May 6, 2010. Swift Energy’s oil and gas operations are focused along the U.S. Gulf Coast in the onshore and inland-water areas of Louisiana and Texas. We have four core areas of operation, each consisting of a group of parishes or counties within which we operate producing oil and natural gas fields and maintain a program of development and exploratory drilling. The areas are identified as (1) Southeast Louisiana, (2) South Texas, (3) Central Louisiana/East Texas, and (4) South Louisiana (see map). (Note: During 2011, all properties included in the South Louisiana core area were sold. During 2008, we sold the New Zealand assets we had operated for several years.)

Each of our four core areas has its own multidisciplinary Asset Development Team responsible for managing the fields within the core area, thereby providing the company with profit from the fields' combined production. A core area may be expanded through the discovery of new reserves or through the acquisition of additional reserves in established fields within the area.

Our current core areas of operation have resulted from our long-term strategy of focusing on multiple fields within specific geographical areas that are sufficiently separated to provide a balance of reserves with respect to oil vs. natural gas, developed vs. undeveloped, and short-lived vs. long-lived. By maintaining majority working interests in essentially all of the areas’ fields, we serve as operator of the fields, and by operating the fields within a core area together, we capitalize on economy of scale, minimize costs, and better utilize our technical and operational expertise.

Click here for interactive map of all Swift properties.

Core Areas of Operation

Currently our operational activities are largely focused in our Southeast Louisiana area and South Texas area. Both areas have long-lived reserves that will provide us with production for years into the future.

In Southeast Louisiana, where we have been drilling in inland waters since 2001, we target multilayered Miocene sands at depths varying between 3,000 feet and greater than 20,000 feet. The area contains two fields, the Lake Washington Field and the Bay de Chene Field, each of which surrounds a central submerged salt dome. The area also contains a producing area between the two fields that resulted from a 2008 discovery well (Shasta). All exploration and development in this area is entirely seismic led (see Louisiana Geoscience Databases).

In South Texas, we have focused for over 20 years on the tight Olmos sand at depths of approximately 11,500 feet in the company’s AWP Field and more recently at shallower depths in other South Texas fields acquired in 2007 (the Briscoe, Las Tiendas, and Sun TSH fields). In late 2008, we began a horizontal drilling program in the Olmos sand, and in late 2009 we initiated a second horizontal drilling program in the deeper Eagle Ford shale formation, both programs being largely conducted in the AWP Field. As part of the Eagle Ford shale program, we formed a joint venture with Petrohawk Energy Corporation on an approximately 26,000-acre portion of the field.

In Central Louisiana/East Texas, we target the Austin Chalk Trend and the Wilcox sands, the latter primarily in the area’s South Bearhead Creek Field, which we have operated since 2005. The area’s other three fields, Brookeland, Burr Ferry, and Masters Creek, all of which we have operated since 1998, produce from the Austin Chalk. In mid-2009, we entered into a joint venture agreement with Anadarko E&P Company LP for development and exploitation of a largely undeveloped area in the Burr Ferry Field beginning in 2010.

In South Louisiana, where we conduct both inland-water and land-based drilling, we target reserves in the Miocene sands and several other formations. The area includes five Swift-operated fields (Cote Blanche Island, Jeanerette, Horseshoe Bayou, Bayou Sale, and High Island) and one nonoperated field (Bayou Penchant). Like the Southeast Louisiana area, all exploration and development in these fields is entirely seismic led.

Year-end 2009 Reserves

At year-end 2009, we had operational control of 96% of our reserves base, which was estimated to total 112.9 MMBoe (see Reserves) with a PV-10 value of $1.3 billion. These reserves were 50% proved developed and were comprised of approximately 39% crude oil, 43% natural gas, and 18% NGL. They included 8.3 MMBoe of proved undeveloped reserves added during 2009 based on the results of the horizontal drilling program conducted in the AWP Field during the year.

Of our total year-end reserves, 56% were concentrated in Louisiana, 43% in Texas, and 1% in other states. The quantities held in the four core areas of operation were: 27.7% in Southeast Louisiana (86.1% oil and NGL); 38.5% in South Texas (41.8% oil and NGL); 17.7% in Central Louisiana/East Texas (64.2% oil and NGL); and 15.9% in South Louisiana (41.6% oil and NGL).

At year-end 2009, we projected that our reserves would increase 5% to 10% over 2009 levels. (Note: See revised projection under First Quarter 2009 Activities below.)

2009 Production & Sales

Our 2009 production totaled 9.1 MMBoe, a decrease of 10% from our production of 10.0 MMBoe in 2008 due primarily to reduced drilling activity in 2009 following the plunge in commodity prices in 2008. The contributions to the 2009 production from the core areas of operation were 52.8% from Southeast Louisiana, 30.1% from South Texas, 9.5% from Central Louisiana/East Texas, and 7.2% from South Louisiana. The production volumes were 48% crude oil, 39% natural gas, and 13% natural gas liquids (NGL).

Oil and gas sales decreased 53% in 2009 to $371.7 million from $793.9 in 2008 due to both decreased production and lower unit prices. The average prices we received in 2009 were $60.07 per barrel for oil compared to $101.38 per barrel in 2008; $3.48 per Mcf for natural gas compared to $8.54 per Mcf in 2008; and $31.36 per barrel for natural gas liquids (NGL) compared to $57.15 per barrel in 2008.

2009 Producing Wells

Excluding 59 service wells, as of December 31, 2009, we had interests in 1,294 producing wells (1,165.5 net wells), of which we were operating 1,146. The wells included 569 producing from the Olmos formation in the AWP Field and 107 producing from the Miocene sands in the Lake Washington Field, the two fields providing 18.4% and 39.7% of our 2009 production, respectively. In addition, we had 402 proved undeveloped locations (PUDs) for future drilling, 99 in our Southeast Louisiana core area, 201 in South Texas, 65 in South Louisiana, and 37 in Central Louisiana/East Texas.

2009 Operational Activities

During 2009, we drilled 20 wells with a 90% success rate compared to 126 wells drilled in 2008 with an 87% success rate. The reduced drilling program in 2009 was in keeping with the company’s intentional reduction of operational expenses during 2009. Of the 20 wells drilled, seven wells with five successes were drilled in the Southeast Louisiana core area (Lake Washington Field) and 13 wells with 13 successes were drilled in the South Texas core area (11 in the AWP Field, one in the Briscoe Ranch Field, and one in the Sun TSH Field).

Thirteen of the 2009 wells were drilled in the fourth quarter with a 92% completion rate. In the Lake Washington Field, we completed four of five development wells drilled to measured depths of 6,023 feet to 7,240 feet in a new shallow well drilling program. In the southern portion of our AWP Field we completed the last two wells in a five-well horizontal drilling program in the Olmos sand, and in the northern portion of the field we completed six wells in a shallow vertical well drilling program in the Olmos sand.

Also during fourth quarter 2009, we continued programs to assist in mitigating natural field declines in both Lake Washington and AWP. In a production optimization program in Lake Washington, we did work on 11 wells involving gas lift enhancements, acid stimulations, and sliding sleeve changes to more productive zones, and we also performed recompletions on two wells. In a fracture stimulation program in AWP, we applied additional fracture stimulations to existing vertical well bores in the Olmos sand.

At year-end 2009 we had one operated rig and one nonoperated rig drilling in the South Texas core area and one rig drilling in the Southeast Louisiana core area. We expect to maintain this minimum level of activity throughout 2010. (See statement on increase in drilling rigs.)

2010 Drilling Plans

For the year 2010, our plans include drilling up to 50 wells and continuing to perform well recompletions and fracture enhancements as follows: (1) In the South Texas AWP Field, up to 4 horizontal wells in the Olmos sand, up to 6 horizontal wells in the Eagle Ford shale, up to 9 horizontal wells in the Eagle Ford shale joint venture, and up to 30 fracture enhancements; (2) in other South Texas fields, 6 to 10 horizontal wells in the Eagle Ford shale; (3) in the Southeast Louisiana Lake Washington Field, 10 to 15 wells and up to 10 recompletions; (4) in the Southeast Louisiana Bay de Chene Field, 2 to 5 wells; and (4) in the Central Louisiana/East Texas Masters Creek Field, 1 horizontal well.

Capital expenditures for 2010 are currently budgeted at $300 million to $375 million, net of minor non-core dispositions. (See update on 2010 capital budget.)

First Quarter 2010 Operational Activities

After completing five horizontal development wells in the Olmos sand in the South Texas AWP Field (one in late 2008 and four during 2009), in first quarter 2010 we completed two other South Texas horizontal wells that had been spudded in December 2009 in the deeper Eagle Ford shale formation—the Fasken EF 1H well in the Las Tiendas Field and the PCQ 1H well in the AWP Field.

Also in first quarter 2010, our 50% joint venture partner (Petrohawk) finished drilling the first horizontal well to the Eagle Ford shale on the 26,000-acre portion of the AWP Field covered by the joint venture. This well, the Bracken JV 1H, was completed in April, after which we assumed operation of the well.

Other South Texas first quarter 2010 activity included drilling and completing a shallow vertical development well, the Henry #1, in the AWP Olmos sand and performing refractures on six existing vertical well bores in the field.

In the Southeast Louisiana core area, one of a group of three shallow development wells drilled during first quarter 2010 in the Lake Washington Field, the CM #410, was completed. A fourth shallow first quarter 2010 well was plugged because of mechanical failure and was successfully re-drilled early in the second quarter (in April) as the CM #411 well. In addition, seven Lake Washington wells were recompleted, adding 339 gross Boe/day per well to the field’s production.

Drilling operations are expected to resume in the area’s Bay de Chene Field during second quarter 2010. All facilities were brought on line on August 28, 2009, following new construction and upgrades necessitated by damages caused by Hurricane Gustav. Also, we began making preparations to spud a well in the Bay de Chene Field late in the first quarter or early in the second quarter of this year. Initial drilling will focus on oil development opportunities at depths between 11,000 and 12,000 feet.

Swift’s first quarter 2010 production was 2.04 MMBoe and consisted of 46.2% oil, 14.8% NGL, and 39.0% natural gas. The contributions to the first quarter 2010 production from the core areas of operation were 936 net MBoe from Southeast Louisiana, 790 net MBoe from South Texas, 161 net MBoe from Central Louisiana/East Texas, 153 net MBoe from South Louisiana, and 5 net MBoe from non-core properties.

During first quarter 2010, the company increased its year-end reserves growth guidance to a mean range of 8% to 12%, up from the 5% to 10% predicted at year-end 2009. It also increased its average daily production exit rate guidance from 27,500 Boe per day to 28,000 Boe per day.

This web page may contain "forward-looking statements" as defined in Section 21E of the Securities Exchange Act of 1934, as amended. Any opinions, forecasts, projections, or other statements other than statements of historical fact are forward-looking statements. Although Swift Energy Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Certain risks and uncertainties inherent in the company's business are set forth in the filings of the company with the Securities and Exchange Commission. (See Terms of Use.)

Updates (in reverse chronological order)

May 3, 2012: PRESS RELEASE. In the first quarter of 2012, we drilled 17 operated development wells and completed 16 wells. Of the wells completed, seven had been drilled in fourth-quarter 2011.

South Texas
We drilled 15 wells in our South Texas area in first-quarter 2012: six to the Olmos formation and two to the Eagle Ford formation in the AWP field in McMullen County, two to the Eagle Ford in the Fasken field in Webb County, and five to the Eagle Ford in the Artesia Wells field in La Salle County. We currently have six operated rigs drilling in our South Texas area.

We also completed 12 operated wells and one non-operated well in South Texas during the first quarter, including seven wells that were drilled in fourth-quarter 2011. The completed wells included nine wells in the AWP field: three operated Olmos wells, five operated Eagle Ford wells, and one non-operated Eagle Ford well. They also included three operated Eagle Ford wells in the Fasken field in Webb County and one operated Eagle Ford well in the Artesia Wells field in LaSalle County. (See table of completed wells.)

Southeast Louisiana
In our Southeast Louisiana area we drilled and completed two wells in the Miocene sands in first-quarter 2012, both in the Lake Washington field in Plaquemines Parish. The first well, the CM 419, had impaired production for mechanical reasons and will undergo a workover in the second quarter. The second well, the CM 421, was placed on production. Both wells opened up additional drilling opportunity on the west side of the field's salt dome.

A third well, the CM 422, has been drilled and completed during the second quarter. This well, located in the Northeast portion of the field, sets up additional drilling inventory in this portion of the field.

We currently have one operated barge rig drilling in our Southeast Louisiana area. In addition, the on-going recompletion and production optimization program continues.

Central Louisiana/East Texas Area
In our Central Louisiana/East Texas area, we completed the Exxon Corp #10-1well, which was a fourth-quarter 2011 well drilled to the Austin Chalk in our Masters Creek field in Vernon Parish and Rapides Parish, Louisiana. This well was a successful proof-of-concept well that increases our ability to down space on previously developed acreage units in the area.

In the Burr Ferry field in Vernon Parish, our partner has two drilling rigs operating, both targeting the Austin Chalk. We expect to participate in up to six non-operated wells in this area during 2012.

February 23, 2012: PRESS RELEASE. In our South Texas core area, we completed eleven operated wells and one non-operated well during the fourth quarter: five operated Eagle Ford wells, three operated Olmos wells, and one non-operated Eagle Ford well in the AWP field in McMullen County; two operated Eagle Ford wells in the Fasken field in Webb County; and one operated Eagle Ford well in the Artesia Wells field in LaSalle County (see table).

To date in the first quarter 2012, we have completed the following wells: two operated Eagle Ford wells, one operated Olmos well, and one non-operated Eagle Ford well in the AWP field; two operated Eagle Ford wells in the Fasken field; and one operated Eagle Ford well in the Artesia Wells field (see table).

In our Southeast Louisiana core area, we continued our ongoing recompletion and production optimization program in the Lake Washington field with ten recompletions and six production optimization projects.

Also, late in the fourth quarter, we moved a drilling rig into the Lake Washington field that will drill 5 to 10 wells during 2012. The first well in this program, the CM 419, was drilled early in first quarter 2012, and a second well, the CM 421, is currently being drilled.

In our Central Louisiana/East Texas core area, we drilled one operated well (Exxon Corp. #10-1) to the Austin Chalk formation in the Masters Creek field. This well produced significant volumes of water during a preliminary test and will not be completely cleaned up until it is connected to production facilities now being constructed.

Also in the Central Louisiana/East Texas core area, we completed the GASRS 20-1 well in the Burr Ferry field. Previously disclosed mechanical difficulties experienced during the initial completion and cleanup of the well could not be remedied, which made it impossible for the well to produce commercial quantities of hydrocarbons. Based on drilling results and short lived production performance, this well is a candidate to be sidetracked.

In accordance with its demonstrated long-term strategy, Swift Energy currently plans to balance its 2012 capital expenditures with its 2012 cash flow and cash on hand. Current 2012 spending plans are budgeted at $575 million to $625 million in total capital expenditures. For 2012, Swift Energy is targeting production to increase 14% to 20% and proved reserves to increase 10% to 15%, over respective 2011 levels, with a focus on oil and liquid rich opportunities.

November 15, 2011: PRESS RELEASE. Swift Energy announced preliminary plans for 2012 capital expenditures of $575 to $625 million. These expenditures will be allocated primarily towards drilling and completion activity, with approximately 75%–80% of expected expenditures focused on the company’s liquids rich acreage in the Eagle Ford shale and the Olmos sands in South Texas. The remainder of 2012 expenditures is expected to be directed towards drilling oil wells in Southeast Louisiana and Austin Chalk oil and natural gas development wells in our Central Louisiana/East Texas core area.

Based upon these preliminary spending plans for next year, the Company is targeting production to grow 20%–25% and reserves to grow 15%–20% over 2011 levels.

November 3, 2011: PRESS RELEASE; 2011 THIRD QUARTER 10-Q. In the third quarter of 2011, we drilled eleven operated development wells and participated in one non-operated well. In our South Texas core area, ten operated horizontal development wells were drilled to the Eagle Ford shale: six wells in the AWP field in McMullen County, three in the Fasken field in Webb County and one in the Artesia Wells field in LaSalle County. In our Central Louisiana/East Texas core area, one operated well and one non-operated well were drilled in the Burr Ferry field in Louisiana's Vernon Parish.

Also in the third quarter, we completed nine operated wells and one non-operated well in South Texas. In McMullen County, four operated Olmos wells and two operated Eagle Ford wells were completed. In Webb County, two operated Eagle Ford wells were completed, and in LaSalle County, one operated Eagle Ford well was completed.

We currently have four operated rigs and one non-operated rig drilling in our South Texas core area. A fifth contracted rig is undergoing repairs and should return to this area during the quarter. Additionally, one operated drilling rig is active in our Central Louisiana/East Texas core area.

We produced 2.54 MMBoe during the third quarter of 2011, an increase of 23% over our production of 2.07 MMBoe during the third quarter of 2010.

During the third quarter, we sold our interest in six fields in South Louisiana, two in Texas, and one in Alabama to EnergyQuest II, LLC effective August 1, 2011. The sales price was $48.8 million, net of $4.7 million in purchase price adjustments and the buyer’s assumption of approximately $27.7 million of asset retirement related to these properties. The sale closed in October, with the sales prices subject  to customary post-closing adjustments that are not expected to be material. The fields in Louisiana include Horseshoe Bayou/Bayou Sale, High Island, Bayou Penchant, Jeanerette and Cote Blanche Island. The Texas fields include Bego South and Briscoe Ranch. The Alabama field includes Chunchula.

We will use the net cash proceeds from this transaction (as adjusted for cash flows from effective date through the closing date) to fund a portion of our 2011 capital expenditures.

September 29, 2011: PRESS RELEASE. Failure of a third party operated gathering line earlier this week halted natural gas sales from our Fasken field in Webb County, TX. Gross natural gas sales volumes in the Fasken field were averaging approximately 40 million gross cubic feet per day before the failure occurred, and continued well productivity above initial expectations in this area led us to recently raise our expected well recovery estimates to 10 billion cubic feet per well. While we expect pipeline services to resume in the near future, the estimation of a service restoration date requires that the pipeline operator complete a full review of the damages and determine a specific repair timeline. This incident will result in our third-quarter production being slightly below the low end of our previous guidance of 2.56 – 2.76 million barrels of oil equivalent (MMBoe).

Our third-quarter production will also be negatively impacted by previously announced shut-ins along the Louisiana coast during Tropical Storm Lee, delays in the commissioning of dedicated transportation and processing through a newly constructed third-party pipeline handling natural gas production in McMullen County, TX, and periodic transportation and processing curtailments under existing interruptible natural gas agreements that we have in McMullen County.

Finally, we have obtained the additional planned rig for our South Texas area to drill Olmos and Eagle Ford horizontal wells. However, another rig currently under contract recently experienced a major mechanical problem and is expected to be out of service for much of the rest of the year. This will impact our drilling schedule until planned activity can be resumed or the rig replaced. The impact on our fourth-quarter production of this rig's absence combined with the pipeline service outage in Webb County cannot be fully determined at this time.

September 6, 2011: PRESS RELEASE. Because of the risk of adverse weather conditions caused by Tropical Storm Lee, we implemented standard shut-down procedures in several of our coastal Louisiana properties, including the Lake Washington field in Plaquemines Parish, the Bay de Chene field in Jefferson and Lafourche Parishes, and the Horseshoe Bayou, Bayou Sale, and Cote Blanche Island fields in St. Mary’s Parish.  All nonessential personnel and equipment were evacuated from these fields. 

Field operations necessary to safely bring production levels back to normal levels have begun. Some minor damage has been observed in certain areas but is not expected to impact ongoing operations.  Current 2011 production and operational forecasts will be updated if necessary once the impact of Tropical Storm Lee on Swift Energy’s operations is known.

August 4, 2011: PRESS RELEASE. Refer to individual core areas and individual operational activities pages for updates of Swift's second quarter 2011 performance. (NOTE: As of March 1, 2011, the South Louisiana core area was combined with the Central Louisiana/East Texas core area.)

July 25, 2011: PRESS RELEASE. Maintenance projects by a large pipeline operator that currently provides processing and transportation for our natural gas production in McMullen County caused a shut-in of Swift operated production there for approximately four days at the end of the quarter.  Additionally, this same pipeline operator experienced periodic capacity constraints throughout the quarter that also limited our natural gas production. 

Construction of a pipeline related to a previously announced long-term processing and transportation agreement with a new midstream provider is well underway, and we expect to have up to 90 MMcf of gas per day of firm capacity available to us by the end of the third quarter.  Until then, we expect continued pressure on natural gas sales volumes in McMullen County, limiting the amount of our production which can be sold.  Even as second quarter volumes were (and third quarter production volumes potentially could be) limited by capacity constraints, we still expect 2011 production to grow considerably over 2010 levels and will widen the range of our full-year production forecast by 2% to accommodate the current short-term uncertainties in the pipeline capacity situation in McMullen County.  We now expect production for 2011 to be 10.7 to 11.2 MMBoe, 28% to 34% above 2010 production.

Because we had returned the dedicated frac fleet to the vendor for approximately six weeks in order to balance our drilling and completion schedule, only two operated and two non-operated wells were completed in McMullen County during the second quarter. When the frac fleet was returned at the end of the second quarter, a backlog of seven drilled but not yet completed wells existed.  We do not anticipate releasing this frac fleet again in 2011 and expect to have four to five operated drilling rigs running in South Texas by the end of the year.

In McMullen County, one operated Eagle Ford horizontal well and one operated Olmos horizontal well were completed during the quarter.  The SMR EF 3H was completed in the Eagle Ford and had an initial production rate of 1,230 barrels of oil per day, 0.78 MMcf of gas per day, and 60 barrels of natural gas liquids per day with flowing casing pressure of 1,975 psi on a 18/64-inch choke.  This well was drilled to a lateral length of 4,850 feet.  As a result of the liquids-rich production and strong performance of the wells in this area, an additional drilling rig has been contracted and will drill horizontal Eagle Ford and Olmos wells in this area for the remainder of 2011.

The R Bracken 38H Olmos well had an initial production rate of 7.5 MMcf of gas per day and 578 barrels of natural gas liquids per day, with flowing casing pressure of 5,475 psi on an 18/64-inch choke. 

Also in McMullen County, our joint venture partner completed the Bracken JV 8H and the Anthony JV 1H during the second quarter.  The initial production rate of the Bracken JV 8H was 10.9 MMcf of gas per day with flowing casing pressure of 6,575 psi on a 20/64-inch choke.  The initial production rate of the Anthony JV 1H was 8.2 MMcf of gas per day with flowing casing pressure of 4,922 psi on a 20/64-inch choke. 

In the Lake Washington field in Plaquemines Parish, Louisiana, we completed the LL&E #5 (Jelly Bowl) well.  The initial production rate of this well was 2,294 barrels of oil per day and 1.2 MMcf of natural gas per day with flowing tubing pressure of 1,080 psi on a 26/64-inch choke setting.  The most recent test rate of this well was 799 barrels of oil per day and 2.4 MMcf of gas per day with flowing tubing pressure of 1,020 psi on a 32/64-inch choke setting.
           
A second well located on the west side of the Lake Washington field, the CM #420, was recently drilled to a measured depth of 9,882 feet and encountered 93 feet of true vertical net pay in three productive horizons.  The initial production rate of this well was 399 barrels of oil per day of oil and 0.12 MMcf of natural gas per day with flowing tubing pressure of 230 psi on a 40/64-inch choke setting.

May 5, 2011: PRESS RELEASE. Refer to individual core areas and individual operational activities pages for updates of Swift's first quarter 2011 performance. (NOTE: As of March 1, 2011, the South Louisiana core area was combined with the Central Louisiana/East Texas core area.)

February 24, 2011: PRESS RELEASE. Refer to individual core areas and individual operational activities pages for updates of Swift's fourth quarter 2010 performance.

February 10, 2011: PRESS RELEASE. Swift Energy announced that its year-end estimate of proved reserves as of December 31, 2010, was 132.8 MMBoe, 18% higher than 2009 year-end proved reserves of 112.9 MMBoe. These 2010 proved reserves are 47% crude oil and natural gas liquids, with 45% classified as proved developed.

Swift Energy’s year-end 2010 proved reserves were valued at approximately $1.8 billion of present value discounted at 10% per year (PV-10), compared to a PV-10 value of $1.3 billion for the company’s 2009 year-end proved reserves. Pricing for reserves and PV-10 calculations utilized $78.30 per barrel for crude oil and $4.07 per thousand cubic feet (Mcf) for natural gas at year-end 2010, compared to $59.76 per barrel and $3.78 per Mcf used for reserves valuation at year-end 2009.

Total capital expenditures for 2010 were approximately $421 million, slightly above expected levels as completion efficiencies realized in the fourth quarter of 2010 allowed for increased activity levels in South Texas. In total, 12 operated wells and one joint venture well were fracture stimulated during the fourth quarter in this area.

As previously guided, year-end 2011 reserves volumes are expected to grow 15% to 20% over 2010 levels as a result of increased development drilling activity in the company’s South Texas and Central Louisiana/East Texas core areas.

Swift's fourth quarter 2010 production totaled approximately 2.18 MMBoe, or approximately 23,750 Boe per day, an increase of 5% when compared to the 2.07 MMBoe (~22,500 Boe per day) produced in the third quarter of 2010 and a 1% decrease compared to fourth quarter 2009 production of 2.21 MMBoe. Production has continued to trend upward in 2011, averaging approximately 26,600 Boe per day during the month of January, with increasing production levels anticipated throughout 2011. As previously guided, the company currently expects 2011 full-year production to increase 25% to 30% over 2010 levels.

Commenting on the company's performance, CEO Terry Swift said, "2010 was a tremendously important and productive year for Swift Energy as we appraised and delineated our large acreage positions prospective for liquids rich Eagle Ford shale and Olmos tight sand development. In 2011, we are focused on accelerating our pace of development in South Texas, improving our results through more efficient execution and exploiting other areas of our asset base. Our exposure to liquids rich production growth in South Texas, our oil production in South Louisiana, our growing leasehold acreage in the Austin Chalk and our deep exploration prospect inventory along the Gulf Coast together provide a uniquely positioned resource portfolio for investors to evaluate."

November 10, 2010: PRESS RELEASE. Swift Energy announced a preliminary 2011 capital budget of $430 million to $450 million to cover an accelerated drilling program with a production growth goal of 25% to 30% and a reserves growth goal of 15% to 20%. Approximately 75% to 80% of the capital budget will be spent in our South Texas core area, much of it on drilling oil and condensate development wells on acreage proved up in 2010 in the Eagle Ford shale and Olmos sands. The remainder will be directed towards oil production in our Southeast Louisiana core area and high-rate Austin Chalk oil and natural gas development wells in our Central Louisiana/East Texas core area. This program will be partially funded by proceeds from a public offering of 3 million shares of the company’s common stock also announced on November 10. (Note: See additional press releases on November 10, November 11, and November 30, 2010, regarding common stock offering.)

November 4, 2010: PRESS RELEASE; 2010 THIRD QUARTER 10-Q. During the third quarter of 2010, we drilled a total of 21 wells. Of these, 16 wells were in our South Texas core area and included six horizontal wells drilled to the Eagle Ford shale, five horizontal wells drilled to the Olmos sand, and five vertical wells drilled to the Olmos sand. Four wells were drilled in our Southeast Louisiana core area, and one well was drilled in our Central Louisiana/East Texas core area. One horizontal Olmos well in South Texas and one well in Southeast Louisiana were unsuccessful.

Unexpected and uncontrollable delays in obtaining well fracturing services in South Texas during the third quarter resulted in 12 horizontal wells not being fracture stimulated before the end of the quarter. Beginning in the fourth quarter, we began receiving dedicated fracturing services from our exclusive 24-month contract with a large oil field service company (announced in the second quarter), and in October our fracturing performance increased from one per month during the third quarter to four per month in October. Even so, with the backlog of wells awaiting completions, we expect to have a number of wells still awaiting stimulation at year end, which will result in a lower full-year production volume and a lower year-end exit production rate than previously expected.

Third Quarter 2010 South Texas Eagle Ford Shale Activities. The six horizontal wells drilled in the Eagle Ford shale during the third quarter consisted of five development wells located in the AWP Field in McMullen County and one exploratory well in the Sun TSH (Tri Bar) Field in LaSalle County.

Three of the Eagle Ford development wells were drilled by the company: the Quintanilla Me-You 1-H, the PCQ 2-H, and the PCQ 3-H. Following a 12-stage fracture stimulation performed on the Quintanilla Me-You 1-H, the well’s initial production rate was 494 barrels of oil per day and 1.3 MMcf of gas per day, with a flowing casing pressure of 2,100 psi on an 18/64-inch choke. The PCQ 2-H and PCQ 3-H wells are awaiting completion operations.

Two of the Eagle Ford development wells were drilled by our joint venture partner: the Whitehurst JV 1-H and the Bracken JV 6-H. Both wells are awaiting completion operations.

The Eagle Ford exploratory well was drilled by the company and was identified as the Carden 1-H. It underwent a 14-stage fracture stimulation and is in the process of flowing back and being brought on line.

Two horizontal Eagle Ford wells drilled in the AWP Field by the company in the second quarter were completed in the third quarter: the Discher 1-H and PCQ 4-H. A 14-stage fracture stimulation was performed on the Discher 1-H, and the well’s initial production rate was 448 barrels of oil per day and 1.6 MMcf of gas per day with a flowing casing pressure of 3,275 psi on a 12/64-inch choke. A 13-stage fracture stimulation was performed on the PCQ 4-H, and the well’s initial production rate was 528 barrels of oil per day and 1.9 MMcf of gas per day with a flowing casing pressure of 4,903 psi on a 14/64-inch choke.

One horizontal well drilled by our joint venture partner in the AWP Field in the second quarter, the Bracken JV 3-H, was also completed in the third quarter. A 10-stage fracture was performed on this well, and its initial production rate was 5.8 MMcf of gas per day with a flowing casing pressure of 5,753 psi on a 16/64-inch choke. Another second-quarter well drilled by our joint venture partner, the Bracken JV 2-H, is currently undergoing stimulation.

Third Quarter 2010 South Texas Olmos Sand Activities. Of the five horizontal development wells drilled to the Olmos sand during the third quarter, all were drilled by the company in the AWP Field and four were successful. The fifth well encountered mechanical difficulties and was completed as a water source well.

The four successful Olmos horizontal wells were the AFP 3-H, the SBR 1-H, the AAFP 4-H, and the Whitehurst 1-H, all of which are awaiting fracture stimulation.

The five vertical wells drilled to the Olmos sand during third quarter 2010 represented a continuation of our production optimization program consisting of shallow vertical oil wells in the northern portion of our AWP Field. At the end of the third quarter, three of the wells were completed and waiting to be put on production. The initial production rate of the most recently completed well, the SMR 7, was 318 barrels of oil per day and 0.8 MMcf of gas per day with a flowing tubing pressure of 1,900 psi on a 12/64-inch choke. This 2010 vertical drilling program was concluded with a sixth well drilled early in the fourth quarter.

Third Quarter 2010 Southeast Louisiana Activities. We completed three of four development wells we drilled in the Lake Washington Field during third quarter 2010 as part of our one-rig shallow drilling program to enhance the field’s production.

The CM 413 was drilled to a measured depth of 2,922 feet and encountered 48 feet of true vertical net pay. This well has averaged approximately 270 gross barrels of oil per day over a period of 30 days.

TThe SL 17266 #25 was drilled to a measured depth of 5,037 feet and encountered 246 feet of true vertical net pay. It has averaged approximately 100 gross barrels of oil per day over a period of 30 days.

The CM 414 was drilled to a measured depth of 1,622 feet and encountered 90 feet of true vertical pay. This well was recently completed and will be tested following a facility upgrade.

In our second production enhancement program in the Lake Washington Field, we executed six sliding sleeve changes that resulted in an average production increase of 277 gross Boe per day per operation.

Third Quarter 2010 Central Louisiana/East Texas Activities. During third quarter 2010, our joint venture partner Anadarko drilled and completed an exploratory well in the Austin Chalk trend in the Burr Ferry Field, in which we have a 50% working interest. Gross initial production rates of the well were 13 MMcf per day and 1,000 barrels of oil per day. This well will produce to sales upon completion of a saltwater disposal well. A second well in the field is under way.

Third Quarter 2010 Production and Year-end Projections. Our third quarter 2010 production was 2.07 MMBoe (approximately 22,500 Boe per day), a decrease of 7% when compared to our third quarter 2009 production of 2.22 MMBoe.

This third quarter 2010 production represented an increase of 2% from our second quarter 2010 production of 2.03 MMBoe (approximately 22,300 Boe per day). The increase resulted from increased activity levels in our South Texas core area, but was less than had been anticipated because of delays in scheduling fracture stimulation services (see discussion above). These delays have led us to reduce our forecasted year-end 2010 corporate daily production rate to 26,000 to 28,000 net Boe per day (from an earlier projection of 28,000 to 30,000 net Boe per day). This reduced production rate corresponds to a 15% to 24% increase from our third quarter 2010 average daily production rate.

The overall impact of the scheduling delays will be a delay of approximately 525,000 Boe of production until 2011. As a result, we have reduced the projection for our full year 2010 production to 8.30 to 8.50 MMBoe (from an earlier projection of 8.85 to 9.15 MMBoe). This new projection includes a 2% to 9% sequential increase in our fourth quarter 2010 production over our third quarter 2010 production levels.

Our third quarter 2010 production consisted of 48.5% oil, 12.4% NLG, and 39.1% natural gas. Our emphasis on liquids production (oil and NGL made up 60.9% of our total third quarter production) continues to allow us to benefit from the better margins for liquids than for natural gas.

The contributions to the third quarter 2010 production from the core areas of operation were 934 net MBoe (45.1%) from Southeast Louisiana, 796 net MBoe (38.4%) from South Texas, 192 net MBoe (9.3%) from Central Louisiana/East Texas, 145 net MBoe (7.0%) from South Louisiana, and 5 net MBoe (0.2%) from non-core properties.

The company realized an aggregate average price of $51.06 per Boe during third quarter 2010, an increase of 16% from the $44.14 per Boe average price received in the third quarter 2010: average crude oil prices increased 12% to $76.39 per barrel from $68.15 per barrel; average natural gas prices increased 36% to $3.87 per Mcf from $2.84 per Mcf; and average prices for natural gas liquids increased 14% to $39.88 per barrel from $35.09 per barrel.

Third Quarter 2010 Reserves Projections. Our estimate of an increase in reserves at year-end 2010 remains at 15% to 20% above the 2009 year-end level of 112.9 MMBoe (677.4 Bcfe).

Third Quarter 2010 Marketing Activities. During third quarter 2010, our net oil and gas production volume of 2,072 MBoe consisted of 1,005 MBbl of oil, 256 MBbl of natural gas liquids (NGL), and 4.87 Bcf of natural gas. This volume was lower than our third quarter 2009 volume by 147 MBoe, or 7%.

Our total third quarter 2010 sales were $105.8 million, an increase of 8%, or $7.9 million, from our sales in third quarter 2009. The company realized an aggregate average price of $51.06 per Boe during third quarter 2010, an increase of 16% from the $44.14 per Boe received in third quarter 2009 and a decrease of 1% from the $51.80 per Boe received in second quarter 2010. Average crude oil prices increased 12% to $76.39 per barrel from $68.15 per barrel in third quarter 2009; average natural gas prices increased 36% to $3.87 per Mcf from $2.84 per Mcf in third quarter 2009; and natural gas liquids (NGL) increased 14% to $39.88 per barrel from $35.09 per barrel in third quarter 2009.

During the third quarter 2010, we recorded a net loss of $0.2 million related to our derivative activities. Had this loss been recognized in the oil and gas sales account, our average oil price in third quarter 2010 would have been $76.44 per barrel and our average natural gas price would have been $3.81 per Mcf.

Third Quarter 2010 Financing Activities. For the first nine months of 2010, our net cash provided by operating activities from continuing operations was $193.7 million, representing a 33% increase as compared to $146.2 million generated during the first nine months of 2009. This increase in 2010 was primarily due to an increase of $63.7 million in oil and gas sales.

Our capital expenditures on an accrual basis were $270.6 million in the first nine months of 2010, which was an increase from $95.1 million spent on an accrual basis in the 2009 period. The increase in the 2010 period was mainly due to additional drilling activity in our South Texas region. These 2010 expenditures were primarily funded by the $193.7 million of cash provided by operating activities from continuing operations, the use of cash on hand, the use of $12.5 million in carried interests from our Eagle Ford joint venture operations, and $5.0 million of cash provided from our discontinued operations.

We currently plan to fund our 2010 capital expenditures with our 2010 cash flow, cash on hand, and availability under our credit facility. Our 2010 capital expenditures are currently budgeted at $370 million to $390 million, net of minor non-core dispositions. These expenditures are expected to include: South Texas activities that include a continuation of our horizontal well drilling programs in both the Olmos sands and the Eagle Ford shale formation, as well as the fracture enhancement and artificial lift programs; Southeast Louisiana activities that consist of a focus on recompletions and facility optimization; and Central Louisiana/East Texas activities that include placing one non-operated well on line and completing another non-operated well in November and completing both an operated and a non-operated well in December.

We had no borrowings under our bank credit facility at September 30, 2010.

September 23, 2010: PRESS RELEASE. Swift Energy has entered into a long-term agreement for natural gas gathering and treating services in South Texas with Meritage Midstream Services’ subsidiary, Eagle Ford Escondido Gathering. This agreement will involve the construction of a new pipeline to our Fasken operating area (Las Tiendas Field) in Webb County, TX.  We will have up to 40 million cubic feet of gas per day of firm capacity on this new pipeline, which is expected to be completed by December 1, 2010.

We have also agreed to a long-term sales contract with Kinder Morgan Texas Pipeline LLC that is indexed to market and will be delivered to a new connection with the Kinder Morgan system.

In addition, we have extended contracts for two horizontal rigs currently drilling for us by 12 and 15 months from their current terms due to expire in December 31, 2010.  With these contracts in place, we will enter 2011 with three South Texas horizontal drilling rigs under long term contracts. 

As stated by Swift's CEO Terry Swift, “These separate agreements for dedicated gathering and drilling services further reduce Swift Energy’s exposure to the continuing tightness of oilfield services and gathering outlets facing operators in South Texas.  We expect an increase in operating activity in 2011 and have taken numerous steps to ensure that we can drill, complete and produce our wells without interruption due to third party service constraints.”

August 5, 2010: PRESS RELEASE; 2010 SECOND QUARTER 10-Q. During the second quarter of 2010, we drilled nine successful operated wells and participated in two successful non-operated joint venture wells. The operated wells consisted of six horizontal wells drilled in our South Texas core area (four to the Eagle Ford shale formation and two to the Olmos sand) and three shallow vertical wells drilled in our Southeast Louisiana core area. The non-operated wells consisted of two horizontal wells drilled to the Eagle Ford shale in South Texas by Petrohawk, our joint venture partner for the development of the Eagle Ford shale in a 26,000-acre region in our AWP Field.

We currently have five operated rigs and one non-operated rig drilling in our South Texas core area and one operated rig drilling in our Southeast Louisiana core area. (We also have one non-operated rig in our Central Louisiana/East Texas core area that is drilling the first well in our joint venture with Anadarko in the Burr Ferry Field.)

According to CEO Terry Swift, “The addition of two drilling rigs…in South Texas will result in increased activity targeted towards growing oil and natural gas liquids production.” Explaining the continued focus on oil and NGL, he said, “Gas versus oil volume equivalence is reported using a 6 to 1 ratio. Current market pricing comparisons, however, reflect a 17 to 1 ratio. Our higher liquid yield areas provide slightly lower equivalent production rates compared with our dry gas activities, but better relative economic results.”

Swift also pointed out that increased industry activity in South Texas has caused a shortage of critical services, particularly delays in fracture stimulation services that push back completion schedules. To alleviate this problem, the company has executed an exclusive 24-month contract for fracture stimulation services with a large oil field service company. “By committing to this strategic contract,” Swift says, “we expect to complete three to four wells per month beginning in the fourth quarter and significantly reduce our per well completion costs.”

Second Quarter 2010 South Texas Eagle Ford Shale Activities. The four operated horizontal wells we drilled to the Eagle Ford shale in second quarter 2010, all in the AWP Field, were the Hayes 1H, the San Miguel Ranch 1H, the Discher 1H, and the PCQ 4H. The Hayes 1H and the San Miguel Ranch 1H have both been placed on production; the Discher 1H is awaiting tie-in to sales; and the PCQ 4H is awaiting completion.

The two non-operated horizontal wells drilled by our joint venture partner to the Eagle Ford shale, also in the AWP Field, were the Bracken Family 2H and 3H. Both wells are awaiting fracture stimulation.

We now have five horizontal Eagle Ford wells on production (four operated and one non-operated) that have had average initial production rates of 1,152 Boe per day (or 6.9 MMcfe per day), with approximately 40% of the initial production volumes being oil.

Second Quarter 2010 South Texas Olmos Sand Activities. The two operated horizontal wells we drilled to the Olmos sand in the AWP Field during second quarter 2010 were the Huff 1H and the AFP 2H. Both wells have been placed on production.

We now have seven horizontal Olmos wells (all operated) on production that have had average initial production rates of 1,248 Boe per day (or 7.5 MMcfe per day), with approximately 35% of the initial production volumes being liquids, mostly NGL.

Second Quarter 2010 Southeast Louisiana Activities. In our Southeast Louisiana area, we drilled three development wells in the Lake Washington Field during second quarter 2010 as part of our one-rig shallow drilling program to enhance the field’s production. The CM 411, drilled to a measured depth of 5,481 feet, and the SL 212 #178, drilled to a measured depth of 7,200 feet, have both been placed on production. The CM 412, drilled to a measured depth of 8,178 feet, was completed early in the third quarter.

In our second production enhancement program in the Lake Washington Field, we recompleted seven Lake Washington wells with average initial production rates of 244 gross Boe per day. In addition, four sliding sleeve changes yielded an average production increase of 324 barrels of oil per day per well. And one gas lift redesign was performed that increased the well’s performance from 98 to 315 barrels of oil per day.

Second Quarter 2010 Central Louisiana/East Texas Activities. In our Central Louisiana/East Texas area, the first well was spudded by Anadarko in our joint venture to develop the Austin Chalk trend in the Burr Ferry Field.

Second Quarter 2010 Production. Our second quarter 2010 production was 2.03 MMBoe and consisted of 48.3% oil, 13.8% NGL, and 37.9% natural gas. The contributions to the second quarter 2010 production from the core areas of operation were 944 net MBoe (46.5%) from Southeast Louisiana, 732 net MBoe (36.1%) from South Texas, 175 net MBoe (8.6%) from Central Louisiana/East Texas, 171 net MBoe (8.4%) from South Louisiana, and 6 net MBoe (0.3%) from non-core properties.

Second Quarter 2010 Reserves Guidance. During second quarter 2010, we increased our year-end reserves growth guidance to 15% to 20% higher than the 112.9 MMBoe reported at year-end 2009. Our previous guidance had predicted an 8% to 12% increase.

2010 Capital Budget. Our 2010 capital expenditures, previously projected at $300 million to $375 million, are currently budgeted at $360 million to $375 million, net of minor non-core dispositions.

May 27, 2010: PRESS RELEASE. Swift Energy’s Lake Washington Field located in Plaquemines Parish, Louisiana, has not been impacted by the Deepwater Horizon oil spill in the Gulf of Mexico, although there have been isolated reports of oil sheens along the Louisiana coast in close proximity to the company’s operations. “Our organization’s focus is first and foremost on Health, Safety and the Environment,” commented Terry Swift, CEO and Chairman of Swift Energy, “We have taken precautionary measures to protect our assets, the environment we operate in and the safety of our employees and contractors who work in southeast Louisiana. Swift Energy, through its crisis management plan and in communication with other operators and authorities monitoring the spill, will take appropriate measures to protect our people, assets and the environment as conditions require.”

The Company currently has one drilling rig and one completion rig operating in Lake Washington and maintains an inventory of projects to continue its 2010 operational plan.

For additional information, please see the latest Form 10-K and Form 10-Q.