Attached files

file filename
EX-21 - LIST OF SUBSIDIARIES OF SWIFT ENERGY COMPANY - SILVERBOW RESOURCES, INC.a201410k-exhibit21.htm
EX-31.1 - CERTIFICATION OF CEO (SECTION 302) - SILVERBOW RESOURCES, INC.a201410k-exhibit311.htm
EX-23.1 - CONSENT OF H.J. GRUY AND ASSOCIATES, INC - SILVERBOW RESOURCES, INC.a201410k-exhibit231.htm
EX-23.2 - CONSENT OF ERNST AND YOUNG LLP - SILVERBOW RESOURCES, INC.a201410k-exhibit232.htm
EX-10.21 - RETIREMENT AND RELEASE AGREEMENT - SILVERBOW RESOURCES, INC.a201410k-exhibit1021.htm
EXCEL - IDEA: XBRL DOCUMENT - SILVERBOW RESOURCES, INC.Financial_Report.xls
EX-32 - CERTIFICATION OF CEO AND CFO (SECTION 906) - SILVERBOW RESOURCES, INC.a201410k-exhibit32.htm
EX-99.1 - REPORT OF H.J. GRUY AND ASSOCIATES, INC - SILVERBOW RESOURCES, INC.a201410k-exhibit991.htm
EX-12 - RATIO OF EARNINGS TO FIXED CHARGES - SILVERBOW RESOURCES, INC.a201410k-exhibit12.htm
EX-31.2 - CERTIFICATION OF CFO (SECTION 302) - SILVERBOW RESOURCES, INC.a201410k-exhibit312.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, 2014

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.)
 
 
16825 Northchase Drive, Suite 400
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
New York Stock Exchange

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.
þ

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
þ
 
Accelerated filer
o 
 
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, 2014, the last business day of June 2014, was approximately $551,832,992.

The number of shares of common stock outstanding as of January 31, 2015 was 44,006,995.

Documents Incorporated by Reference

Proxy Statement for the Annual Meeting of Shareholders to be held May 19, 2015
Part III, Items 10, 11, 12, 13 and 14


2


Form 10-K
Swift Energy Company and Subsidiaries

10-K Part and Item No.
Part I
 
Page
 
 
 
Items 1 & 2
Business and Properties
 
 
 
Item 1A.
Risk Factors
 15
 
 
 
Item 1B.
Unresolved Staff Comments
 
 
 
Item 3.
Legal Proceedings
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
Part II
 
 
 
 
 
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
 
 
Item 6.
Selected Financial Data
 
 
 
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
Item 8.
Financial Statements and Supplementary Data
 
 
 
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
 
 
Item 9A.
Controls and Procedures
 
 
 
Item 9B.
Other Information
 
 
 
Part III
 
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance (1)
 
 
 
Item 11.
Executive Compensation (1)
 
 
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters (1)
 
 
 
Item 13.
Certain Relationships and Related Transactions, and Director Independence (1)
 
 
 
Item 14.
Principal Accountant Fees and Services (1)
 
 
 
Part IV
 
 
 
 
 
Item 15.
Exhibits and Financial Statement Schedules
 
 
 
(1) Incorporated by reference from Proxy Statement for the Annual Meeting of Shareholders to be held May 19, 2015



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 21 and 22 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 99% 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 2015 planned capital expenditures of $110 to $125 million, in this area.

At December 31, 2014, we had estimated proved reserves of 193.8 MMBoe with a PV-10 Value of $1.9 billion (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 closest GAAP measure). Our total proved reserves at December 31, 2014 were approximately 26% crude oil, 59% natural gas, and 15% NGLs while 34% of our total proved reserves were developed. Approximately 81% of our proved reserves are located in Texas with the remainder in Louisiana.

Business Strategy

Our primary business strategy is to increase our reserves, production and cash flows at an attractive rate of return on invested capital. 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 believe our current acreage position in the Eagle Ford provides us the ability to continue to increase reserves and production at competitive costs and at attractive rates of return. During 2014, we drilled 36 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.

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.

Acquire strategic and complementary assets. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects in our existing core area in the Eagle Ford. We focus particularly on opportunities where we believe our operational efficiency, reservoir management and geological expertise in unconventional oil and gas properties will enhance value and performance.

Efficiently finance growth. During 2014, we closed a transaction with Saka Energi to develop 8,300 acres of natural gas Eagle Ford shale properties in our Fasken area. Saka Energi purchased a 36% full participating interest in the properties for $175 million. The proceeds from the transaction were used to pay down our credit facility which were partially offset by subsequent additional borrowings against the credit facility to fund development expenditures.


4


Competitive Strengths

Premier Eagle Ford Operator

We have operational history, experience and success in South Texas that is unmatched by many other operators. We first acquired producing properties in our AWP field in 1989, added adjacent acreage shortly thereafter and launched our first aggressive drilling program in 1994. This area has remained a cornerstone of our operations as we have pursued other opportunities. While the combination of proven drilling and completion technologies have allowed us to begin to exploit the Eagle Ford shale, we have applied the same methods to further develop the “mature” Olmos sand. As a result, we substantially increased our Olmos production even though we have been producing from this formation for over 20 years. Almost all of our existing South Texas interest overlays portions of the Eagle Ford shale play which is being developed through the combination of horizontal drilling and multi-stage fracture stimulation completion techniques. 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. In 2014, we successfully drilled 36 horizontal wells in our South Texas area using this technology.

High Quality Reserve Base

We have grown our proved reserves from 112.9 MMBoe to 193.8 MMBoe over the five-year period ended December 31, 2014. Over the same period, our annual production has grown from 8.3 MMBoe to 12.4 MMBoe. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities in our core areas. Based on our long-term historical performance and our business strategy going forward, we believe that we have the opportunities, experience, and knowledge to continue growing both our reserves and production. We have replaced approximately 248% of our production on average over the last five years with our new reserves.

Experienced Technical Team

We employ 56 oil and gas technical professionals, including geophysicists, petrophysicists, geologists, petroleum engineers and production and reservoir engineers, who have an average of approximately 24 years of experience in their technical fields and have been employed by us for an average of approximately seven 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 2014 year-end proved reserves of 193.8 MMBoe and production of 12.4 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
 
8.4

 
14.0

 
22.4

 
11.5
%
 
53.3
%
 
1,786

AWP
 
26.5

 
41.2

 
67.7

 
34.9
%
 
54.8
%
 
4,636

Fasken
 
18.4

 
45.6

 
64.0

 
33.0
%
 
%
 
3,565

Other South Texas
 
3.5

 

 
3.5

 
1.8
%
 
53.1
%
 
252

Total South Texas
 
56.8

 
100.8

 
157.6

 
81.2
%
 
 
 
10,239

 
 
 
 
 
 
 
 
 
 
 
 
 
Southeast Louisiana
 
5.7

 
5.9

 
11.6

 
6.0
%
 
93.6
%
 
1,459

 
 
 
 
 
 
 
 
 
 
 
 
 
Central Louisiana
 
3.7

 
20.8

 
24.5

 
12.7
%
 
71.9
%
 
656

 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
0.1

 

 
0.1

 
0.1
%
 
0.5
%
 
33

 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
66.3

 
127.5

 
193.8

 
100.0
%
 
40.9
%
 
12,387



5


South Texas

AWP. During 2014, the Company drilled 20 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 41% natural gas, 22% NGLs, and 36% oil on a Boe basis. As of December 31, 2014 we had identified 120 proved undeveloped locations.

In the Olmos formation, the wells are operated and owned by Swift Energy and our reserves in this formation are approximately 58% natural gas, 31% NGLs, and 11% oil on a Boe basis. At December 31, 2014, we had seven proved undeveloped locations in the Olmos.

Artesia Wells. Our December 31, 2014 proved reserves in this formation are 47% natural gas, 35% NGLs, and 18% oil on a Boe basis. At December 31, 2014, we had identified 31 proved undeveloped locations.

Fasken. During 2014, the Company drilled 16 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, 2014, we had identified 45 proved undeveloped locations.

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 8 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 97% 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 2014 we did not drill any wells in Lake Washington, but in our 2014 production optimization program we performed 23 recompletions and numerous production enhancement operations including sliding sleeve changes, gas lift modifications and well stimulations. At December 31, 2014, we had 26 proved undeveloped locations in this field.

Bay de Chene. The Bay de Chene field is located approximately 25 miles from the Lake Washington field and produces from Miocene sands surrounding a central salt dome. At December 31, 2014, we had one proved undeveloped location in the Bay de Chene field.

Central Louisiana

Burr Ferry. This field is predominately located in Vernon Parish, Louisiana. During 2014 our joint venture agreement for a portion of the field expired and was not renewed. The reserves are approximately 59% oil and NGLs. We have identified 23 proved undeveloped locations in this field.

Masters Creek. Located in Vernon Parish and Rapides Parish, Louisiana, this field produces oil and natural gas from the Austin Chalk formation. The reserves are approximately 61% oil and NGLs.

South Bearhead Creek. This field is located approximately 50 miles south of our Masters Creek field 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. At December 31, 2014, we had 49 proved undeveloped locations in this field.

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, 2014, 2013 and 2012. The information set forth in the tables regarding reserves is based on proved reserves reports we have prepared. Our Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of our 2014 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 97% of our proved reserves for the years ended December 31, 2014 and 2013 and 96% of our proved

6


reserves for the year ended December 31, 2012. 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 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, for the years ended December 31, 2014, 2013 and 2012 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 2014 average adjusted prices after differentials for operations were $4.32 per Mcf of natural gas, $93.64 per barrel of oil, and $33.00 per barrel of NGL, compared to $3.41 per Mcf of natural gas, $104.38 per barrel of oil, and $31.68 per barrel of NGL for 2013 and $2.71 per Mcf of natural gas, $103.64 per barrel of oil, and $46.22 per barrel of NGL for 2012.

The 2014 prices noted above do not fully reflect significant crude oil and natural gas price declines in late 2014 or early 2015 when these commodity prices dropped rapidly, declining to below $45 per barrel of oil (as measured using the WTI crude oil price and below $3.00 per Mcf of natural gas (as measured using the Henry Hub natural gas spot price).


7


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, 2014, 2013 and 2012. 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. 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,
 
 
2014
 
2013
 
2012
Natural gas reserves (MMcf):
 
 
 
 
 
 
   Proved developed
 
232,807

 
197,816

 
195,643

   Proved undeveloped
 
453,940

 
617,309

 
401,926

      Total
 
686,747

 
815,125

 
597,569

Oil reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
14,989

 
16,884

 
17,780

   Proved undeveloped
 
34,717

 
36,110

 
25,479

      Total
 
49,706

 
52,994

 
43,259

NGL reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
12,495

 
13,059

 
15,328

   Proved undeveloped
 
17,168

 
17,320

 
33,891

      Total
 
29,663

 
30,379

 
49,219

 
 
 
 
 
 
 
Total Estimated Reserves (MBoe) (1)
 
193,826

 
219,227

 
192,073

 
 
 
 
 
 
 
Estimated Discounted Present Value of Proved Reserves (in millions)
 
 
 
 
 
 
Proved developed
 
$
954

 
$
1,028

 
$
1,201

Proved undeveloped
 
990

 
1,397

 
1,083

PV-10 Value (2)
 
$
1,944

 
$
2,425

 
$
2,284


(1) The 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, 2014, 2013 and 2012 are net of $85.5 million, $87.0 million, and $89.6 million of asset retirement obligation liabilities, respectively.

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 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.


8


The following table provides a reconciliation between the PV-10 Value and the Standardized Measure.
 
As of December 31,
(in millions)
2014
 
2013
 
2012
PV-10 Value
$
1,944

 
$
2,425

 
$
2,284

 
 
 
 
 
 
Future income taxes (discounted at 10%)
(292
)
 
(423
)
 
(412
)
Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves
$
1,652

 
$
2,002

 
$
1,872


Proved Undeveloped Reserves

The following table sets forth the aging of our proved undeveloped reserves as of December 31, 2014:
Year Added
 
Volume
(MMBoe)
 
% of PUD
Volumes
2014
 
22.0
 
17
%
2013
 
93.4
 
73
%
2012
 
11.4
 
9
%
2011
 
0.7
 
1
%
2010
 
0.0
 
%
Total
 
127.5
 
100
%

During 2014, our proved undeveloped reserves decreased by approximately 23 MMBoe due to the sale of our Fasken properties, which is discussed further in Note 8 of the consolidated financial statements in this Form 10-K. We also incurred approximately $226 million in capital expenditures during the year which resulted in the conversion of 21 MMBoe of our December 31, 2013 proved undeveloped reserves to proved developed reserves in the Fasken and AWP fields. These reductions were partially offset by the addition of approximately 15 MMBoe in proved undeveloped reserves in the AWP area based on the results of our drilling program.

The PV-10 Value from our proved undeveloped reserves was $1.0 billion at December 31, 2014, which was approximately 51% of our total PV-10 Value of $1.9 billion. The PV-10 Value of our proved undeveloped reserves, by year of booking, was 14% in 2014, 73% in 2013, 11% in 2012 and 2% in 2011.

Sensitivity of Reserves to Pricing

As of December 31, 2014, a 5% increase in oil and NGL pricing would increase our total estimated proved reserves of 193.8 MMBoe by approximately 0.4 MMBoe, and would increase the PV-10 Value of $1.9 billion by approximately $146 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.4 MMBoe and would decrease the PV-10 Value by approximately $143 million.

As of December 31, 2014, a 5% increase in natural gas pricing would increase our total estimated proved reserves by approximately 0.2 MMBoe and would increase the PV-10 Value by approximately $75 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated proved reserves by approximately 0.2 MMBoe and would decrease the PV-10 Value by approximately $72 million.


9


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, 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

December 31, 2012
 
 
 
 
 
Gross
375

 
744

 
1,119

Net
345.9

 
713.5

 
1,059.4


(1)
Excludes 49, 60 and 59 service wells in 2014, 2013 and 2012.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2014:
 
Developed
 
Undeveloped
 
Gross
 
Net
 
Gross
 
Net
Colorado

 

 
76,265

 
56,537

Louisiana (1)
116,891

 
103,571

 
99,628

 
79,772

Texas (2)
68,518

 
64,147

 
24,867

 
22,755

Wyoming

 

 
3,797

 
1,602

Total
185,409

 
167,718

 
204,557

 
160,666


(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 36,316 gross and 29,706 net developed acres and 34,455 gross and 27,010 net undeveloped acres. A large portion of our undeveloped Eagle Ford acreage underlies developed Olmos acreage. In the Olmos, we have 49,917 gross and 46,518 net developed acres and 24,526 gross and 21,940 net undeveloped acres.

As of December 31, 2014, Swift Energy's net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 10% in 2015, 4% in 2016 and 11% in 2017. In most cases, acreage scheduled to expire can be held through drilling operations or we can exercise extension options. 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.


10


Drilling and Other Exploratory and Development Activities

The following table sets forth the results of our drilling activities during the years ended December 31, 2014, 2013 and 2012:
 
 
 
 
Gross Wells
 
Net Wells
Year
 
Type of Well
 
Total
 
Producing
 
Dry
 
Total
 
Producing
 
Dry
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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
71

 
71

 

 
66.2

 
66.2

 


Present Activities

As of December 31, 2014, we were in the process of drilling five development wells in our South Texas Area, of which four wells were in the Fasken field with a 64% working interest and one well was in the AWP field with a 100% working interest.

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 administrated 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 2014 totaled $12.7 million and ranged from $383 to $1,945 per well per month.

Fixed and Determinable Commitments

As of December 31, 2014, we had natural gas sales commitments to deliver fixed and determinable quantities of natural gas under term contracts in the amount of 18.3 MMBTU. The sales price is tied to current spot gas prices at the time of delivery. Delivery quantities in excess of the minimums for any given year will proportionally reduce the minimum quantities for subsequent periods. The delivery point is in South Texas, and the Company's proven reserves and production rates in the area significantly exceed the minimum obligations. There is no dedication of production from specific leases under the agreement.

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, 2014, 2013 and 2012, Shell Oil Company and affiliates accounted for 21%, 33% and 46% of our total oil and gas gross receipts, respectively. Kinder Morgan and Plains Marketing accounting for approximately 20% and 11% of our total oil and gas gross receipts in 2014, respectively. BP America accounted for approximately 21% of our total oil and gas gross receipts in 2013 while Southcross Energy accounted for approximately 11% of our total oil and gas gross receipts in 2012. Credit losses in each of the last three years were immaterial. Due to the demand for oil and natural gas and the availability of other purchasers, we do not believe that the loss of any single oil or natural gas purchaser or contract would materially affect our revenues.


11


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.

We have a gathering agreement with Howard Energy providing for the transportation of our Eagle Ford production on the new pipeline from Fasken to Kinder Morgan Texas Pipeline, 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.

In 2012, we entered into 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 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 or at fixed prices tied to the then current NYMEX crude oil contract for the applicable month(s). Historically, our natural gas production from this field is either consumed on the lease or is delivered to El Paso's Southern Natural Gas pipeline system and the processing of natural gas occurs at the Toca Plant.

Oil production from the Burr Ferry, Masters Creek and South Bearhead Creek fields is sold to various purchasers at prevailing market prices. Our natural gas production from the Burr Ferry and Masters Creek fields is processed under long term gas processing contracts with 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 in the “Management's Discussion and Analysis of Financial Condition and Results of Operations” section of 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, 2014, 2013 and 2012.

 
 
Year Ended December 31,
All Fields
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
   Oil (MBbls)
 
3,511

 
3,926

 
3,774

   Natural Gas Liquids (MBbls)
 
1,812

 
2,320

 
1,862

Natural gas (MMcf) (1)
 
38,499

 
29,672

 
33,462

      Total (MBoe)
 
11,740

 
11,191

 
11,213

 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
   Oil (Per Bbl)
 
$
92.74

 
$
103.42

 
$
106.17

   Natural Gas Liquids (Per Bbl)
 
$
31.83

 
$
31.39

 
$
35.07

   Natural gas (Per Mcf)
 
$
4.27

 
$
3.70

 
$
2.64

 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
9.74

 
$
11.08

 
$
10.30


(1) Excludes natural gas consumed in operations that is included in reported production volumes of 3,884 MMcf in 2014, 3,325 MMcf in 2013 and 2,924 MMcf in 2012.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.


12


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 68% of the Company's proved reserves based on total Boe as of December 31, 2014:
 
 
Year Ended December 31,
Fasken
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
   Oil (MBbls)
 

 

 

   Natural Gas Liquids (MBbls)
 
3

 
3

 
1

   Natural gas (MMcf) (1)
 
20,738

 
8,457

 
12,460

      Total (MBoe)
 
3,459

 
1,413

 
2,078

 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
   Oil (Per Bbl)
 
$

 
$

 
$

   Natural Gas Liquids (Per Bbl)
 
$
32.44

 
$
35.59

 
$
37.85

   Natural gas (Per Mcf)
 
$
4.20

 
$
3.57

 
$
2.47

 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
3.77

 
$
4.34

 
$
4.06


(1) Excludes natural gas consumed in operations that is included in reported production volumes of 636 MMcf in 2014, 360 MMcf in 2013 and 541 MMcf in 2012.
(2) Average production cost includes transportation and gas processing costs but excludes severance and ad valorem taxes.

 
 
Year Ended December 31,
AWP
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
Net Sales Volume:
 
 
 
 
 
 
   Oil (MBbls)
 
1,655

 
1,421

 
1,167

   Natural Gas Liquids (MBbls)
 
968

 
1,068

 
1,139

   Natural gas (MMcf) (1)
 
10,753

 
10,359

 
12,910

Total (MBoe) (3)
 
4,415

 
4,216

 
4,458

 
 
 
 
 
 
 
Average Sales Price:
 
 
 
 
 
 
   Oil (Per Bbl)
 
$
89.86

 
$
100.42

 
$
101.86

   Natural Gas Liquids (Per Bbl)
 
$
30.72

 
$
30.72

 
$
34.58

   Natural gas (Per Mcf)
 
$
4.31

 
$
3.72

 
$
2.58

 
 
 
 
 
 
 
Average Production Cost (Per Boe sold) (2)
 
$
8.98

 
$
10.50

 
$
9.11


(1) Excludes natural gas consumed in operations that is included in reported production volumes of 1,327 MMcf in 2014, 1,097 MMcf in 2013 and 993 MMcf in 2012.
(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 67%, 48% and 33% of total BOE sales in 2014, 2013 and 2012, 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, 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

13


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. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices. For additional discussion related to our price-risk policy, refer to Note 1 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.

Federal Leases

Some of our properties are located on federal oil and natural gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and administrative orders affect the terms of leases, and in turn may affect our exploration and development plans, methods of operation, and related matters.

Litigation

In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In our opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Employees

As of December 31, 2014, the Company employed 294 people. Subsequent to December 31, 2014 the company reduced personnel by approximately 20% in connection with the lower commodity pricing environment. None of our employees were represented by a union and relations with employees are considered to be good.

Facilities

At December 31, 2014, we occupied approximately 147,000 square feet of office space at 16825 Northchase Drive, Houston, Texas. In January of 2015 we signed a new lease agreement commencing on March 1, 2015 for approximately 117,000 square feet of office space at 17001 Northchase Drive, Houston, Texas. For discussion regarding the term and obligations of this lease refer to Note 5 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.


14


Item 1A. Risk Factors

The nature of the business activities conducted by Swift Energy subjects it to certain hazards and risks. The following is a summary of the major risks relating to our business activities:

Oil and natural gas prices are volatile. Commodity prices have dropped substantially and rapidly since September 2014. Continued low prices or their further downward movement would adversely affect our liquidity, operating results, financial condition, cash flows and growth prospects.

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. Oil and natural gas prices historically have been volatile and have dropped precipitously over the past six months, especially in the last quarter of 2014 and first quarter of 2015.

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

our cash flow would be reduced, decreasing funds available for capital expenditures;
certain reserves would no longer be economic to produce, leading to both lower cash flow and lower proved reserves;
our lenders could reduce the borrowing base under our bank credit facility because of lower oil and natural gas reserves values, reducing our liquidity and possibly requiring mandatory loan repayments; and
such a reduction may result in a downward adjustment to our estimated proved reserves, and require write-downs of our oil and gas properties.

The effects of current or lower oil and gas prices could require us to amend financial covenants in our credit facility.

Our revolving credit facility contains both an adjusted working capital ratio covenant and an interest coverage ratio covenant (as defined in our Credit Agreement in exhibit 10.8 to this Form 10-K; see also Note 4 of the consolidated financial statements in this Form 10-K for further discussion of these ratios). Continuation of low oil prices or their further deterioration could significantly reduce cash flow, which is a critical underpinning of these ratios. If this were to occur, it could be necessary to negotiate for an amendment to one or both of these financial covenants.

If low commodity prices continue for an extended period it could negatively affect our cash flows, which would reduce our liquidity.

As of December 31, 2014, the aggregate amount of our outstanding indebtedness was approximately $1.1 billion, however the company has continued to borrow under the credit facility since that time. As of December 31, 2014, our total debt comprised approximately 57% of our total capitalization and in 2014 we spent approximately 25% of our net cash provided by operating activities on interest payments. In addition, we may also incur additional indebtedness in the future. A high level of debt could adversely affect us in several ways, including the following:

it may be more difficult for us to repay or make interest payments on our outstanding indebtedness;
we estimate that we will use a significant portion of our 2015 cash flows to pay interest on our debt, which will reduce the amount of money we have for operations, capital expenditures, or other business activities;
the amount of our interest expense could increase if we deem it necessary to borrow additional amounts; and
our debt levels could limit our future business flexibility, including the necessity to sell assets at prices below market values.

Our level of indebtedness may adversely affect operations and raise issues related to maintaining certain properties.

While a portion of our leases are held by production, other leases 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 proved undeveloped reserves and production.

Our development operations require substantial capital and we may be unable to obtain needed capital at satisfactory levels, which 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 2014 total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $364 million, our 2015 capital expenditure budget has been

15


reduced to between $110 to $125 million. Cash flow from operations is the principal source we intend to use for financing our future capital expenditures in 2015. Our cash flow from operations and access to capital are subject to a number of variables, including:

the prices at which our oil and natural gas are sold;
our ability to borrow under our credit facility;
our proved reserves;
the volume of oil and natural gas we are able to produce from existing wells; and
our ability to acquire, locate and produce new reserves.

Cash flow from our operations and other capital resources may be insufficient to maintain planned levels of capital expenditures. If we are unable to fund our capital requirements, we may be required to curtail our operations even further, which in turn could lead to declines in our cash flows, or in our oil and natural gas reserves, or in a loss of properties.

For both 2014 and 2013, we have written down the carrying values on our oil and gas properties and could incur additional write-downs in the future.

The SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment (the "ceiling test"). Any capital costs in excess of the ceiling amount must be permanently written down. For the years ended December 31, 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, 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 2014 ceiling test, we could be required to record additional non-cash write-downs of oil and gas properties as early as the first quarter of 2015, as the prices previously used in the ceiling test may be replaced by lower prices during 2015. Refer to Note 1 of the consolidated financial statements in this Form 10-K for further discussion of the ceiling test calculation.

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 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. Further, the EPA's Office of Research and Development (ORD) is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. 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 final outcome of the ORD's study or 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. For example, the hydraulic fracturing process which we employ to produce commercial quantities of crude oil and natural gas from many reservoirs, including the Eagle Ford Shale, require the use and disposal of significant quantities of water. In certain areas, there may be insufficient aquifer capacity to provide a local source of water for drilling activities. 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, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas.
 

16


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.

If we cannot replace our reserves, our revenues and financial condition will suffer.
    
Unless we successfully replace our reserves, our long-term production will decline, which could result in lower revenues and cash flow. When our capital expenditures are limited to funding from our cash flow in lower commodity price environments, or when oil and natural gas prices decrease, our cash flow decreases, resulting in less available cash to drill and replace our reserves and an increased need to draw on our credit facility or generate funds through property sales or joint ventures, neither of which can be assured. Even if we have the capital to drill new wells, unsuccessful wells can hurt our efforts to replace reserves. Additionally, lower oil and natural gas prices can have the effect of lowering our reserves estimates and the number of economically viable prospects that we have to drill.

Our business depends on oil and natural gas transportation facilities, some of which are owned by others.

The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems owned by third parties an area in which we have been affected by constraints for periods of time. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

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 2014 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.

Any significant variance from the assumptions used 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. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of future net cash flows from our oil and natural gas reserves.

At December 31, 2014, approximately 66% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserves data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur.

Our Southeast Louisiana core area could occasionally 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 6% of our 2014 reserves, 12% of our 2014 production and 23% of our 2014 revenues were located in our Southeast Louisiana core area. Increased hurricane activity over the past six 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.


17


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.

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.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities, if at all, to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present. We cannot assure you that the analogies we draw from available data from other wells,

18


more fully explored prospects, or producing fields will be applicable to our drilling prospects. In addition, a variety of factors, including geological and market-related, can cause a well to become uneconomical or only marginally economical. For example, if oil and natural gas prices are much lower after we complete a well than when we identified it as a prospect, the completed well may not yield commercially viable quantities.

We may have difficulty competing for oil and gas properties, equipment, supplies, oilfield services, and trained and experienced personnel.

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 the 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. As demand increases for equipment, services, and personnel, we may experience increased costs and various shortages and may not be able to obtain the necessary oilfield services and trained personnel.

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 environmental protection. 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 legislative or regulatory proposals under consideration could negatively affect our business.

Numerous legislative and regulatory proposals affecting the oil and gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by 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) proposals contained in the President's budget, along with legislation introduced in Congress (none of which have passed), to impose new 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, 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; and (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 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. Any of the foregoing described 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 (iv) the elimination of the deduction for certain U.S. production

19


activities. It is currently unclear whether any such proposals will be enacted or what form they might possibly take. 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.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. New or modified rules, regulations or requirements may increase the cost and availability to our counterparties of their hedging and swap positions which they can make available to us, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities which may not be as creditworthy as the current counterparties. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives we use to hedge against commodity price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties.

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 procedures 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. 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 have not experienced 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.

20


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.
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.
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.
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.
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

21


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

No material legal proceedings are pending other than ordinary, routine litigation and claims incidental to our business.

Item 4. Mine Safety Disclosures

None.


22


PART II

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

Common Stock, 2014 and 2013

Our common stock is traded on the New York Stock Exchange under the symbol “SFY.” The high and low quarterly closing sales prices for the common stock for 2014 and 2013 were as follows:
 
2014
 
2013
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Low
$9.62
$10.26
$9.60
$2.63
 
$13.18
$11.81
$10.99
$11.59
High
$13.70
$13.01
$12.86
$9.21
 
$17.10
$15.63
$13.56
$14.90

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, and we presently intend to continue a policy of using retained earnings for expansion of our business.

We had approximately 152 stockholders of record as of December 31, 2014.

Stock Repurchase Table

The following table summarizes repurchases of our common stock during the fourth quarter of 2014, 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, 2014
 
4,300

 
$
7.09

 

 
$---

November 1- 30, 2014
 
192

 
$
6.81

 

 

December 1 - 31, 2014
 
18,461

 
$
4.30

 

 

Total
 
22,953

 
$
4.84

 

 
$---


Equity Compensation Plan Information

The 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, 2014 is located in Note 6 of these consolidated financial statements in this Form 10-K.

23


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, 2009 to December 31, 2014, 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, 2009, in our common stock at the closing market price at the beginning of this period and in each of the other indexes.


24


Item 6. Selected Financial Data
(annual data in thousands except share & well amounts)
2014
2013
2012
2011
2010
 
 
 
 
 
 
Total Revenues from Continuing Operations (1)
$
549,456

$
584,401

$
561,486

$
597,809

$
438,867

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

$
37,773

$
131,125

$
72,225

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

$
82,071

$
45,146

 
 
 
 
 
 
Net Cash Provided by Operating Activities - Continuing Operations
$
306,371

$
311,447

$
314,606

$
373,058

$
258,996

 
 
 
 
 
 
Per Share and Share Data
 
 
 
 
 
Weighted Average Shares Outstanding
43,795

43,331

42,840

42,394

38,300

Earnings per Share--Basic(1)
$
(6.47
)
$
(0.06
)
$
0.51

$
1.94

$
1.17

Earnings per Share--Diluted(1)
$
(6.47
)
$
(0.06
)
$
0.50

$
1.91

$
1.16

Shares Outstanding at Year-End
43,918

43,402

42,930

42,485

41,999

Book Value per Share at Year-End
$
18.09

$
24.55

$
24.52

$
23.80

$
21.36

Market Price
 
 
 
 
 
High
$
13.70

$
17.10

$
35.00

$
47.32

$
40.83

Low
$
2.63

$
10.99

$
14.28

$
21.81

$
24.52

Year-End Close
$
4.05

$
13.50

$
15.39

$
29.72

$
39.15

 
 
 
 
 
 
Assets
 
 
 
 
 
Current Assets
$
64,669

$
92,489

$
87,005

$
334,594

$
158,796

Property & Equipment, Net of Accumulated
 
 
 
 
 
Depreciation, Depletion, and Amortization
$
2,095,037

$
2,588,817

$
2,367,954

$
1,892,866

$
1,599,796

Total Assets
$
2,173,347

$
2,698,505

$
2,473,463

$
2,244,012

$
1,771,305

 
 
 
 
 
 
Liabilities
 
 
 
 
 
Current Liabilities
$
148,919

$
176,033

$
179,412

$
216,605

$
157,102

Long-Term Debt
$
1,074,534

$
1,142,368

$
916,934

$
719,775

$
471,624

Total Liabilities
$
1,378,969

$
1,633,155

$
1,420,680

$
1,232,661

$
874,237

 
 
 
 
 
 
Stockholders' Equity
$
794,378

$
1,065,350

$
1,052,783

$
1,011,351

$
897,068

 
 
 
 
 
 
Producing Wells
 
 
 
 
 
Swift Operated
1,040

1,039

1,069

1,025

1,212

Outside Operated
25

25

50

46

119

Total Producing Wells
1,065

1,064

1,119

1,071

1,331

 
 
 
 
 
 
Wells Drilled (Gross)
36

48

71

44

56

 
 
 
 
 
 
Proved Reserves
 
 
 
 
 
Natural Gas (Bcf)
686.7

815.1

597.6

616.8

423.0

Oil Reserves (MBoe)
49.7

53.0

43.3

30.9

39.3

NGL Reserves (MBoe)
29.7

30.4

49.2

25.8

23.0

Total Proved Reserves (MMBoe equivalent)
193.8

219.2

192.1

159.6

132.8

 
 
 
 
 
 
Production (MMBoe equivalent)
12.4

11.7

11.7

10.5

8.3

 
 
 
 
 
 
Average Sales Price (2)
 
 
 
 
 
Natural Gas (per Mcf produced)
$
3.88

$
3.32

$
2.42

$
3.70

$
3.96

Natural Gas Liquids (per barrel)
$
31.83

$
31.39

$
35.07

$
52.13

$
42.44

Oil (per barrel)
$
92.74

$
103.42

$
106.17

$
107.00

$
79.45

Boe Equivalent
$
44.22

$
50.11

$
47.37

$
57.22

$
52.42


(1) Amounts have been retroactively adjusted in all periods presented to give recognition to discontinued operations related to the sale of our New Zealand oil & gas assets.

(2) 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.

25


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, 2014, 2013 and 2012 included with this report. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 34 of this report.

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. Oil production accounted for 28% of our 2014 production and 59% of our oil and gas sales, and combined production of both oil and natural gas liquids (“NGLs”) constituted 43% of our 2014 production and 70% of our oil and gas sales. In 2014, we benefited from this production mix as oil prices were significantly higher than natural gas prices, on a Boe basis.

As a result of the July 2014 sale of a 36% interest in our Fasken area Eagle Ford shale properties to Saka Energi (as described below), we reduced the outstanding balance under our credit facility between June 30, 2014 and December 31, 2014 by over $100 million using a portion of the proceeds from the Saka Energi transaction.

Recent crude oil price decline and its effect on our business: Crude oil prices are volatile and significant price movement can impact our cash flows, operating results and our future growth prospects. Oil prices started to decline in the second half of 2014, accelerating during the fourth quarter of 2014 through early 2015, falling from over $107 per barrel (as measured using the WTI crude oil price) in June 2014 to below $45 per barrel in January 2015, recovering slightly to approximately $51 per barrel as of February 25, 2015. Although the effect of this price decrease was somewhat muted on our 2014 results as it affected only a portion of our 2014 prices, we expect 2015 results will be affected in a more significant way as approximately 60% of the Company’s oil and gas sales revenue for 2014 was derived from crude oil sales.

2015 planned capital expenditures: We expect the current significantly lower oil and natural gas prices to reduce operating cash flows and have therefore meaningfully reduced our capital spending plans for 2015. The Company is targeting annual production levels of 11.4 to 11.6 MMBoe based on planned full-year capital expenditures of $110 to $125 million, with a focus on drilling activity in our dry gas Fasken area as well as in our South Texas oil, gas and condensate properties. A portion of our capital expenditure program is discretionary and may be further deferred, if necessary. We expect to fund 2015 capital expenditures primarily using cash flow from operations with the remaining balance supplied by borrowings under our credit facility or possibly proceeds from joint ventures or other arrangements.

2015 cost reduction initiatives: We are taking significant steps to reduce our future capital, operating and overhead costs. With the reduction in our capital spending plans for 2015, we terminated one of our two drilling contracts and are in discussions to reduce the day-rate for the remaining rig. We are also in negotiations with all of our primary suppliers and service companies to reduce our capital and operating cost structures. Through these initiatives, we anticipate achieving cost reductions of approximately 15-30% for a substantial portion of the goods and services consumed in our drilling and production operations. 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 operating personnel. Additionally, we have proactively taken steps to materially reduce our overhead costs by (i) signing a new lease for less corporate office space at more attractive costs and (ii) carrying out a reduction-in-force that aligns with proposed spending levels in this lower commodity pricing environment.

2015 borrowing base redeterminations and credit facility financial covenants: Our credit facility provides for semi-annual borrowing base redeterminations by our lenders on or about May 1 and November 1 of each year. Due to the recent fall in oil prices, our borrowing base could be reduced at the next redetermination in May 2015. In addition, our bank credit agreement contains financial covenants detailing certain minimum financial ratios that must be maintained. The first is an adjusted working capital ratio of adjusted current assets to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0, which is below the Company's December 31, 2014 ratio of 1.9 to 1.0. There is also an interest coverage ratio, calculated on a trailing twelve month basis of EBITDAX to interest expense (as defined in the Credit Agreement), of no less than 2.75 to 1.0, which is below the Company's December 31, 2014 ratio of 4.9 to 1.0. Based upon our current projections of production and current commodity futures prices, we believe we will remain in compliance with these financial covenants throughout 2015; however, if oil prices were to decline further, we could find our operating earnings reduced to a level not in compliance with our interest coverage ratio by the end of 2015 or early 2016. Similarly, a significant reduction in our borrowing base

26


during 2015 could lead to non-compliance with our adjusted working capital ratio. Either event could lead to a default under our credit facility, requiring us to seek a waiver, renegotiate our credit agreement or reduce or repay outstanding borrowings, which we anticipate being able to accomplish.

2015 liquidity: We expect to control our reduced liquidity during 2015 by scaling back our capital expenditures to match the current commodity pricing environment. Although we cannot predict nor control future commodity prices, we have already reduced our 2015 capital expenditure budget to accommodate market expectations of reduced commodity prices. As of December 31, 2014, we had approximately $220 million of remaining availability under our credit facility (excluding $1.6 million in letters of credit), which is subject to our borrowing base redetermination in May 2015. The Company has continued to borrow under the credit facility since December 31, 2014. We are simultaneously pursuing joint ventures and other arrangements which would enable us to support development of our core areas with additional third-party capital.

Ability to capitalize on natural gas at current market prices: Natural gas prices declined during the second half of 2014 and into 2015, however selected natural gas properties can be economically developed at current market prices. Our Fasken properties in Webb County and part of our AWP properties in McMullen County can be economically developed today, while other areas may require a higher price environment to provide adequate economic returns. Our strategy includes a focus on natural gas and we plan to continue development on our prolific natural gas properties, along with development in economic liquids-rich areas if commodity prices improve.

2014 Operating Highlights

Saka Energi transaction: 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 area. Saka Energi purchased a 36% full participating interest in the properties for $175 million in total cash consideration, with $125 million paid at closing and $50 million in cash to be paid by Saka Energi over time to carry a portion of Swift Energy's field development costs incurred after the effective date, January 1, 2014. As of December 31, 2014, approximately $29 million remained of Saka Energi's original $50 million carry obligation, which is expected to be fulfilled by the end of calendar year 2016 but is dependent on the pace of drilling in the Fasken area. At closing, Swift received proceeds of approximately $147 million, composed of the initial $125 million in cash consideration plus Saka Energi's share of capital costs, net of revenue between the January 1, 2014 effective date and the closing date. The proceeds from this transaction initially were used to pay down our credit facility and were partially offset by subsequent additional borrowings against the credit facility to fund development expenditures. This transaction allowed accelerated drilling and development of our Fasken properties in 2014.

Enhancing Eagle Ford asset value through operating improvements and completion technology: Our South Texas drilling activities continue to benefit from optimized well design as we are drilling longer laterals in our horizontal wells and performing more frac stages per well. 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 well results. Before completion operations commence, we conduct GEOFRAC logging of the horizontal well bore, which has led to more effective placement of frac stages and has also assisted in identifying sections of rock that are ideal for stimulation. These techniques have been effectively deployed in wells drilled in our Fasken and North AWP areas as well as the joint venture area in the central portion of AWP, proving the transferability of this technology. We have observed that longer laterals with additional frac stages and more intense treatment of each stage have resulted in improved rates of return of our Eagle Ford horizontal wells when comparing results using normalized oil and gas prices. Our current process allows us to drill wells in our Fasken area with laterals of over 7,500 feet and over 20 frac stages per well. We believe the successful extension of lateral lengths, increased number of frac stages and engineered spacing of these stages will result in further improvements in our economic returns across our acreage.

Improved value of Eagle Ford shale assets through 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 per well drilling costs come down from those experienced in the prior year. For 2014, our average drilling cost per well has decreased to $3.4 million from $3.6 million during 2013, even though the average well included over 750 additional lateral feet in the current year. We have also experienced efficiency gains in our hydraulic fracturing activities, lowering the overall frac cost per stage while performing an average of four more frac stages per well and achieving better overall results as measured by rates of return and net present value. For 2014 compared to 2013, our average completion cost decreased approximately $20,000 per stage, while using additional proppant in each stimulated stage.


27


2014 revenues and net income: Our 2014 revenues decreased 6% or $34.9 million, when compared to 2013, primarily due to the impact of lower oil prices and production volumes, partially offset by higher natural gas production volumes and pricing. Revenues decreased due to lower oil production in our Lake Washington field and lower overall production in our Artesia Wells field, partially offset by an increase in natural gas production volumes from our Fasken field and an increase in oil and natural gas production from our AWP field. Revenues also decreased from lower overall commodity pricing as oil prices were 10% lower in 2014, when compared to 2013, partially offset by a 17% increase in natural gas prices during the same period. Our net loss of $283.4 million for 2014 is primarily due to the $445.4 million non-cash write-down of our oil and gas properties.

2014 changes in reserve quantities and value: Our 12% or 25.4 MMBoe decrease in proved reserves quantities from 2013 to 2014, was principally due to the sale of a 36% interest in our Fasken Eagle Ford properties and production of 12.4 MMBoe during 2014, partially offset by various extensions, discoveries and revisions (mainly in our AWP Eagle Ford field). The 20% decrease in our PV-10 Value from 2013 and 2014 reflected not only these quantity decreases, but also the impact of lower oil and NGL prices during the last quarter of 2014.

2014 lease acquisition activity in Eagle Ford: The company recently acquired approximately 12,635 acres of high quality, contiguous Eagle Ford gas acreage at Oro Grande in La Salle County. The lease also contains a one year option to lease an additional contiguous 11,850 acres in McMullen County. This formation is 100% gas and we believe we can apply our enhanced techniques from our Fasken and AWP fields to this area in the Eagle Ford formation.

Liquidity and Capital Resources

Outstanding bank borrowings: At December 31, 2014, we had $197.3 million in outstanding borrowings under our credit facility with a borrowing base and commitment amount of $417.6 million, after being automatically reduced from $450.0 million effective July 15, 2014, due to the Saka Energi transaction. The proceeds of approximately $147 million received at closing were immediately used to pay down our outstanding borrowings under the credit facility, with subsequent borrowings against the credit facility during the second half of the year to fund development activities.

2014 capital expenditures: Our capital expenditures on a cash flow basis were $386.3 million in 2014, compared to $540.4 million for 2013. The expenditures were devoted to drilling and completion activity in our South Texas core region as we drilled 20 wells in our AWP Eagle Ford field and 16 wells in our Fasken field during the year. These expenditures were funded by $306.4 million of cash provided by operating activities along with borrowings under our credit facility.

Net cash provided by operating activities: For 2014, our net cash provided by operating activities was $306.4 million, representing a $5.1 million or 2% decrease, compared to $311.4 million generated during 2013, primarily due to the impacts of lower oil prices and production, partially offset by higher natural gas production and prices.
 

28


Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter as of December 31, 2014 were as follows (in thousands):
 
2015
2016
2017
2018
2019
Thereafter
Total
Non-cancelable operating leases (1)
$
12,560

$
79

$

$

$

$

$
12,639

Asset retirement obligation (2)
10,709

3,040

2,877

2,618

568

53,019

72,831

Drilling, Completion and Geoscience Contracts
13,109






13,109

Gas transportation and Processing (3)
12,663

12,543

10,057

10,239

8,720

7,397

61,619

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
69,281

69,281

60,375

51,469

51,469

88,734

390,609

Credit facility (4)


197,300




197,300

Total
$
118,322

$
84,943

$
520,609

$
64,326

$
60,757

$
774,150

$
1,623,107


(1) Subsequent to December 31, 2014, we signed a new lease commencing on March 1, 2015. For additional discussion regarding the terms and obligations of this lease refer to Note 5 of the consolidated financial statements in this Form 10-K.
(2) Amounts shown by year are the net present value at December 31, 2014.
(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) The credit facility expires in November 2017 and these amounts exclude $1.6 million standby letters of credit outstanding under this facility.

As of December 31, 2014, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

Proved Oil and Gas Reserves

We have added proved reserves over the past three years primarily through our drilling activities, including 18.2 MMBoe added in 2014, 76.3 MMBoe added in 2013, and 43.8 MMBoe added in 2012. The 2014 proved reserves additions from drilling activities consisted primarily of additions in the AWP Eagle Ford field in South Texas based on the results of the horizontal drilling program conducted in the area during the year. 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 disposition, as noted in Note 8 of our consolidated financial statements in this Form 10-K. At year-end 2014, 34% of our total proved reserves were proved developed, compared with 29% at year-end 2013 and 34% at year-end 2012.

At December 31, 2014, our proved reserves were 193.8 MMBoe with a PV-10 Value of $1.9 billion (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 $481 million, or 20%, from the prior year-end levels. In 2014, our proved natural gas reserves decreased 128.4 Bcf, or 16%, while our proved oil reserves decreased 3.3 MMBbl, or 6%, and our NGL reserves decreased 0.7 MMBbl, or 2%, for a total equivalent decrease of 25.4 MMBoe, or 12%.

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 2014 was $4.32 per Mcf. This average price increased from the average price of $3.41 per Mcf used in the PV-10 calculation for 2013. Our average oil price used in the PV-10 Value calculation for 2014 was $93.64 per Bbl. This average price decreased from the average price of $104.38 per Bbl used in the PV-10 calculation for 2013.

Results of Operations

Revenues — Years Ended December 31, 2014, 2013 and 2012

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.


29


2013 - Our revenues in 2013 increased by 4% compared to revenues in 2012, due to higher natural gas pricing and higher oil and NGL production, partially offset by lower oil and NGL pricing and lower natural gas production. Average oil prices we received were 3% lower than those received during 2012, while natural gas prices were 37% higher, and NGL prices were 10% lower.

Crude oil production was 28%, 33% and 32% of our production volumes while crude oil sales were 59%, 69% and 72% of oil and gas sales for the years ended December 31, 2014, 2013 and 2012, respectively. Natural gas production was 57%, 47% and 52% of our production volumes while natural gas sales were 30%, 19% and 16% of oil and gas sales for the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012:
Core Areas
 
Oil and Gas Sales
(In Millions)
 
Net Oil and Gas Production
Volumes (MBoe)
 
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Southeast Louisiana
 
$
124.2

 
$
168.0

 
$
215.0

 
1,459

 
1,797

 
2,227

South Texas (1)
 
382.4

 
360.2

 
290.1

 
10,239

 
9,009

 
8,555

Central Louisiana
 
39.5

 
54.9

 
52.6

 
656

 
897

 
898

Other
 
1.7

 
2.1

 
0.7

 
33

 
43

 
20

Total
 
$
547.8

 
$
585.2

 
$
558.4

 
12,387

 
11,746

 
11,700


(1) Our 2014 South Texas oil and gas sales include $62.2 million for Artesia Wells, $224.8 million for AWP, $87.2 million for Fasken and $8.2 million for other South Texas fields. Our 2014 South Texas net oil and gas production volumes include 1,786 million MBoe for Artesia Wells, 4,636 million MBoe for AWP, 3,565 million MBoe for Fasken and 252 million MBoe for other South Texas fields.

Our production increase from 2013 to 2014 was primarily due to an increase of natural gas production from increased drilling in our Fasken field, plus an increase in oil and natural gas production at our AWP field. These increases were partially offset by a decrease in overall production for our Artesia Wells field and a decrease in oil production in our Lake Washington field.

In 2014, our $37.4 million, or 6% decrease 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.
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.

In 2013, our $26.8 million, or 5% increase in oil, NGL, and natural gas sales resulted from:

Price variances that accounted for approximately $10 million of the favorable increase as gas prices were up 37%, partially offset by lower prices for oil (down 3%) and NGLS (down 10%); and
Volume variances that had an approximate $17 million favorable impact on sales attributable to higher oil and NGL production, partially offset by a reduction in natural gas volumes.


30


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, 2014, 2013 and 2012:

 
Production Volume
 
Average Price
 
Oil
 
NGL
 
Gas
 
Combined
 
Oil
 
NGL
 
Gas
 
(MBbl)
 
(MBbl)
 
(Bcf)
 
(MBoe)
 
(Bbl)
 
(Bbl)
 
(Mcf)
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
884
 
376
 
9.2
 
2,799
 
$111.99
 
$45.30
 
$2.18
  Second Quarter
905
 
430
 
9.5
 
2,918
 
$108.02
 
$35.25
 
$2.01
  Third Quarter
870
 
512
 
9.0
 
2,875
 
$102.73
 
$31.29
 
$2.52
  Fourth Quarter
1,115
 
544
 
8.7
 
3,108
 
$102.73
 
$31.42
 
$3.04
    Total
3,774
 
1,862
 
36.4
 
11,700
 
$106.17
 
$35.07
 
$2.42
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

For the years ended December 31, 2014, 2013 and 2012, we recorded net gains (losses) of $1.3 million, ($0.9) million and $2.3 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 $92.52, $102.93 and $106.77 for the years ended December 31, 2014, 2013 and 2012, respectively, and our average natural gas price would have been $3.93, $3.35 and $2.42 for the years ended December 31, 2014, 2013 and 2012, respectively.

Costs and Expenses

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, but we believe that these costs will decrease from current levels with the recent decline in oil prices.

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

31


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 carries 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.

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.

2013 - Our expenses for the year ended December 31, 2013 increased $60.5 million, or 12%, compared to the prior year levels, for the reasons noted below.

Lease Operating Cost. These expenses increased $1.9 million, or 2%, compared to the level of such expenses for the year ended December 31, 2012, due to higher costs in our South Texas region for chemical treating, compressor rentals and lease operator costs, partially offset by lower salt water disposal costs in South Texas. Our lease operating costs per Boe produced were $8.49 and $8.36 for the years ended December 31, 2013 and 2012, respectively.

Transportation and gas processing. These expenses increased $1.6 million, or 8%, compared to the level of such expenses for the year ended December 31, 2012, due to additional NGL production. Our transportation and gas processing costs per Boe produced were $1.79 and $1.66 for the years ended December 31, 2013 and 2012, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses increased $3.4 million, or 1%, from those during the year ended December 31, 2012, due to a higher depletable base including higher future development costs, partially offset by higher reserves volumes. Our DD&A rate per Boe of production was $21.52 and $21.31 for the years ended December 31, 2013 and 2012, respectively.

General and Administrative Expenses, Net. These expenses decreased $1.7 million or 4%, compared to the level of such expenses for the year ended December 31, 2012, due to lower stock compensation, partially offset by higher salaries and burdens and higher temporary labor costs. For the years ended December 31, 2013 and 2012, our capitalized general and administrative costs totaled $31.8 million and $31.1 million, respectively. Our net general and administrative expenses per Boe produced were $3.87 and $4.03 for the years ended December 31, 2013 and 2012, respectively. The supervision fees recorded as a reduction to general and administrative expenses were $11.6 million and $11.3 million for the years ended December 31, 2013 and 2012, respectively.

Severance and Other Taxes. These expenses decreased $4.8 million, or 10%, from the year ended December 31, 2012. Severance and other taxes, as a percentage of oil and gas sales, were approximately 7.3% and 8.5% for the years ended December 31, 2013 and 2012, respectively. The change in rate was primarily driven by higher oil production in South Texas as our Texas oil production carries a lower severance tax rate than in Louisiana.
 
Interest. Our gross interest cost for the year ended December 31, 2013 was $76.6 million, of which $7.2 million was capitalized. Our gross interest cost for the year ended December 31, 2012 was $65.2 million, of which $7.9 million was capitalized. The increase in interest came from increased credit facility borrowings during 2013.

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


32


Income Taxes. Our effective income tax rate was over 100% for the year ended December 31, 2013. As our net income was near break-even tax expense is primarily attributable to non-deductible book expenses. For the year ended December 31, 2012 our effective rate was 42.5%.

Critical Accounting Policies and New Accounting Pronouncements

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 property-by-property 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").

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, 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.

Given the volatility of oil and natural gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could continue to change in the near-term. If oil and natural gas prices decline from the prices used in the Ceiling Test, it is reasonably possible that additional non-cash write-downs of oil and gas properties would 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 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.

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 are currently reviewing the new requirements to determine the impact of this guidance on our financial statements.

33


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:

• oil and natural gas pricing expectations;
• business strategy;
• estimated oil and natural gas reserves or the present value thereof;
• technology;
• our borrowing capacity, 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 and amount of future production of oil and natural gas;
• availability of drilling and production equipment or availability of oil field labor;
• availability and terms of capital;
• drilling of wells;
• marketing and 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;
• 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, 2014. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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.

34


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 throughout 2013 and 2014.

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 1 of the consolidated financial statements in this Form 10-K.

Income Tax Carryforwards. As of December 31, 2014, the Company has net deferred tax carryforward assets of $132.3 million for federal net operating losses, $2.1 million for federal alternative minimum tax credits and $4.7 million, net of a $10.9 million valuation allowance, for deferred state tax net operating loss carryforwards which in management's judgment will more likely than not be utilized to offset future taxable earnings. Changes in markets conditions or significant changes in the Company's ownership could impact our ability to utilize these carryforwards.

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, 2014, 2013 and 2012, Shell Oil Company and affiliates accounted for 21%, 33% and 46% 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, 2014, we had $197.3 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 33 basis points and would not have a material adverse effect on our future cash flows.



35


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
 
 
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
 
 
Consolidated Balance Sheets
 
 
Consolidated Statements of Operations
 
 
Consolidated Statements of Comprehensive Income
 
 
Consolidated Statements of Stockholders' Equity
 
 
Consolidated Statements of Cash Flows
 
 
Notes to Consolidated Financial Statements
 
 
Supplementary Information


36


Management's Report on Internal Control Over Financial Reporting

Management of Swift Energy Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with U. S. generally accepted accounting principles.

Management of the Company assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2014. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) (2013 framework) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2014.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the Company's internal control over financial reporting as of December 31, 2014, based on their audit. The Public Company Accounting Oversight Board (United States) standards require that they plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Their audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as they considered necessary in the circumstances.


37


Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of Swift Energy Company
 
We have audited Swift Energy Company and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Swift Energy Company and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Swift Energy Company and subsidiaries' maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Swift Energy Company and subsidiaries' as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2014 and our report dated March 2, 2015 expressed an unqualified opinion thereon.



/s/ ERNST & YOUNG LLP

Houston, Texas
March 2, 2015



38


Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of Swift Energy Company
 
We have audited the accompanying consolidated balance sheets of Swift Energy Company and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Swift Energy Company and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Swift Energy Company and subsidiaries' internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 2, 2015 expressed an unqualified opinion thereon.




/s/ ERNST & YOUNG LLP

Houston, Texas
March 2, 2015


39


Consolidated Balance Sheets
Swift Energy Company and Subsidiaries (in thousands, except share amounts)
 
December 31, 2014
 
December 31, 2013
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
406

 
$
3,277

Accounts receivable
48,451

 
70,897

Deferred tax assets
6,243

 
10,715

Other current assets
9,569

 
7,600

Total Current Assets
64,669

 
92,489

 
 
 
 
Property and Equipment:
 

 
 

Property and Equipment, including $64,903 and $71,452 of unproved property costs not being amortized, respectively
5,934,155

 
5,714,099

Less – Accumulated depreciation, depletion, and amortization
(3,839,118
)
 
(3,125,282
)
Property and Equipment, Net
2,095,037

 
2,588,817

Other Long-Term Assets
13,641

 
17,199

Total Assets
$
2,173,347

 
$
2,698,505

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current Liabilities:
 

 
 

Accounts payable and accrued liabilities
$
68,244

 
$
82,318

Accrued capital costs
41,461

 
61,164

Accrued interest
21,389

 
21,561

Undistributed oil and gas revenues
17,825

 
10,990

Total Current Liabilities
148,919

 
176,033

 
 
 
 
Long-Term Debt
1,074,534

 
1,142,368

Deferred Tax Liabilities
86,376

 
241,205

Asset Retirement Obligations
62,122

 
63,225

Other Long-Term Liabilities
7,018

 
10,324

 
 
 
 
Commitments and Contingencies

 

 
 
 
 
Stockholders' Equity:
 

 
 

Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding

 

Common stock, $.01 par value, 150,000,000 shares authorized, 44,379,463 and 43,915,346 shares issued, and 43,918,029 and 43,401,920 shares outstanding, respectively
444

 
439

Additional paid-in capital
771,972

 
762,242

Treasury stock held, at cost, 461,434 and 513,426 shares, respectively
(9,855
)
 
(12,575
)