Attached files

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EX-21 - SWIFT ENERGY CO - SIGNIFICANT SUBSIDIARIES - SILVERBOW RESOURCES, INC.subsidiaries.htm
EX-31.1 - CEO CERTIFICATION - SILVERBOW RESOURCES, INC.ceocertification.htm
EX-31.2 - CFO CERTIFICATION - SILVERBOW RESOURCES, INC.cfocertification.htm
EX-99.1 - GRUY YE RESERVES AUDIT - SILVERBOW RESOURCES, INC.reserveaudit.htm
EX-23.2 - CONSENT OF ERNST AND YOUNG - SILVERBOW RESOURCES, INC.auditorconsent.htm
EX-23.1 - CONSENT OF HJ GRUY - SILVERBOW RESOURCES, INC.reserveconsent.htm
EX-12 - RATIOS OF EARNINGS TO FIXED CHARGES - SILVERBOW RESOURCES, INC.ratioofearnings.htm
EX-32 - CERTIFICATION OF CEO AND CFO - SILVERBOW RESOURCES, INC.ceocfocertification.htm
EX-10.27 - SIXTH AMENDMENT CREDIT AGREEMENT - SILVERBOW RESOURCES, INC.sixthamendmencragrmnt.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, 2009

Commission File Number 1-8754

Swift Energy Company Logo

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
 þ
No

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
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
 
No
þ

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]

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
 
 Non-accelerated filer
 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
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, 2009, the last business day of June 2009, was approximately $503,004,459.

The number of shares of common stock outstanding as of January 31, 2010 was 37,524,307.

Documents Incorporated by Reference


Proxy Statement for the Annual Meeting of Shareholders to be held May 11, 2010
 
Part III, Items 10, 11, 12, 13 and 14
   

 
2

 

Form 10-K
Swift Energy Company and Subsidiaries

10-K Part and Item No.
 
   
Page
Part I
   
Item 1.
Business
4
     
Item 1A.
Risk Factors
20
     
Item 1B.
Unresolved Staff Comments
25
     
Item 2.
Properties
7
     
Item 3.
Legal Proceedings
26
     
Item 4.
Submission of Matters to a Vote of Security Holders
27
     
Part II
   
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
28
     
Item 6.
Selected Financial Data
29
     
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
30
     
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
43
     
Item 8.
Financial Statements and Supplementary Data
45
     
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
81
     
Item 9A.
Controls and Procedures
81
     
Item 9B.
Other Information
82
     
Part III
   
Item 10.
Directors, Executive Officers and Corporate Governance (1)
83
     
Item 11.
Executive Compensation (1)
83
     
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters (1)
83
     
Item 13.
Certain Relationships and Related Transactions, and Director Independence (1)
83
     
Item 14
Principal Accountant Fees and Services (1)
83
     
Part IV
   
Item 15
Exhibits and Financial Statement Schedules
84
     
(1) Incorporated by reference from Proxy Statement for the Annual Meeting of Shareholders to be held May 11, 2010

 
3

 

PART I

Item 1. Business

See pages 25 and 26 for explanations of abbreviations and terms used herein.

General

Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and natural gas properties, with a focus on oil and natural gas reserves onshore and in the inland waters of Louisiana and Texas. Swift Energy was founded in 1979 and is headquartered in Houston, Texas. In December 2007, we agreed to sell the majority of our New Zealand assets and in 2008 we completed the sale.  At year-end 2009, we had estimated proved reserves from our continuing operations of 112.9 MMBoe with a PV-10 of $1.3 billion (PV-10 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, the standardized measure). Our total proved reserves at year-end 2009 were comprised of approximately 39% crude oil, 43% natural gas, and 18% NGLs; and 50% of our total proved reserves were proved developed. Our proved reserves are concentrated with 56% of the total in Louisiana, 43% in Texas, and 1% in other states.

We currently focus primarily on development and exploration of fields in four core areas as well as a strategic growth area:

•       Southeast Louisiana
Lake Washington field
Bay de Chene field

•       South Texas
AWP field
Sun TSH field
Briscoe Ranch field
Las Tiendas field
Other South Texas field

•       Central Louisiana/East Texas
Brookeland field
South Bearhead Creek field
Masters Creek field

•       South Louisiana
Horseshoe Bayou/Bayou Sale fields
Jeanerette field
Cote Blanche Island field
Bayou Penchant field
High Island field

•       Other
Non-Core Areas

Competitive Strengths and Business Strategy

Our competitive strengths, together with a balanced and comprehensive business strategy, provide us with the flexibility and capability to achieve our goals.  Our primary strengths and strategies are set forth below.

Demonstrated Ability to Grow Reserves and Production

We have grown our proved reserves from 108.8 MMBoe to 112.9 MMBoe over the five-year period ended December 31, 2009. Over the same period, our annual production has grown from 7.0 MMBoe to 9.1 MMBoe. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities and acquisitions in our core areas. During 2009, our proved reserves decreased by 3%, due mainly to lower prices used in the 2009 computation of reserves. 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.

4

Balanced Approach to Growth

Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions and strategic opportunities. In general, we focus on drilling in each of our core areas when oil and natural gas prices are strong. When prices weaken and the per unit cost of acquisitions becomes more attractive, or a strategic opportunity exists, we also focus on acquisitions. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner.  We have replaced 109% of our production on average over the last five years.

We currently plan to balance our 2010 capital expenditures with our 2010 cash flow and cash on hand.  Our 2010 capital expenditures are currently budgeted at $300 million to $375 million, net of minor non-core dispositions and excluding any property acquisitions.   Approximately two-thirds of our capital budget is targeted for our South Texas core area, while one-quarter is planned for our Southeast Louisiana core area. For 2010, we anticipate an increase in production volumes of 3% to 7% over 2009 levels and expect reserves to grow 5% to 10% over 2009 levels.

Replacement of Reserves

Historically we have added proved reserves through both our drilling and acquisition activities. We believe that this strategy will continue to add reserves for us over the long-term; however, external factors beyond our control, such as limited availability of capital or its cost, competition within our industry, adverse weather conditions, commodity market factors, the requirement of new or upgraded infrastructure at the production site, technological advances, and governmental regulations, could limit our ability to drill wells, access reserves, and acquire proved properties in the future. We have included below a listing of the vintages of our proved undeveloped reserves in the table titled “Proved Undeveloped Reserves” and believe this table will provide an understanding of the time horizon required to convert proved undeveloped reserves to oil and natural gas production. Our reserves additions for each year are estimates. Reserves volumes can change over time and therefore cannot be absolutely known or verified until all volumes have been produced and a cumulative production total for a well or field can be calculated.

Concentrated Focus on Core Areas with Operational Control

The concentration of our operations in our core areas allows us to leverage our drilling unit and workforce synergies while minimizing the continued escalation of drilling and completion costs. Our average lease operating costs for continuing operations, excluding taxes, were $8.47, $10.44 and $6.68 per Boe in 2009, 2008, and 2007, respectively. Each of our core areas includes properties that are targeted for future growth. This concentration allows us to utilize the experience and knowledge we gain in these areas to continually improve our operations and guide us in developing our future activities and in operating similar type assets. The value of this concentration is enhanced by our operational control of 96% of our proved oil and natural gas reserves base as of December 31, 2009. Retaining operational control allows us to more effectively manage production, control operating costs, allocate capital, and time field development.

Develop Under-Exploited Properties

We are focused on applying advanced technologies and recovery methods to areas with known hydrocarbon resources to optimize our exploration and exploitation of such properties as illustrated in our core areas. For instance, the Lake Washington field was discovered in the 1930s. We acquired our properties in this area for $30.5 million in 2001. Since that time, we have increased our average daily net production from less than 700 Boe to over 9,600 Boe for the quarter ended December 31, 2009. We have also increased our proved reserves in the area from 7.7 million Boe to approximately 27.2 million Boe as of December 31, 2009. When we first acquired our interests in the AWP, Brookeland, and Masters Creek fields, these fields each had significant additional development potential. In December 2004, we acquired our Bay de Chene and Cote Blanche Island fields which hold both proved developed and proved undeveloped reserves and we began our initial development activities of these properties in 2006. In November 2005, we acquired our South Bearhead Creek field and then in October 2006, we acquired interests in five fields in South Louisiana which have significant development potential. In October 2007, we acquired interests in three South Texas properties one in the Maverick Basin (Briscoe Ranch) and two in the Gulf Coast basin (Sun TSH and Las Tiendas) that total approximately 82,000 acres.  These properties are located in the Sun TSH field in La Salle County, the Briscoe Ranch field primarily in Dimmitt County, and the Las Tiendas field in Webb County.  In September 2008, we acquired additional interests in the Briscoe Ranch field within the Briscoe “A” lease in Dimmit County.  We intend to continue acquiring large acreage positions where we can grow production by applying advanced technologies and recovery methods using our experience and knowledge developed in our core areas.
 
5


Maintain Financial Flexibility and Disciplined Capital Structure

We practice a disciplined approach to financial management and have historically maintained a disciplined capital structure to provide us with the ability to execute our business plan. As of December 31, 2009, our debt to capitalization was approximately 41%, while our debt to proved reserves ratio was $4.17 per Boe, and our debt to PV-10 ratio was 36%. We plan to maintain a capital structure that provides financial flexibility through the prudent use of capital, aligning our capital expenditures to our cash flows, and maintaining a strategic hedging program when appropriate.

Experienced Technical Team and Technology Utilization

We employ 64 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 five 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.

We increasingly use advanced technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, licensing and pre-stack time and depth imaging, advanced attributes, pore-pressure analysis, inversion and detailed field reservoir depletion planning. In 2004, we recorded a 3-D seismic survey covering our Lake Washington field, and in 2006 we recorded a second 3-D survey in and around our Cote Blanche Island field.  We now have proprietary pre-stack time and depth migrated seismic data covering over 4,000 square miles in South Louisiana. These data have been merged into two large data volumes, inclusive of data covering five fields we acquired in 2006.  In late 2007, we began to extend this methodology to South Texas and licensed approximately 200 square miles of 3-D seismic data.  In 2008, we licensed an additional 350 square miles of 3-D seismic data over and near our AWP field. As these data are processed and merged with other available seismic data, and integrated with geologic data, we develop proprietary geo-science databases that we use to guide our exploration and development programs.

We use various recovery techniques, including gas lift, water flooding, pressure maintenance, and acid treatments to enhance crude oil and natural gas production. We also fracture reservoir rock through the injection of high-pressure fluid, install gravel packs, and insert coiled-tubing velocity strings to enhance and maintain production. We believe that the application of fracturing and coiled-tubing technology has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP field.  By December 31, 2009, we have successfully drilled and completed five horizontal multistage fracture completions in the Olmos Sand at AWP.  We will continue to improve and employ this new technology in South Texas and apply this to other areas in which Swift Energy operates.

Swift Energy’s success at drilling both in South Texas and in Louisiana can be marked by requiring excellence in engineering.  This was accomplished by elevating the quality of engineering first and operations second.  A premium was placed on well planning.  Drilling guidelines and design specifications were developed and implemented as best practices and standards, respectively, from which all planning and execution was derived.  The emphasis on well planning permeated throughout the organization and the results of that planning has shown up in performance across all drilling operations.  Lastly, the quality of the equipment and field personnel, together with a complete drilling process has been enforced.  This has been the final mixture of resources that have aided Swift Energy to move toward becoming a top tier Company.

 
6

 


Item 2. Properties

Operating Areas (Continuing Operations)

The following table sets forth information regarding our 2009 year-end proved reserves from continuing operations of 112.9 MMBoe and production of 9.1 MMBoe by area:

Field/Area
 
Developed (MMBoe)
 
Undeveloped
(MMBoe)
 
Total
(MMBoe)
 
% of
Reserves
 
% of
Production
 
% Oil and
NGLs
Lake Washington
 
12.3
 
14.9
 
27.2
 
24.1%
 
39.7%
 
92.7%
Bay de Chene
 
3.1
 
1.1
 
 4.1
 
3.7%
 
13.1%
 
43.0%
Total Southeast Louisiana
 
15.4
 
16.0
 
31.3
 
27.7%
 
52.8%
 
86.1%
                         
AWP
 
16.3
 
13.2
 
29.6
 
26.2%
 
18.4%
 
38.1%
Sun TSH
 
8.3
 
3.2
 
11.4
 
10.1%
 
8.0%
 
50.7%
Briscoe Ranch
 
1.2
 
0.8
 
2.0
 
1.7%
 
2.0%
 
53.8%
Las Tiendas
 
0.3
 
0.0
 
0.3
 
0.3%
 
0.5%
 
17.9%
Other South Texas
 
0.2
 
0.0
 
0.2
 
0.2%
 
1.2%
 
6.6%
Total South Texas
 
26.3
 
17.2
 
43.5
 
38.5%
 
30.1%
 
41.8%
                         
Brookeland
 
1.9
 
2.6
 
4.5
 
4.0%
 
2.4%
 
58.2%
South Bearhead Creek
 
4.0
 
2.8
 
6.8
 
6.0%
 
5.3%
 
68.5%
Masters Creek
 
2.1
 
5.2
 
7.3
 
6.5%
 
1.4%
 
70.9%
Chunchula
 
1.2
 
0.2
 
1.4
 
1.2%
 
0.4%
 
27.0%
Total Central Louisiana / East Texas
 
9.1
 
10.8
 
20.0
 
17.7%
 
9.5%
 
64.2%
                         
Horseshoe Bayou /Bayou Sale
 
2.8
 
3.3
 
6.1
 
5.4%
 
4.0%
 
25.9%
Jeanerette
 
1.0
 
4.1
 
5.2
 
4.6%
 
0.9%
 
7.8%
Cote Blanche Island
 
0.7
 
4.7
 
5.4
 
4.8%
 
0.6%
 
78.4%
Bayou Penchant
 
0.1
 
0.0
 
0.1
 
0.1%
 
0.7%
 
55.5%
High Island
 
1.2
 
0.0
 
1.2
 
1.1%
 
1.0%
 
100.0%
Total South Louisiana
 
5.8
 
12.1
 
18.0
 
15.9%
 
7.2%
 
41.6%
                         
Other
 
0.2
 
0.0
 
0.2
 
0.2%
 
  0.4%
 
4.3%
                         
Total
 
56.8
 
56.1
 
112.9
 
100%
 
100%
 
58.0%

Focus Areas

Our operations are primarily focused in four core areas identified as Southeast Louisiana, South Texas, Central Louisiana/East Texas, and South Louisiana.  In addition, we have a strategic growth area with acreage in the Four Corners area of southwest Colorado. South Texas is the oldest of our core areas, with our operations first established in the AWP field in 1989 and subsequently expanded with the acquisition of the Sun TSH, Briscoe Ranch, and Las Tiendas fields during 2007 and with additional interests in the Briscoe Ranch field in 2008. Operations in our Central Louisiana/East Texas area began in mid-1998 when we acquired the Masters Creek field in Louisiana and the Brookeland field in Texas, later adding the South Bearhead Creek field in Louisiana in late 2005. The Southeast Louisiana and South Louisiana areas were established when we acquired majority interests in producing properties in the Lake Washington field in early 2001, in the Bay de Chene and Cote Blanche Island fields in December 2004, and in the Bayou Sale, Bayou Penchant, Horseshoe Bayou, and Jeanerette fields in 2006.

Southeast Louisiana

Lake Washington. As of December 31, 2009, we owned drilling and production rights in 24,624 net acres in the Lake Washington field located in Southeast Louisiana nearshore waters within Plaquemines Parish. 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 and ranging in depth from 2,000 feet to 13,000 feet. The area around the dome is heavily faulted, thereby creating a large number of potential hydrocarbon traps. Approximately 93% of our proved reserves of 27.2 MMBoe in this field at December 31, 2009, consisted of oil and NGLs. Oil and natural gas from approximately 107 currently producing wells is gathered to four platforms located in water depths from 2 to 12 feet, with drilling and workover operations performed with rigs on barges.  The fourth platform, the Westside production processing facility, was commissioned in 2008.

7

 
In 2009, we drilled and completed 4 out of 5 development wells in Lake Washington.  We also drilled 2 exploratory wells and successfully completed one of them in Lake Washington. At year-end 2009, we had 96 proved undeveloped locations in this field. Our planned 2010 capital expenditures in the field will include drilling 10 to 15 wells and performing recompletions on up to 10 wells.

Bay de Chene. The Bay de Chene field is located along the border of Jefferson Parish and Lafourche Parish in  nearshore waters approximately 25 miles WNW of the Lake Washington field. As of December 31, 2009, we owned drilling and production rights in approximately 16,035 net acres in the Bay de Chene field.  Like Lake Washington, it produces from Miocene sands surrounding a central salt dome.  Partial production from the field was shut in from September 2008 through August 2009 due to damages that occurred from Hurricane Gustav in 2008.  The Bay De Chene facility was rebuilt and commissioned in August 2009.  During 2009 we did not drill any wells in the Bay De Chene field.  At year-end 2009, we had three proved undeveloped locations in the Bay de Chene field. During 2010, we plan to drill from 2 to 5 wells in Bay de Chene.

South Texas

AWP. The AWP field is located in McMullen County, Texas. As of December 31, 2009 we owned drilling and production rights in 71,997 net acres in the field and were operating 569 wells producing oil and natural gas from the Olmos sand formation at depths from 9,000 to 11,500 feet. Field reserves are approximately 62% natural gas and the reservoir has provided Swift Energy an opportunity to develop extensive experience with low-permeability, tight-sand formations. We own nearly 100% of the working interests in all these operated wells.  In 2009, we completed 11 out of 11 development wells drilled in the AWP field in South Texas and performed 29 fracture enhancements.  At year-end 2009, we had 83 proved undeveloped locations in the field.  Our planned 2010 capital expenditures will include drilling up to 4 horizontal wells in the Olmos formation, and performing approximately 30 fracture enhancements for wells in this field.

Eagle Ford Joint Venture. In November 2009, we entered into a joint venture agreement with an independent oil and gas producer to jointly develop and operate an approximate 26,000 acre portion of our Eagle Ford Shale acreage in McMullen County, Texas. Swift Energy retains a 50% interest in the joint venture that calls for joint development of this area located in our AWP field and covers leasehold interests beneath the Olmos formation (including the Eagle Ford Shale formation) extending to the base of the Pearsall formation. We received approximately $26 million in cash related to this transaction and approximately $13 million of carried interests which would be credited against future drilling costs.

We plan to drill up to 9 wells in 2010 through our joint venture and up to 6 wells on our own in 2010 targeting our Eagle Ford shale acreage in the AWP area.

Sun TSH, Briscoe Ranch, and Las Tiendas. In October 2007, Swift Energy acquired operating interests in three additional Olmos sand reservoirs producing in the Maverick Basin. These properties are in the Sun TSH field located in La Salle County, Briscoe Ranch field located in Dimmitt County and the Las Tiendas field located in Webb County. The fields produce primarily natural gas from depths of 4,500 to 7,500 feet.  As of December 31, 2009, we owned drilling and production rights in 97,502 net acres in these fields (21,882 in Sun TSH, 66,998 in Briscoe Ranch, 8,622 in Las Tiendas).  In 2009, we drilled and completed 2 development wells drilled in these fields. At year-end 2009, we were operating 243 wells in these fields and had 118 proved undeveloped locations.  Our planned 2010 capital expenditures include drilling from 6 to 10 wells in these fields all targeting the Eagle Ford shale acreage in these areas.

Central Louisiana/East Texas

Brookeland. The Brookeland field area is located in Newton County and Jasper County, Texas, and Vernon Parish, Louisiana. As of December 31, 2009, we owned drilling and production rights in 56,355 net acres and 3,500 fee mineral acres in this field.  The field consists of opposing dual lateral horizontal wells completed in the Austin Chalk formation. Oil and natural gas are produced from natural fractures encountered within the lateral borehole sections from depths of 11,500 to 13,500 feet. The reserves are approximately 58% oil and natural gas liquids.  During 2009 we did not drill any wells in the Brookland field and at year-end 2009, we had 10 proved undeveloped locations in the field.

8

 
In August 2009 we entered into a joint venture agreement with a large independent oil and gas producer active in the area for development and exploitation in and around the Burr Ferry field in Vernon Parish, Louisiana. Swift Energy, as fee mineral owner, leased a 50% working interest in approximately 33,623 gross acres to the joint venture partner. Swift Energy retains a 50% working interest in the joint venture acreage as well as its fee mineral royalty rights, and received approximately $4.2 million related to this transaction. We used the proceeds from this joint venture to pay down a portion of the outstanding balance on our credit facility.

Masters Creek. As of December 31, 2009, we owned drilling and production rights in 52,964 net acres and 91,594 fee mineral acres in the Masters Creek field. The Masters Creek field, located in Vernon Parish and Rapides Parish, Louisiana, consists of opposing dual lateral horizontal wells completed in the Austin Chalk formation. Oil and natural gas are produced from natural fractures encountered within the lateral borehole sections from depths of 11,500 to 13,500 feet. The reserves are approximately 71% oil and NGLs. We did not drill any wells in this field during 2009 and at year-end 2009, we had nine proved undeveloped locations. During 2010, we plan to drill 1 well in Masters Creek.

South Bearhead Creek. In 2005 and 2006, we acquired interests in the South Bearhead Creek field, which is located in Beauregard Parish, Louisiana approximately 50 miles south of our Masters Creek field and 30 miles north of Lake Charles, Louisiana. The field was discovered in 1958 and is a large east-west trending anticline closure with cumulative production over 4 million Boe.  As of December 31, 2009, we owned drilling and production rights in 8,074 net acres in this field.  Wells drilled in this field are completed in a multiple set of separate sands: Lower Wilcox - 12,500 to 14,500 feet; Middle and Upper Wilcox – 9,000 to 12,000 feet; and Cockfield – 8,000 to 9,000 feet.  In 2009, we did not drill any wells in this field and at year-end 2009, we had 18 proved undeveloped locations in this field.

South Louisiana

Cote Blanche Island.  The Cote Blanche Island field, acquired in 2005, is located in nearshore waters within St. Mary Parish. As of December 31, 2009, we owned drilling and production rights in 6,556 net acres in the Cote Blanche Island field. Like Lake Washington and Bay de Chene, it produces from Miocene sands surrounding a central salt dome.  During 2009 we did not drill any wells in the Cote Blanche Island field, and at year-end 2009, we had 18 proved undeveloped locations in the field.

Bayou Sale, Horseshoe Bayou, Jeanerette, and Bayou Penchant.  In October 2006 we acquired interests in four additional onshore fields in the area: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all located in St. Mary Parish), and Bayou Penchant field in Terrebonne Parish. As of December 31, 2009, we owned drilling and production rights in a total of 23,309 net acres in these fields (5,700 in Bayou Sale, 9,524 in Horseshoe Bayou, 5,088 in Jeanerette, and 2,997 in Bayou Penchant).  Bayou Sale and Horseshoe Bayou fields are adjacent to each other and located 13 miles southeast of our Cote Blanche Island field. They produce from several formations.  The Jeanerette field is positioned on the flank of a large salt dome 12 miles north of Cote Blanche Island and produces form the Planulina sands.  The Bayou Penchant field was discovered in the 1930s, and is located approximately 44 miles southeast of Cote Blanche Island in Terrebonne Parish.  Swift Energy holds an average 43% working interest in the wells in this non-operated field, which produces from a number of Middle Miocene sands.

In 2009, we did not drill any wells in our Bayou Sale, Horseshoe Bayou and Jeanerette fields. At year-end 2009, we had 47 proved undeveloped locations in the Bayou Sale, Horseshoe Bayou and Jeanerette fields.

High Island. In October 2006, we acquired interests in the High Island field in Cameron Parish along with our acquisition of interests in four fields in the South Louisiana area. The High Island field was discovered in 1983 and is located 65 miles west of Cote Blanche Island.  As of December 31, 2009, we owned drilling and production rights in 2,041 net acres in this field.  During 2009 we did not drill any wells in the High Island field.

Other

Four Corners. At the end of 2009, we had approximately 21,507 net acres leased in the Four Corners area of southwest Colorado.

9

 
New Zealand Areas (Discontinued Operations)

In December 2007, Swift Energy agreed to sell substantially all of our New Zealand assets. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of operations and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. In June 2008, Swift Energy completed the sale of substantially all of our New Zealand assets for $82.7 million in cash after purchase price adjustments.  Proceeds from this asset sale were used to pay down a portion of our credit facility.  In August 2008, we completed the sale of our remaining New Zealand permit for $15.0 million; with three $5.0 million payments to be received nine months after the sale, 18 months after the sale, and 30 months after the sale. All payments under this sale agreement are secured by unconditional letters of credit. Due to ongoing litigation, we have evaluated the situation and determined that certain revenue recognition criteria have not been met at this time for the permit sale, and have deferred the potential gain on this property sale pending final resolution of this litigation.

In February 2009, the first $5.0 million payment from the sale of our last permit was released to our attorneys who were holding these proceeds in trust for Swift Energy.  In April 2009, after an injunction limiting our ability to use such funds was dismissed in favor of Swift Energy, the proceeds were transferred to our bank account in the United States.

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 both domestically as of December 31, 2009, 2008, and 2007, and in New Zealand as of December 31, 2007. As of December 31, 2009 and 2008, our domestic proved reserves comprise all of the company’s proved reserves.  The information set forth in the tables regarding reserves is based on proved reserves reports prepared by us. Our Director of Reserves & Evaluations, the primary technical person responsible for overseeing the preparation of our reserves estimates, is a Licensed Professional Engineer, holds a bachelor’s and a master’s degree in chemical engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has over 20 years of experience supervising or preparing reserves estimates.  H.J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers, has audited 96% of our 2009 domestic proved reserves, 97% of our domestic proved reserves for 2008 and 100% of our domestic proved reserves for 2007. 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 20 years experience overseeing reserves audits. Based on its audits, 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.

Reserves estimates are based on extrapolation of established performance trends, material balance calculations, volumetric calculations, analogy with the performance of comparable wells, or a combination of these methods.  The classification and definitions of all proved reserves estimates are in accordance with Rule 4-10 of Regulation S-X and the auditing process was conducted in accordance with Regulation S-K, Item 1202.  The reserves audit performed by H.J. Gruy and Associates, Inc. is one control procedure used during the reserves estimation process to ensure the integrity of our reserves estimates.  In addition to the reserves audit, the reserves estimation process is conducted by senior engineers with a minimum of 10 years of reservoir engineering experience, and multiple levels of review and reconciliation are applied to their estimates before the estimates are finalized.

A reserves audit and a financial audit are separate activities with unique and different processes and results.  These two activities should not be confused.  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 year ended December 31, 2009, are made based on either the preceding 12-months’ average price based on closing prices on the first business day of each month, or prices defined by existing contractual arrangements 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. For the years ended December 31, 2008 and 2007, these same amounts are based on the same methodology except for the use of period-end oil and natural gas sales prices. 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.

10

 
Our hedges at year-end 2009 consisted of natural gas collars and price floors with strike price ranges outside the current period-end price and did not affect prices used in these calculations. The 12-month average 2009 prices for domestic operations were $3.78 per Mcf of natural gas, $59.76 per barrel of oil, and $30.00 per barrel of NGL compared to $4.96 per Mcf of natural gas, $44.09 per barrel of oil, and $25.39 per barrel of NGL at year end 2008 and $6.65 per Mcf of natural gas, $93.24 per barrel of oil, and $56.28 per barrel of NGL at year-end 2007. At December 31, 2009 and 2008, we did not have any reserves in New Zealand. The weighted averages of such year-end 2007 prices for New Zealand were $3.08 per Mcf of natural gas, $93.20 per barrel of oil, and $36.98 per barrel of NGL. The weighted averages of such year-end 2007 prices for all our reserves, both domestically and in New Zealand, were $6.19 per Mcf of natural gas, $93.24 per barrel of oil, and $54.63 per barrel of NGL.

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, 2009, 2008, and 2007. 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, which is calculated after provision for future income taxes. We combine NGL volumes with oil volumes solely for reserves volumes reporting purposes. We apply oil prices to proved oil reserves volumes and apply NGL prices to proved NGL reserves volumes in determining both the PV-10 and standardized measure values.  PV-10 is a non-GAAP measure; see the reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure, in the section below this table (MBoe amounts shown below are based on a natural gas conversion factor of 6 Mcf to 1 Boe):

 
As of December 31, 2009
 
Total
 
Domestic
 
Discontinued
Operations
Estimated Proved Oil and Natural Gas Reserves
         
Natural gas reserves (MMcf):
         
Proved developed
155,405
 
155,405
 
---
Proved undeveloped
135,148
 
135,148
 
---
Total
290,553
 
290,553
 
---
Oil, NGL, and Condensate reserves (MBbl):
         
Proved developed
30,897
 
30,897
 
---
Proved undeveloped
33,606
 
33,606
 
---
Total
64,503
 
64,503
 
---
           
Total Estimated Reserves (MBoe)
112,928
 
112,928
 
---
           
Estimated Discounted Present Value of Proved Reserves (in millions)
         
Proved developed
$766
 
$766
 
$---
Proved undeveloped
557
 
557
 
---
PV-10 Value
$1,323
 
$1,323
 
$---


 
11

 


 
As of December 31, 2008
 
Total
 
Domestic
 
Discontinued
Operations
Estimated Proved Oil and Natural Gas Reserves
         
Natural gas reserves (MMcf):
         
Proved developed
172,214
 
172,214
 
---
Proved undeveloped
120,166
 
120,166
 
---
Total
292,380
 
292,380
 
---
Oil, NGL, and Condensate reserves (MBbl):
         
Proved developed
33,411
 
33,411
 
---
Proved undeveloped
34,299
 
34,299
 
---
Total
67,710
 
67,710
 
---
           
Total Estimated Reserves (MBoe)
116,440
 
116,440
 
---
           
Estimated Discounted Present Value of Proved Reserves (in millions)
         
Proved developed
$832
 
$832
 
$---
Proved undeveloped
481
 
481
 
---
PV-10 Value
$1,313
 
$1,313
 
$---


 
As of December 31, 2007
 
Total
 
Domestic
 
Discontinued
Operations
Estimated Proved Oil and Natural Gas Reserves
         
Natural gas reserves (MMcf):
         
Proved developed
187,152
 
172,974
 
14,178
Proved undeveloped
206,862
 
170,824
 
36,038
Total
394,014
 
343,798
 
50,216
Oil, NGL, and Condensate reserves (MBbl):
         
Proved developed
36,753
 
35,548
 
1,205
Proved undeveloped
47,702
 
40,934
 
6,768
Total
84,455
 
76,482
 
7,973
           
Total Estimated Reserves (MBoe)
150,124
 
133,781
 
16,343
           
Estimated Discounted Present Value of Proved Reserves (in millions)
         
Proved developed
$2,025
 
$1,961
 
$65
Proved undeveloped
1,823
 
1,790
 
32
PV-10 Value
$3,848
 
$3,751
 
$97

Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering 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.

The closest GAAP measure to PV-10, a non-GAAP measure, is the standardized measure of discounted future net cash flows. We believe PV-10 is a helpful measure in evaluating the value of our oil and natural gas reserves and many securities analysts and investors use PV-10. We use PV-10 in our ceiling test computations, and we also compare PV-10 against our debt balances. The following table provides a reconciliation between PV-10 and the standardized measure of discounted future net cash flows:

 
12

 


   
As of December 31, 2009
 
 
 
Total
   
Domestic
   
Discontinued
Operations
 
(in millions)
                 
PV-10 Value
  $ 1,323     $ 1,323     $ ---  
                         
Future income taxes (discounted at 10%)
    (302 )     (302 )     ---  
Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves
  $ 1,021     $ 1,021     $ ---  


   
As of December 31, 2008
 
 
 
Total
   
Domestic
   
Discontinued
Operations
 
(in millions)
                 
PV-10 Value
  $ 1,313     $ 1,313     $ ---  
                         
Future income taxes (discounted at 10%)
    (280 )     (280 )     ---  
Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves
  $ 1,033     $ 1,033     $ ---  


   
As of December 31, 2007
 
 
 
Total
   
Domestic
   
Discontinued
 Operations
 
(in millions)
                 
PV-10 Value
  $ 3,848     $ 3,751     $ 97  
                         
Future income taxes (discounted at 10%)
    (1,212 )     (1,211 )     (1 )
Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves
  $ 2,636     $ 2,540     $ 96  

Domestic Proved Undeveloped Reserves

The following table sets forth the aging and PV-10 value of our domestic proved undeveloped reserves as of December 31, 2009:

Year Added
 
Volume
(MMBoe)
 
% of PUD
Volumes
 
PV-10 Value
(in millions)
 
% of PUD
PV-10 Value
2009
 
8.5
 
15%
 
$36.1
 
7%
2008
 
6.3
 
11%
 
61.8
 
11%
2007
 
10.3
 
18%
 
79.1
 
14%
2006
 
5.5
 
10%
 
76.5
 
14%
2005
 
8.2
 
15%
 
99.4
 
18%
2004
 
5.4
 
10%
 
111.4
 
20%
Prior to 2004
 
11.9
 
21%
 
93.5
 
16%
Total
 
56.1
 
100%
 
$557.8
 
100%

In our AWP field, we recorded 8.3 MMBoe of additional proved undeveloped reserves during 2009 based on the results of the horizontal drilling program conducted in the area during the year.  We also spent approximately $17.7 million in capital expenditures during the year to convert proved undeveloped reserves to proved developed reserves in the AWP and Lake Washington fields.  As of December 31, 2009, approximately 15% of our total proved reserves consisted of undeveloped reserves added prior to 2005, primarily in the Lake Washington, AWP, Masters Creek and Brookeland fields.  Our efforts to convert unproved locations during 2009 were significantly impacted by operating decisions made at that time in relation to the global financial crisis and depressed oil and natural gas prices, which significantly lowered capital expenditures.

 
13

 


Sensitivity of Domestic Reserves to Pricing

As of December 31, 2009, a 5% increase in oil and NGL pricing would increase our total estimated domestic proved reserves of 112.9 MMBoe by approximately 0.5 MMBoe, and increase the domestic PV-10 Value of $1.3 billion by approximately $89 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated domestic proved reserves by approximately 0.5 MMBoe and decrease the domestic PV-10 Value by approximately $88 million.

As of December 31, 2009 a 5% increase in natural gas pricing would increase our total estimated domestic proved reserves by approximately 0.5 MMBoe and increase the domestic PV-10 Value by approximately $26 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated domestic proved reserves by approximately 0.2 MMBoe and decrease the domestic PV-10 Value by approximately $26 million.

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)(2)
December 31, 2009:
     
Gross
469
825
1,294
Net
406.6
758.9
1,165.5
December 31, 2008:
     
Gross
510
817
1,327
Net
447.4
744.9
1,192.3
December 31, 2007:
     
Gross
504
761
1,265
Net
437.4
719.9
1,157.3

(1)  
Excludes 59 service wells in 2009 and 65 service wells in both 2008 and 2007.
(2)  
Includes 49 wells in New Zealand in 2007.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2009:

 
Developed(1)(2)
 
Undeveloped(3)(4)
 
Gross
 
Net
 
Gross
 
Net
Alabama
8,120
 
1,580
 
176
 
1
Colorado
---
 
---
 
31,888
 
21,507
Louisiana
120,537
 
102,046
 
32,193
 
26,587
Texas
154,786
 
112,990
 
131,959
 
125,717
Wyoming
640
 
151
 
6,651
 
4,664
Offshore Louisiana
4,609
 
277
 
---
 
---
All other states
---
 
---
 
721
 
257
Total
288,692
 
217,044
 
203,588
 
178,733

(1)
Fee Mineral acres are not included in the above leasehold acreage table.  We have 26,345 developed fee mineral acres and 68,689 undeveloped fee mineral acres for a total of 95,034 fee mineral acres.
(2)
In total, our Eagle Ford shale position encompassed approximately 89,000 gross and 76,000 net acres in our South Texas region.  A portion of this Eagle Ford acreage is below developed Olmos acreage.
(3)
Subsequent to 12/31/2009 leases covering 60,316 gross and 60,158 net undeveloped have expired in our Briscoe Ranch field in the South Texas region.
(4)
We also own overriding royalty interest ranging between 1% and 7.5% in 31,325 undeveloped acres in Texas and Wyoming.

 
14

 


Drilling and Other Exploratory and Development Activities

The following table sets forth the results of our drilling activities during the three years ended December 31, 2009:

 
 
Gross Wells
 
Net Wells
Year
Type of Well
Total
Producing
Dry
 
Total
Producing
Dry
2009
Exploratory — Domestic
2
1
1
 
2
1
1
 
Development — Domestic
18
17
1
 
18
17
1
 
Exploratory — New Zealand
 
 
Development — New Zealand
 
                 
2008
Exploratory — Domestic
3
2
1
 
1.8
1.5
0.3
 
Development — Domestic
123
108
15
 
120.0
106.0
14.0
 
Exploratory — New Zealand
 
 
Development — New Zealand
 
                 
2007
Exploratory — Domestic
5
2
3
 
5.0
2.0
3.0
 
Development — Domestic
64
59
5
 
62.6
58.1
4.5
 
Exploratory — New Zealand
 
 
Development — New Zealand
 

Additional development activities during 2008 included the commissioning of our fourth production platform, the Westside facility, in the Lake Washington field.

Present Activities

As of December 31, 2009, we were in the process of drilling four wells in South Texas (3.5 net wells) and one well in Southeast Louisiana in which we have a 100% working interest.  We have also continued the production optimization program in the Lake Washington field, involving gas lift enhancements and sliding sleeve shifts to change productive zones, to assist in mitigating natural field declines.

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.

Oil and natural gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator’s direct expenses and for payment of monthly per-well supervision fees. 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 2009 totaled $11.4 million and ranged from $374 to $2,888 per well per month.

Marketing of Production

We typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We usually sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. Shell Oil Company and its affiliates accounted for approximately 48% and 28% of our gross oil and gas sales in 2009 and 2008, respectively. In 2008, Chevron and its domestic affiliates accounted for 25% of our gross oil and gas sales. No other purchasers accounted for more than 10% of our total oil and gas sales for the past two years. Due to the demand for oil and natural gas and 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.

15

 
Our oil production from the Lake Washington field is 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). Our natural gas production from this field is either consumed on the lease or is delivered into El Paso’s Tennessee Gas Pipeline system and then sold in the spot market at prevailing prices. Natural gas delivered into Tennessee Gas Pipeline is processed at the Yscloskey plant.  In 2008, we completed a connection which provides for the delivery of natural gas from this field to El Paso’s Southern Natural Gas pipeline system (Sonat) and the processing of natural gas delivered to Sonat at the Toca Plant.

In 2008, we entered into gas processing and gas transportation agreements for our natural gas production in the AWP field with Enterprise Hydrocarbons L.P. and Enterprise South Texas Pipeline, replacing the ten-year agreements with Enterprise that expired in 2008. Processing revenues are received from Enterprise.  The residue gas is sold at downstream connections with the Enterprise pipeline at prevailing market prices.  Oil production is transported to market by truck or pipeline and sold at prevailing market prices.

In the Sun TSH, Briscoe Ranch and Las Tiendas fields, our oil production is sold at prevailing market prices and transported to market by truck.  Natural gas from the fields is delivered either to Enterprise South Texas Gathering or Regency Gas Services.  For natural gas delivered to Enterprise, the natural gas is sold to Enterprise; with Swift Energy receiving revenues from residue gas sales and processed liquids. For natural gas delivered to Regency, the natural gas production is transported to a downstream processing plant. We sell the residue gas at prevailing market prices and receive processing revenues from Regency.

Our oil production from the Brookeland, Masters Creek and South Bearhead Creek fields is sold to various purchasers at prevailing market prices. Our natural gas production from the Brookeland and Masters Creek fields is processed under long term gas processing contracts with Eagle Rock Operating, LLC. The processed liquids and residue gas production are sold in the spot market at prevailing prices. South Bearhead Creek natural gas production is sold into the interstate market on Trunkline Gas Company’s pipeline at prevailing market prices.

Our oil production from the Bay de Chene and Cote Blanche Island fields is transported on barges for sales to various purchasers at prevailing market prices. Natural gas production from both fields is sold into intrastate pipelines with prices tied to monthly and daily natural gas price indices.

In the fields of Bayou Sale, Horseshoe Bayou, High Island and Jeanerette in South Louisiana, we sell the oil production to various purchasers at prevailing market prices. The oil is transported to market by truck. Natural gas production for each of these fields is sold into one or more interstate pipelines at prevailing market prices.

The following table summarizes sales volumes, sales prices, and production cost information for our net oil and natural gas production from our continuing operations for the three-year period ended December 31, 2009:

 
Year Ended December 31,
 
2009
 
2008
 
2007
Net Sales Volume:
         
Oil (MBbls)
4,346
 
5,420
 
7,045
Natural Gas Liquids (MBbls)
1,183
 
1,211
 
774
Natural gas (MMcf) 1
19,211
 
18,872
 
15,288
Total (MBoe)
8,731
 
9,777
 
10,368
           
Average Sales Price:
         
Oil (Per Bbl)
$60.07
 
$101.38
 
$71.92
Natural Gas Liquids (Per Bbl)
$31.36
 
$57.15
 
$49.72
Natural gas (Per Mcf)
$3.83
 
$9.28
 
$7.04
           
Average Production Cost (Per Boe sold) 2
$8.79
 
$10.73
 
$6.84
1 Excludes gas consumed in operations that is included in reported production volumes
2 Excludes severance and ad valorem taxes

Oil and natural gas prices declined significantly in the latter part of 2008 from levels earlier in the year, and the average sales prices for 2008 are not indicative of prices in effect at the end of 2008. The prices above also 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.

16

 
xThe following table provides a summary of our production, average sales prices, and average production costs for fields containing 15% or more of our total proved reserves as of December 31, 2009:

 
Year Ended December 31,
 
2009
 
2008
 
2007
Lake Washington
         
           
Net Production:
         
Oil (MBbls)
3,199
 
3,999
 
5,719
Natural Gas Liquids (MBbls)
75
 
178
 
202
Natural gas (MMcf) 1
931
 
2,309
 
3,145
Total (MBoe)
3,430
 
4,562
 
6,446
           
Average Sales Price:
         
Oil (Per Bbl)
$59.62
 
$100.21
 
$71.71
Natural Gas Liquids (Per Bbl)
$43.55
 
$78.02
 
$51.12
Natural gas (Per Mcf)
$4.37
 
$9.68
 
$6.93
           
Average Production Cost (Per Boe sold) 2
$9.13
 
$8.59
 
$4.10
           
AWP
         
           
Net Production:
         
Oil (MBbls)
197
 
197
 
139
Natural Gas Liquids (MBbls)
496
 
344
 
225
Natural gas (MMcf) 1
5,623
 
5,125
 
4,436
Total (MBoe)
1,630
 
1,395
 
1,103
           
Average Sales Price:
         
Oil (Per Bbl)
$58.52
 
$95.81
 
$71.80
Natural Gas Liquids (Per Bbl)
$29.68
 
$50.94
 
$47.69
Natural gas (Per Mcf)
$3.63
 
$9.15
 
$7.27
           
Average Production Cost (Per Boe sold) 2
$6.51
 
$9.35
 
$9.80
 Excludes gas consumed in operations that is included in reported production volumes
2 Excludes severance and ad valorem taxes

Our New Zealand production and pricing information is included in the Discontinued Operations discussion within the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this Form 10-K.

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. See “1A. Risk Factors” of this report for more details and for discussion of other risks. We maintain comprehensive insurance coverage, including general liability insurance, officer and director liability insurance, and property damage insurance. Prior to and at the time of Hurricanes Katrina and Rita, we maintained business interruption insurance as well. Since such time, the cost of such business interruption insurance coverage increased to a level that we believe makes it uneconomical to maintain at this time. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect us.

 
17

 

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, mainly through the purchase of price floors and participating collars when appropriate. At December 31, 2009, we had natural gas price collars in effect for the contract months of January through March 2010 that covered a portion of our natural gas production for January to March 2010.  The natural gas price collars contain a floor that covers notional volumes of 200,000 MMBtu per month and a call that covers 100,000 MMBtu per month, for the same period.  The weighted average floor price is $4.50 and the weighted average call price is $6.80 per MMBtu. At December 31, 2009, we had natural gas price floors in effect for the contract months of January through June 2010 that covered a portion of our natural gas production for January to June 2010. These floors cover additional natural gas production of 2,400,000 MMBtu from January through March 2010 and 2,640,000 MMBtu from April through June 2010 with strike prices ranging between $4.55 and $4.96.

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.

Regulations

Environmental Regulations

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

We currently own or lease, and have in the past owned or leased, numerous properties in connection with our operations that have been used for the exploration and production of oil and natural gas for many years. Although we have used operation and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law, the federal Resource Conservation and Recovery Act or “RCRA,” the federal Clean Water Act, the federal Clean Air Act, the federal Oil Pollution Act or “OPA,” and analogous state laws. Under such laws and any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment.

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Our operations offshore in the Gulf of Mexico are subject to OPA, which imposes a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party fails to report the spill or cooperate fully in any resulting cleanup. The OPA also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe our operations are in substantial compliance with OPA requirements.

United States Federal and State Regulation of Oil and Natural Gas

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

Our sales of crude oil, condensate and NGLs are not currently subject to FERC regulation. However, the ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation.

Since December 2007, Congress has passed the Energy Independence and Security Act of 2007, the Energy Economic Stabilization Act of 2008, and the American Recovery and Reinvestment Act of 2009, each of which contains various provisions affecting the oil and gas industry and related tax provisions.  In future periods, Congress may decide to revisit legislation introduced in prior sessions to repeal existing incentives or impose new taxes on the exploration and production of oil and natural gas, and/or create new incentives for alternative energy sources.  If enacted, such legislation could reduce the demand for and uses of oil, natural gas and other minerals and/or increase the costs incurred by the Company in its exploration and production activities, which could affect the Company’s revenues, costs, and profits.

Production of any oil and natural gas by us will be affected to some degree by state regulations. Many states in which we operate have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and natural gas and to protect correlative rights to produce oil and natural gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and natural gas produced by assigning allowable rates of production to each well or proration unit, which could restrict the rate of production below the rate that a well would otherwise produce in the absence of such regulation. In addition, certain state regulatory authorities can limit the number of wells or the locations where wells may be drilled. Any of these actions could negatively affect the amount or timing of revenues.

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.  We have further discussed our New Zealand litigation in footnote 8 of the notes to consolidated financial statements (“Discontinued Operations”).

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Employees

At December 31, 2009, we employed 295 persons. None of our employees are represented by a union. Relations with employees are considered to be good.

Facilities

At December 31, 2009, we occupied approximately 202,355 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring February 2015. The lease requires payments of approximately $440,000 per month. We also have field offices in various locations from which our employees supervise local oil and natural gas operations.

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 Principal Executive Officer. 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.

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 all the material risks relating to our business activities.
 
Enactment of Congressional and regulatory proposals under consideration could negatively affect our business.

Numerous legislative and regulatory proposals affecting the oil and gas industry have been proposed or are under consideration by the Obama administration, Congress and various federal agencies.  Among these proposals are: (1) climate change legislation introduced in Congress, Environmental Protection Agency regulations, carbon emission "cap-and-trade" regimens, and related proposals, none of which have been have been adopted in final form; (2) proposals contained in the President's budget, along with legislation introduced in Congress, none of which have been enacted by both houses of Congress, to repeal various tax deductions or exemptions available to oil and gas producers, such as the tax deduction for intangible drilling and development costs, which 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 being considered by Congress that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act, which could affect Company operations, their effectiveness, and the costs thereof.  Any such future laws and regulations could result in increased costs or additional operating restrictions, and could have an effect on demand for oil and gas or prices at which it can be sold.  Until any such legislation or regulations are enacted or adopted, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.
 
The continuing pressure on the global credit and financial markets could materially and adversely impact our financial results.

As widely reported, global credit and financial markets have been experiencing extreme disruptions since the second half of 2008, including, severely diminished liquidity and credit availability, volatility in consumer confidence, declines in economic growth, increases in unemployment rates, and uncertainty about economic stability.  We cannot assure you that there will not be further deterioration in credit, financial, or commodities markets.   These economic conditions have led to less demand and lower pricing for crude oil and natural gas, as demonstrated by the decline in commodity prices which occurred during the later part of 2008 and into 2009. Our profitability will be significantly affected by decreased demand and lower commodity prices. Our future access to capital and the availability of future financing could be limited due to tightening credit markets that could affect our ability to fund our capital projects.  
 
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Our operating results may be adversely affected if economic conditions impact the financial viability of our insurers, oil and gas purchasers, suppliers and commodity derivatives counterparties.

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.

Negative credit market conditions may adversely affect our access to capital, our liquidity and ability to refinance our debt.

Our future access to capital could be limited due to tightening credit markets that could affect our ability to fund our future capital projects. Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our line of credit or cause them to make the terms of our line of credit costlier or more restrictive. We are subject to semi-annual reviews of our borrowing base and commitment amount under our line of credit, and do not know the result of future redeterminations or the effect of then current oil and gas prices on that process.  Additionally, our line of credit matures in October 2011, and although it has a zero balance as of December 31, 2009, long-term restriction or freezing of the capital markets may affect the availability or pricing of our renewal of the line of credit.

Approximately 44% of our 2009 reserves and 60% of our 2009 production are located in our South Louisiana and Southeast Louisiana core areas.  If this area is hit by a hurricane or we have a pipeline outage, it could cause us to suffer significant losses.

Hurricane activity in 2007 and 2008 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 Katrina and Rita in 2005, and by Hurricanes Gustav and Ike in 2008.  Due to increased costs after the 2005 hurricanes, we no longer carry business interruption insurance.  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.

We have incurred a write-down of the carrying values of our properties in the current year and could incur additional write-downs in the future.

Under the full cost method of accounting, 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. Under these rules, capitalized costs of proved reserves may not exceed a ceiling calculated as the present value of estimated future net revenues from those proved reserves, determined using a 10% per year discount and unescalated prices in effect as of the end of each fiscal quarter for periods ending before December 31, 2009. Starting with our financial statements ending December 31, 2009 the unescalated prices are now calculated using a twelve month rolling average price from the first business day of each month. Capital costs in excess of the ceiling must be permanently written down. Low oil and gas prices at December 31, 2008 and March 31, 2009 led to $473.1 and $50.0 million non-cash after-tax write-downs of our oil and gas properties, respectfully.  If oil and gas prices decline, subject to the degree to which we incur additional capital costs on oil and gas properties and add proved reserves, we may be required to record further write-downs of our oil and gas properties in subsequent periods.

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 such insurance.
 
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Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices would adversely affect our financial results.

Our future revenues, net income, cash flow, and the value of our oil and natural gas properties depend primarily upon market prices for oil and natural gas. Oil and natural gas prices historically have been volatile and will likely continue to be volatile in the future. The recent oil and natural gas prices may not continue and could drop precipitously in a short period of time. The prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, worldwide economic conditions, weather conditions, currency exchange rates, and political conditions in major oil producing regions, especially the Middle East. A significant decrease in price levels for an extended period would negatively affect us in several ways:

• 
our cash flow would be reduced, decreasing funds available for capital expenditures employed to increase production or replace reserves;
• 
certain reserves would no longer be economic to produce, leading to both lower cash flow and 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
• 
access to other sources of capital, such as equity or long term debt markets, could be severely limited or unavailable in a low price environment.

Consequently, our revenues and profitability would suffer.

Our level of debt could reduce our financial flexibility.

As of December 31, 2009, our total debt comprised approximately 41% of our total capitalization. Although our bank credit facility and indentures limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness, we will be permitted to incur significant additional indebtedness, including secured indebtedness, in the future if specified conditions are satisfied. Higher levels of indebtedness could negatively affect us by requiring us to dedicate a substantial portion of our cash flow to the payment of interest, and limiting our ability to obtain financing or raise equity capital in the future.

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 this report are only estimates and subject to numerous uncertainties. Estimates by other engineers might differ materially. 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. These variances may be significant.

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 net cash flows from our oil and natural gas reserves.

At December 31, 2009, approximately 50% 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.
 
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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 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 bank credit facility. Even if we have the capital to drill, 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.

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 or tropical storms;
• 
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 contaminate
• 
abnormally pressured formations;
• 
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
• 
fires and explosions;
• 
personal injuries and death; and
• 
natural disasters.

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, as is the case in our declining business interruption insurance following the hurricanes in 2005. 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.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us.

Reserves on acquired properties may not meet our expectations, and we may be unable to identify liabilities associated with acquired properties or obtain protection from sellers against associated liabilities.

Property acquisition decisions are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately a property’s production and profitability. In addition, we may have difficulty integrating future acquisitions into our operations, and they may not achieve our desired profitability objectives. Likewise, as is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title except through the transferor. In many instances, title opinions are not obtained if, in our judgment, it would be uneconomical or impractical to do so. Losses may result from title defects or from defects in the assignment of leasehold rights. While our current operations are primarily in Louisiana and Texas, we may pursue acquisitions of properties located in other geographic areas, which would decrease our geographical concentration, and could also be in areas in which we have no or limited experience.

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In addition, our assessment of acquired properties may not reveal all existing or potential problems or liabilities, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform, or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of acquired properties in addition to the risk that the properties may not perform in accordance with our expectations.

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, 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.

In many instances, title opinions on our oil and gas acreage are not obtained if in our judgment it would be uneconomical or impractical to do so.

As is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.

Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and expose us to risk of financial loss.

We enter into hedging transactions for our oil and natural gas production to reduce exposure to fluctuations in the price of oil and natural gas, primarily to protect against declines in prices, although we typically enter into only short-term hedges covering less than 50% of our anticipated production, which limits the price protection they provide. Our hedges at year-end 2009 consisted of natural gas collars and price floors with strike price ranges outside the current period-end price. Our hedging transactions have also historically consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions as well as crude oil price floors. We intend to continue to enter into these types of hedging transactions in the foreseeable future when appropriate. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions other than floors may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Additionally, hedging transactions other than floors may expose us to cash margin requirements.

We may have difficulty competing for oil and gas properties or supplies.

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.
 
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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. 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.

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

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in our efforts 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 operations. 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, or cleanup requirements could have a material adverse effect on our operations and financial position.

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:

 
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.
 
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. 1
 
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.
 
EBITDA — Earnings before interest, taxes, depreciation, depletion and amortization.
 
EBITDAX — Earnings before interest, taxes, depreciation, depletion and amortization, and exploration expenses. Since Swift Energy uses full-cost accounting for oil and property expenditures, as noted in footnote one of the accompanying consolidated financial statements, exploration expenses are not applicable to Swift Energy.
 
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. 2
 
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.
 
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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 on or after December 31, 2009, 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. 3
 
Proved Undeveloped (PUD) Locations — A location containing proved undeveloped reserves.
 
PV-10 Value — The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization.  PV-10 Value is a non-GAAP measure and its use is explained under “Item 2. Properties - Oil and Natural Gas Reserves” above in this Form 10-K.
 
SFAS  Statement of Financial Accounting Standards.
 
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. 4

 
Notes to Abbreviations and Terms Above

 
The Regulation S-X definitions below refer to the revised definitions effective January 1, 2010.

 
1. This is only an abbreviated definition.  Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(6) of Regulation S-X.
 
2. This is only an abbreviated definition.  Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(13) of Regulation S-X.
 
3. This is only an abbreviated definition.  Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(22) of Regulation S-X.
 
4. This is only an abbreviated definition.  Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(31) of Regulation S-X.

Item 3. Legal Proceedings

No material legal proceedings are pending other than ordinary, routine litigation and claims incidental to our business.  We have further discussed our New Zealand litigation in footnote 8 of the notes to consolidated financial statements (“Discontinued Operations”)

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Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted during the fourth quarter of 2009 to a vote of security holders.

 
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PART II

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

Common Stock, 2008 and 2009

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 2008 and 2009 were as follows:

 
2008
 
2009
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Low
$39.64
$44.80
$36.83
$15.30
 
$4.95
$7.46
$13.09
$20.88
High
$49.98
$66.06
$67.03
$37.83
 
$21.23
$19.38
$25.61
$25.43

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

We had approximately 193 stockholders of record as of December 31, 2009.

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.
 
SFY 5 yr comparison

 
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Item 6. Selected Financial Data

(in thousands except per share and well amounts)
 
2009
   
2008
   
2007
   
2006
   
2005
 
 
                             
Total Revenues from Continuing Operations (1)
  $ 370,445     $ 820,815     $ 654,121     $ 550,836     $ 354,365  
                                         
Income (Loss) from Continuing Operations,  Before Income
                                       
Taxes and Change in Accounting Principle (1)
  $ (64,617 )   $ (412,758 )   $ 244,556     $ 248,308     $ 156,129  
                                         
Income (Loss) from Continuing Operations (1)
  $ (39,076 )   $ (257,130 )   $ 152,588     $ 151,074     $ 97,880  
                                         
Net Cash Provided by Operating Activities -
                                       
Continuing Operations
  $ 226,176     $ 582,027     $ 442,282     $ 383,241     $ 236,791  
                                         
Per Share and Share Data
                                       
Weighted Average Shares Outstanding(1)
    33,594       30,661       29,984       29,265       28,496  
Earnings per Share--Basic(1)
  $ (1.16 )   $ (8.39 )   $ 5.09     $ 5.16     $ 3.43  
Earnings per Share--Diluted(1)
  $ (1.16 )   $ (8.39 )   $ 4.98     $ 5.03     $ 3.34  
Shares Outstanding at Year-End
    37,457       30,869       30,179       29,743       29,010  
Book Value per Share at Year-End
  $ 18.12     $ 19.47     $ 27.70     $ 26.83     $ 20.94  
Market Price
                                       
High
  $ 25.61     $ 67.03     $ 47.72     $ 51.84     $ 50.01  
Low
  $ 4.95     $ 15.30     $ 35.98     $ 35.48     $ 24.77  
Year-End Close
  $ 23.96     $ 16.81     $ 44.03     $ 44.81     $ 45.07  
                                         
Assets
                                       
Current Assets
  $ 108,600     $ 78,086     $ 199,950     $ 83,783     $ 110,199  
Property & Equipment, Net of Accumulated
                                       
Depreciation, Depletion, and Amortization
  $ 1,315,964     $ 1,431,447     $ 1,760,195     $ 1,239,722     $ 862,717  
Total Assets
  $ 1,434,765     $ 1,517,288     $ 1,969,051     $ 1,585,682     $ 1,204,413  
                                         
Liabilities
                                       
Current Liabilities
  $ 103,604     $ 153,499     $ 210,161     $ 145,471     $ 98,421  
Long-Term Debt
  $ 471,397     $ 580,700     $ 587,000     $ 381,400     $ 350,000  
Total Liabilities
  $ 755,866     $ 916,411     $ 1,132,997     $ 787,765     $ 597,094  
                                         
Stockholders’ Equity
  $ 678,899     $ 600,877     $ 836,054     $ 797,917     $ 607,318  
                                         
Number of Domestic Employees
    295       334       298       272       236  
                                         
Domestic Producing Wells
                                       
Swift Operated
    1,146       1,168       1,091       926       854  
Outside Operated
    148       159       127       112       69  
Total Domestic Producing Wells
    1,294       1,327       1,218       1,038       923  
                                         
Domestic Wells Drilled (Gross)
    20       126       69       55       54  
                                         
Domestic Proved Reserves
                                       
Natural Gas (Bcf)
    290.6       292.4       343.8       269.7       225.3  
Oil, NGL, & Condensate (MMBbls)
    64.5       67.7       76.5       73.5       69.8  
Total Domestic Proved Reserves (MMBoe equivalent)
    112.9       116.4       133.8       118.4       107.3  
                                         
Domestic Production (MMBoe equivalent)
    9.1       10.0       10.6       9.4       7.2  
                                         
Domestic Average Sales Price (2)
                                       
Natural Gas (per Mcf produced)
  $ 3.48     $ 8.54     $ 6.42     $ 6.44     $ 7.40  
Natural Gas Liquids (per barrel)
  $ 31.36     $ 57.15     $ 49.72     $ 38.70     $ 34.00  
Oil (per barrel)
  $ 60.07     $ 101.38     $ 71.92     $ 64.28     $ 53.45  
Boe Equivalent
  $ 41.05     $ 79.00     $ 61.49     $ 56.89     $ 49.61  

(1) Amounts have been retroactively adjusted in all periods presented to give recognition to: (a) discontinued operations related to the sale of our New Zealand oil & gas assets, and (b) the conversion of production and reserves volumes to a Boe basis.

(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. Natural gas sales prices represents the amount realized per MCF of production.

 
29

 


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, 2009, 2008, and 2007 included with this report. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 42 of this report.

Overview

We are an independent oil and natural gas company formed in 1979, and we are engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from the inland waters of Louisiana and from our onshore Louisiana and Texas properties.

We are one of the largest producers of crude oil in the state of Louisiana, due to our South Louisiana operations, with oil constituting 48% of our 2009 production, and together with oil and natural gas liquids (“NGLs”) making up 61% of our 2009 production.  This emphasis has allowed us to benefit from better margins for oil production than natural gas production in 2009.
 
Unless otherwise noted, both historical information for all periods and forward-looking information provided in this Management’s Discussion and Analysis relates solely to our continuing operations located in the United States, and excludes our New Zealand operations discontinued in 2007.
 
2009 Oil and Natural Gas Pricing
 
Significantly reduced prices for oil and natural gas have had a significant impact on our cash flow, capital expenditures, and liquidity over the past year.  Both oil and natural gas prices we received in 2009 were lower than the average prices we received in 2008, with a 48% decline in average prices per BOE received.  These declines reduced our cash flow from operations in 2009 and will continue to reduce our cash flow from operations in future periods if prices remain at these lower levels.  Although prices at the end of 2009 were higher than the average prices we received during 2009, these prices were still significantly lower than the prices we received during 2008.
 
Financial Condition
 
We raised $108.8 million through an underwritten public stock offering in August 2009.  We issued 6.21 million shares of our common stock at a price of $18.50 per share.  The gross proceeds from these sales were approximately $114.9 million, before deducting underwriting commissions and issuance costs totaling $6.1 million.

In November 2009, we issued $225.0 million of 8-7/8% senior notes due 2020 at 98.389% of par, which equates to an effective yield to maturity of 9-1/8%.

In December 2009, we redeemed all $150.0 million of our 7-5/8% senior notes due 2011 and recorded a charge of $4.0 million related to the redemption of these notes, which is recorded in “Debt retirement costs” on the accompanying consolidated statement of operations.  The costs were comprised of approximately $2.9 million of premium paid to redeem the notes, and $1.1 million to write-off unamortized debt issuance costs.

We used the proceeds from this stock sale and note offering, less costs to redeem our senior notes due 2011, to pay down the outstanding balance on our credit facility.
 
Our debt to capitalization ratio decreased to 41% at December 31, 2009, as compared to 49% at year-end 2008, as paid in capital increased and our total debt balance decreased due to our stock offering, offset somewhat by a retained earnings decrease due to our net loss for 2009, which included a non-cash write-down of our oil and gas properties.
 
Operating Results- Prior Year Comparison
 
In 2009 we had revenues of $370.4 million, a decrease of 55% compared to 2008 levels. Our weighted average sales price received decreased 48% to $41.05 per Boe for 2009 from $79.00 per Boe in 2008. This $450.4 million decrease in revenues from 2008 levels resulted from lower oil, natural gas, and NGL prices during 2009, along with a 10% decrease in production mainly due to natural declines in our Lake Washington field.
 
30

 
Our overall costs and expenses decreased in 2009 by $798.5 million when compared to 2008 levels.  The 2008 period included a non-cash write-down of our oil and gas properties of $754.3 million in the fourth quarter of 2008, while the 2009 period included a non-cash write-down of our oil and gas properties of $79.3 million in the first quarter of 2009.  Depreciation, depletion and amortization expense also decreased 25%, mainly due to our lower depletable property base in the 2009 period due to the non-cash write-downs mentioned above, lower production in the 2009 period, partially offset by a reduction in reserves volumes when compared to the 2008 period.  Severance and other taxes decreased 49% mainly due to decreased oil and gas revenues.  Lease operating costs decreased by 27% due to less hurricane related costs, decreased workover costs, decreased natural gas processing costs, and a decrease in plant operating expense resulting from targeted cost reduction initiatives.
 
Our loss from continuing operations for 2009 was $39.1 million.  If the $79.3 million ($50.0 million after tax) first quarter 2009 non-cash write-down of our oil and gas properties is excluded our income after tax would have been $11.0 million. This compares to a loss from continuing operations of $257.1 million. If the $754.3 million ($473.1 million after tax) fourth quarter 2008 non-cash write-down of our oil and gas properties is excluded our income after tax would have been $216.0 million for 2008.
 
Operating Activities
 
In our South Texas core area, the first three wells of our 2009 horizontal drilling and completion program targeting the Olmos formation at the AWP field finished drilling and were completed, while another horizontal well was completed in January 2010.  We also drilled seven vertical wells in the AWP field.
 
In January 2010, we commenced drilling two wells targeting the Eagle Ford shale formation and expect them both to be completed during March 2010.
 
Additionally, in excess of 150 wells in the AWP field have been identified as candidates for additional fracture stimulation.  In 2009, twenty nine of these wells have been re-fractured.  We plan to perform thirty re-fracture operations in 2010.
 
In November 2009, we entered into a joint venture agreement with an independent oil and gas producer to jointly develop and operate an approximate 26,000 acre portion of our Eagle Ford Shale acreage in McMullen County, Texas. Swift Energy retains a 50% interest in the joint venture that calls for joint development of this area located in our AWP field and covers leasehold interests beneath the Olmos formation (including the Eagle Ford Shale formation) extending to the base of the Pearsall formation.  We received approximately $26 million in cash related to this transaction and approximately $13 million of carried interests. The first well under the joint venture agreement, in which we own a 50% interest, commenced drilling in late December 2009 to test the Eagle Ford shale formation and is expected to be completed in the first quarter of 2010.

In the Central Louisiana/East Texas core area, we recently entered into a joint venture agreement with a large independent oil and gas producer active in the area for development and exploitation in and around the Burr Ferry field in Vernon Parish, Louisiana. The Company, as fee mineral owner, leased a 50% working interest in approximately 33,623 gross acres to the joint venture partner. Swift Energy retains a 50% working interest in the joint venture acreage as well as its fee mineral royalty rights, and received approximately $4.2 million related to this transaction.

At Lake Washington during 2009, a production optimization program involving gas lift enhancements and sliding sleeve shifts to change productive zones was continued to assist in mitigation of natural field declines. In 2009 we completed 29 sliding sleeve changes, 9 gas lift modifications, and 3 acid jobs. We also drilled 5 shallow wells in the later part of 2009, completing four of them while one was unsuccessful.

In our Southeast Louisiana and South Louisiana core areas we have completed 4,000 square miles of 3D prestack seismic depth migration over our Lake Washington, Shasta, Bay de Chene, High Island, Cote Blanche Island, Horseshoe Bayou , Bayou Sale and Jeanerette fields. This depth migration and updated “salt model” has significantly improved and refined our understanding of the complex traps associated with salt bodies and will enable us to more accurately plan and position our exploratory and development wells. This seismic processing combined with seismic pore pressure prediction has allowed us to increase our confidence in well planning and drilling of wells that are deeper and larger in our Southeast Louisiana and South Louisiana areas. The improved seismic image in our Southeast Louisiana and South Louisiana core areas described above has delivered additional high value prospects which could be drilled later this year or next depending upon the commodity pricing environment.

31

 
We have spent considerable time and capital on facility capacity upgrades and additions in the Lake Washington field. Our fourth production platform, the Westside facility, was commissioned in the second quarter of 2008.  In the first quarter of 2009, the through-put capacity of this facility was doubled to 20,000 barrels of oil per day and 40 MMCF of natural gas per day. As a result of this expansion, and continued production decline in older portions of the field, production from our SL 212 facility was redirected to Westside.  This has resulted in a reduction in lease operating expenses as the Westside facilities are newer and require less maintenance.  The expanded capacity at the Westside facilities was also utilized to process production from our SL 18669 #1 (Shasta) well starting in late April 2009.
 
In the third quarter of 2008, our Bay de Chene field experienced significant damage to its production facilities from Hurricane Gustav, and some production equipment in the field was damaged or destroyed.  Also in the third quarter of 2008, Hurricane Ike caused damage to several fields in our South Louisiana core area and our High Island field due to high water levels.  In April 2009, we settled our marine insurance claim relating to Hurricane Gustav for a net amount after deductible of $6.8 million, and in September 2009 settled our onshore claim relating to Hurricane Ike for a net amount after deductible of $0.8 million.  Both of these reimbursements related to both capital costs and lease operating expense, and we have no additional hurricane related claims outstanding.

Repairs to existing infrastructure as well as the installation of new production equipment and structures for our Bay De Chene field were completed in the third quarter of 2009. In previous quarters, since Hurricane Gustav in 2008, only high-pressure natural gas was produced from the field through existing high-pressure natural gas facilities. Oil and low pressure natural gas production was reinstated after repairs and new facilities installations were completed.
 
Capital Expenditures
 
Our capital expenditures on a cash flow basis during 2009 were $215.4 million, while our accrual based capital expenditures were $174.6 million, as during the first quarter of 2009 we paid significant accounts payable and accrued capital cost balances incurred prior to year-end 2008.  This cash flow basis amount of capital expenditures decreased by $413.0 million as compared to the 2008 period, primarily due to a decrease in our spending on drilling and development, predominantly, in our Southeast Louisiana and South Texas core areas. These 2009 expenditures were primarily funded by $226.2 million of cash provided by operating activities from continuing operations, and $31.1 million from the sale of properties and proceeds from joint ventures.
 
We currently plan to balance our 2010 accrual based capital expenditures with our 2010 cash flow and cash on hand.  Our 2010 capital expenditures are currently budgeted at $300 million to $375 million, net of minor non-core dispositions and excluding any property acquisitions.  These expenditures are expected to include: a continuation of the horizontal well drilling program in the Olmos sands in our AWP field, an ongoing horizontal well program in the Eagle Ford shale formation in the AWP and other South Texas areas, continuing our drilling activity in Lake Washington by targeting shallow and intermediate depth oil prospects, continuing the recompletion program in our Southeast Louisiana core area and the fracture enhancement program in our South Texas core area.
 
Actions taken in response to the credit crisis and downturn in the industry
 
In 2009, the Company took several steps to manage lower cash flow and provide liquidity in future periods including:

·  
Raised $108.8 million, after deducting commissions and offering costs, through an underwritten public stock offering in August 2009.  We used the proceeds from this stock sale to pay down a portion of the outstanding balance on our credit facility.
·  
Issued $225.0 million of senior notes due 2020 (issued at 98.389% of par) in November 2009 in order to redeem all of our $150 million of senior notes due 2011 in December 2009.
·  
Reduced 2009 capital expenditures when compared to our 2008 total capital costs incurred of $674.7 million (including acquisitions).  We spent $215.4 million in 2009, which was below our cash provided by operating activities.
·  
Reduced our workforce.  In early 2009, we reduced our workforce, in response to the change in our level of operational activity, which will lower general and administrative costs in future periods.
·  
Reduced our field lease operating expenses.
·  
Re-determined our bank credit facility. Our borrowing base and commitment amount in November 2009 was re-set at $277.5 million, a decrease from our previous borrowing base and commitment amount of $300 million.

 
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Results of Continuing Operations — Years Ended 2009, 2008, and 2007

Revenues. Our revenues in 2009 decreased by 55% compared to revenues in 2008 primarily due to lower oil and gas prices as well as decreased production from our Southeast Louisiana core area. Our revenues in 2008 increased by 25% compared to 2007 revenues due to higher oil and gas prices partially offset by decreased production from our Southeast Louisiana core area. Revenues for 2009, 2008, and 2007 were substantially comprised of oil and gas sales. Crude oil production was 48% of our production volumes in 2009, 54% in 2008, and 66% in 2007. Natural gas production was 39% of our production volumes in 2009, 34% in 2008, and 26% in 2007. The remaining production in each year was from natural gas liquids (NGLs).

Our properties are divided into the following core areas: The Southeast Louisiana core area includes the Lake Washington and Bay de Chene fields. The Central Louisiana/East Texas core area includes the Brookeland, Masters Creek, and South Bearhead Creek and Chunchula fields. The South Louisiana core area includes the Cote Blanche Island, Horseshoe Bayou/Bayou Sale, Jeanerette, Bayou Penchant fields and High Island.  The South Texas core area includes the AWP, Briscoe Ranch, Las Tiendas, and Sun TSH fields. We also have a Strategic Growth category for our other strategic fields. The following table provides information regarding the changes in the sources of our oil and gas production and volumes for the years ended December 31, 2009, 2008, and 2007:

Core Areas
 
Oil and Gas Sales (In Millions)
   
Net Oil and Gas Production Volumes (MBoe)
 
   
2009
   
2008
   
2007
   
2009
   
2008
   
2007
 
S. E. Louisiana
  $ 232.5     $ 486.4     $ 477.0       4,782       5,323       7,178  
South Texas
    77.4       158.6       72.0       2,721       2,793       1,517  
Central Louisiana / E. Texas
    37.0       84.7       48.7       864       1,034       872  
South Louisiana
    24.1       61.6       50.2       660       850       961  
Strategic Growth
    0.7       2.6       5.0       28       49       89  
Total
  $ 371.7     $ 793.9     $ 652.9       9,055       10,049       10,617  

Our 2008 production was adversely affected by Hurricanes Gustav and Ike.  As a result of these hurricanes, approximately 0.8 MMBoe of production was shut-in during 2008 predominantly in Southeast Louisiana.  All of this shut-in production was brought online in 2009.

Oil and gas sales in 2009 decreased by 53%, or $422.1 million, from the level of those revenues for 2008, and our net production volumes in 2009 decreased by 10%, or 1.0 MMBoe, over net production volumes in 2008. Average prices for oil decreased to $60.07 per Bbl in 2009 from $101.38 per Bbl in 2008. Average natural gas prices decreased to $3.48 per Mcf in 2009 from $8.54 per Mcf in 2008. Average NGL prices decreased to $31.36 per Bbl in 2009 from $57.15 per Bbl in 2008.

In 2009, our $422.1 million decrease in oil, NGL, and natural gas sales resulted from:

 
Price variances that had a $317.2 million unfavorable impact on sales, of which $179.5 million was attributable to the 43% decrease in average oil prices received, $30.5 million was attributable to the 45% decrease in NGL prices, and $107.2 million was attributable to the 59% decrease in average natural gas prices received; and

 
Volume variances that had a $104.9 million unfavorable impact on sales, with $108.9 million of decreases attributable to the 1.1 million Bbl decrease in oil production volumes, with $1.6 million of decreases attributable to the less than 0.1 million Bbl decrease in NGL production volumes, partially offset by an increase of $5.6 million due to the 0.7 Bcf increase in natural gas production volumes.

Oil and gas sales in 2008 increased by 22%, or $141.0 million, from the level of those revenues for 2007, and our net production volumes in 2008 decreased by 5%, or 0.6 MMBoe, over net production volumes in 2007. Average prices for oil increased to $101.38 per Bbl in 2008 from $71.92 per Bbl in 2007. Average natural gas prices increased to $8.54 per Mcf in 2008 from $6.42 per Mcf in 2007. Average NGL prices increased to $57.15 per Bbl in 2008 from $49.72 per Bbl in 2007.

 
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In 2008, our $141.0 million increase in oil, NGL, and natural gas sales resulted from:

 
Price variances that had a $212.3 million favorable impact on sales, of which $159.7 million was attributable to the 41% increase in average oil prices received, $9.0 million was attributable to the 15% increase in NGL prices, and $43.6 million was attributable to the 33% increase in average natural gas prices received; and
 
Volume variances that had a $71.3 million unfavorable impact on sales, with $116.9 million of decreases attributable to the 1.6 million Bbl decrease in oil production volumes, partially offset by both an increase of $21.7 million due to the 0.4 million Bbl increase in NGL production volumes, and an increase of $23.9 million due to the 3.7 Bcf increase in natural gas production volumes.

The following table provides additional information regarding our quarterly oil and gas sales from continuing operations excluding any effects of our hedging activities:

   
Production Volume
   
Average Price
 
   
Oil
   
NGL
   
Gas
   
Combined
   
Oil
   
NGL
   
Natural Gas
 
   
(MBbl)
   
(MBbl)
   
(Bcf)
   
(MBoe)
   
(Bbl)
   
(Bbl)
   
(Mcf)
 
2007:
                                         
First
    1,773       133       3.8       2,534     $ 57.87     $ 39.90     $ 5.92  
Second
    1,872       134       3.5       2,589     $ 66.20     $ 44.22     $ 7.56  
Third
    1,783       190       4.4       2,702     $ 76.20     $ 48.89     $ 5.68  
Fourth
    1,617       317       5.1       2,792     $ 89.23     $ 56.65     $ 6.62  
Total
    7,045       774       16.8       10,617     $ 71.92     $ 49.72     $ 6.42  
2008:
                                                       
First
    1,420       316       5.0       2,570     $ 99.43     $ 59.80     $ 7.97  
Second
    1,482       290       5.5       2,694     $ 125.20     $ 67.73     $ 10.49  
Third
    1,171       294       5.1       2,319     $ 122.71     $ 70.55     $ 9.70  
Fourth
    1,347       311       4.9       2,466     $ 58.70     $ 32.00     $ 5.68  
Total
    5,420       1,211       20.5       10,049     $ 101.38     $ 57.15     $ 8.54  
2009:
                                                       
First
    1,108       307       5.7       2,366     $ 41.15     $ 22.52     $ 4.19  
Second
    1,026       308       5.5       2,255     $ 55.42     $ 28.26     $ 3.11  
Third
    1,078       279       5.2       2,219     $ 68.15     $ 35.09     $ 2.84  
Fourth
    1,134       289       4.8       2,215     $ 75.09     $ 40.45     $ 3.75  
Total
    4,346       1,183       21.2       9,055     $ 60.07     $ 31.36     $ 3.48  

During 2009, 2008, and 2007, we recognized net gains (losses) of ($1.4) million, $26.1 million, and $0.2 million, respectively, related to our derivative activities.  This activity is recorded in “Price-risk management and other, net” on the accompanying statements of operations.  Had these gains been recognized in the oil and gas sales account, our average oil sales price would have been $59.77, $105.32 and $71.91 for 2009, 2008, and 2007, respectively, and our average natural gas price would have been $3.47, $8.77 and $6.43 for 2009, 2008, and 2007, respectively.

Costs and Expenses. Our expenses in 2009 decreased $798.5 million, or