of December 31, 2015, the Company has net deferred tax carryforward assets of $287.7 million for federal net operating losses, $2.1 million for federal alternative minimum tax credits and $18.4 million for deferred state tax net operating loss carryforwards. In management's judgment it is more likely than not that the company will not be able to utilize these carryforward assets to reduce future taxes. Accordingly these carryovers are all fully reserved by a valuation allowance.

Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and from certain customers we also obtain letters of credit, parent company guarantees if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Concentration of Sales Risk. Over the last several years, a large portion of our oil and gas sales have been to Shell Oil Corporation and affiliates and we expect to continue this relationship in the future. For the years ended December 31, 2015, 2014 and 2013, Shell Oil Company and affiliates accounted for 16%, 21% and 33% of our total oil and gas gross receipts, respectively. We believe that the risk of these unsecured receivables is mitigated by the short-term sales agreements we have in place as well as the size, reputation and nature of their business.

Interest Rate Risk. Our senior notes due in 2017, 2020 and 2022 have fixed interest rates, so consequently we are not exposed to cash flow risk from market interest rate changes on these notes. At December 31, 2015, we had $324.9 million drawn under our credit facility, which bears a floating rate of interest and therefore is susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank’s base rate would constitute 35 basis points and would not have a material adverse effect on our future cash flows.



43


Item 8. Financial Statements and Supplementary Data
Page
 
 
Management's Report on Internal Control Over Financial Reporting
 
 
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting