May 6, 2010. During 2009, our company-wide exploration and development drilling program consisted of two exploratory wells with one completion and 18 development wells with 17 completions, resulting in a success rate of 90% for the total of 20 wells. In 2008, we drilled 126 wells with an 87% success rate. The reduced drilling program in 2009 was in keeping with the company’s intentional reduction of operational expenses during the year.

Of the 20 wells drilled in 2009, 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) and seven wells with five successes were drilled in the Southeast Louisiana core area (Lake Washington Field). Because of our focus on drilling and production in these two areas, we have been the largest operator in the Texas AWP Field for many years and one of the largest crude oil producers in the state of Louisiana since 2005.

Excluding 59 service wells, as of December 31, 2009, we had interests in 1,294 producing wells (1,165.5 net wells). Of these, 569 were producing from the Olmos formation in the AWP Field and 107 were 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—201 in South Texas, 99 in our Southeast Louisiana core area, 65 in South Louisiana, and 37 in Central Louisiana/East Texas.

2009 Wells/PUDs. The two exploratory wells drilled in 2009 were both in the Lake Washington Field with one being successfully completed. The 18 development wells were all located in our Southeast Louisiana and South Texas core areas. The distribution of the development wells is shown in the following table, together with the number of proved undeveloped locations (PUDs) that we have identified for future drilling in all our core areas.

At the end of 2009, we had a total of 413 PUDs identified for future drilling. The PUDs had an estimated total reserves volume of 56.1 MMBoe and a PV-10 value of $557.8 million. Of this total, 8.5 MMBoe having a PV-10 value of $36.1 million was added in 2009.

E&D Approach. Our PUD inventory shows that we began the year 2010 with a large portfolio of proven undeveloped oil and gas reserves that provide us with numerous opportunities for development drilling. As these wells are drilled, the well log data gained from them will provide additional information about the reservoirs and help identify additional PUDs. With this on-going process, we are assured of a relatively low-risk development drilling program over a long period of time.

At the same time, we are constantly seeking both medium-risk and wildcat exploratory prospects and leads in areas we have identified as having possible or probable reserves. Successful exploitative and/or exploratory wells drilled in these areas, together with the development wells that will follow, will expand our operations in the areas.

For our Southeast Louisiana and South Louisiana core areas of operation, our exploratory and development approach is entirely seismic led. For all our fields in the areas, we have high-quality three-dimensional seismic data merged together and integrated with the latest digitized geological data, all of which we leverage with advanced technology in a fairway approach for evaluating reservoir trends and selecting drilling sites. Similar tools are under development for our South Texas area. (See Louisiana Geoscience Databases and South Texas Seismic Datasets.)

In all our drilling operations, in both Louisiana and Texas, we apply newly developed well design, operating, and well control standards and procedures. We also use a Landmark well-planning software platform integrated to geoscience earth models that helps us design directional wells; determine pore pressures, mud densities, and fracture gradients; select casing design and seating; and optimize mud, bit and cementing techniques.

In our completion operations, we are constantly upgrading our techniques, which now include multistage formation-fracturing technologies for horizontal wells. And in our reservoir management, we have an advanced reservoir simulation capability and perform advanced high-resolution petrophysical analyses.

To ensure that the drilling and all other operations within our four core areas are properly executed, we have assigned a multidisciplinary team to each area to follow every aspect of its operation. At year-end 2009, we had operational control of 96% of our proved oil and natural gas reserves, which allows us to more effectively manage production, control operating costs, allocate capital, and time field development. When indicated, we also form alliances with industry-leading companies to better accomplish certain technical goals in some of the core areas.

2009 E&D Activities

With our late 2008 decision to cease all new drilling activities until commodity prices began to recover, our drilling activities during first quarter 2009 consisted solely of finishing the drilling of four wells begun in 2008: two exploration wells in the Lake Washington Field in our Southeast Louisiana core area of operation and one development well each in the Sun TSH Field and the Briscoe Ranch Field in our South Texas core area of operation.

One of the Lake Washington wells, the SL 19338#1 ST1 located on the west side of the field, reached a depth of 16,535 feet with 35 feet of true vertical pay in one zone in the field’s Miocene sands and was placed on production at 3.6 gross MMcf of gas per day with a flowing tubing pressure of approximately 2,150 psi. The other Lake Washington well was deemed uneconomic. Completion of the two South Texas wells, both of which were natural gas wells drilled to the Olmos sand, was delayed.

Essentially all other E&D activities during 2009, including resumed drilling activities, were also focused in the South Texas area (primarily the AWP Field) and the Southeast Louisiana area (primarily the Lake Washington Field).

2009 South Texas E&D Activities. In the South Texas area, first quarter 2009 activities included the completion of a permanent flow line for the R Bracken 33H horizontal well that had been drilled and placed on line in the AWP Field near the end of 2008 at a sustained rate of 6.3 MMcfe per day on a 32/64-inch choke. This well, which was the first horizontal well drilled in the AWP Olmos formation by any company, reached a total measured depth of 14,322 feet that included a horizontal leg of 3,530 feet hydraulically fractured at nine locations (see slide show).

The South Texas horizontal drilling program continued throughout 2009, including wells drilled both to the Olmos sand and to the deeper Eagle Ford formation. Second and third horizontal wells drilled to the Olmos sand, the R Bracken 34-H and 35H wells, were completed in the third quarter in the southern portion of the AWP Field. Following an initial production rate of 5.7 MMcf per day with a flowing tubing pressure of 2,175 psi on a 36/64-inch choke, the Bracken 34H stabilized at 1.8 MMcf per day. The R Bracken 35H well had an initial production rate of 4.6 MMcfe per day with a flowing tubing pressure of 4,200 psi on a 14/64-inch choke, but mechanical difficulties developed after approximately five days. The well was plugged off in the well bore, the well bore was cleaned, and the well was brought back on line slowly at a controlled rate of 2.3 Mcf per day with a flowing tubing pressure of 1,900 psi.

Because of the difficulties encountered with the Bracken 35H, a pilot hole was drilled, cored, and logged for the next well, the R Bracken 36H, in order to enhance our understanding of the depositional environments of the southwest portion of the AWP Field and help us relate petrophysical properties to logs and better predict reserves recoveries. The completion design of the well was also modified to reduce the risk of mechanical issues similar to those encountered in the R Bracken 35H. The R Bracken 36H was placed on production in fourth quarter 2009 with an initial production rate of 11.5 MMcf of gas per day with a flowing casing pressure of 5,300 psi on a 20/64-inch choke and after 30 days was producing 9.9 MMcf of gas per day with a flowing casing pressure of 3,800 psi.

The last horizontal well drilled to the Olmos formation in the AWP Field in 2009 was the AFP 1H well, which also was completed in fourth quarter 2009. The initial production rate of the AFP 1H well was 6.4 MMcf of gas per day and 280 barrels of condensate per day, or 8.1 MMcfe, with a flowing casing pressure of 3,500 psi on a 24/64-inch choke. After 30 days the well’s production rate was 5.3 MMcf of gas per day and 172 barrels of condensate per day, or 6.3 MMcfe per day, with a flowing casing pressure of 2,290 psi.

In August 2009 we reported our intention of testing the Eagle Ford shale formation in the AWP Field and of forming a strategic joint venture with an industry partner to develop our Eagle Ford acreage. We also noted that we had a total of 89,000 net undeveloped Eagle Ford acres in the four fields in South Texas, much of the acreage located below 113,000 net undeveloped Olmos acres in the area.

On November 2, 2009, we announced a joint exploration and development agreement with Petrohawk Energy Corporation to develop and operate approximately 26,000 acres of our Eagle Ford shale acreage in the AWP Field. We retained a 50% interest in the joint venture, which called for Petrohawk to serve as operator during the drilling and completion phase of the joint development and Swift Energy to operate the wells once they enter the production phase. An appraisal program was to begin before the end of 2009 with an acceleration of activity anticipated in 2010. Before year-end 2009 Petrohawk had begun drilling its first joint venture well and we had independently begun drilling two additional wells in the Eagle Ford shale with 100% Swift working interests.

In addition to the horizontal drilling, we instituted two new programs in the AWP Field to optimize production. One consisted of drilling shallow vertical wells targeting oil in the Olmos formation in the northern portion of the field. This program began in third quarter 2009 with the drilling of the Gonzalez #2 well, which reached a depth of 9,510 feet with 25 feet of net pay and initially tested at just over 100 Boe per day. This well was followed by six additional wells in fourth quarter 2009, all at approximately the same depth as the Gonzalez #2 and with similar pay zones. With three wells in the series yet to be placed on production at year-end, this program had already increased the field’s oil production by about 300 gross barrels per day.

In the second AWP program, which also began in third quarter 2009, we applied additional fracture stimulations to existing well bores in the field. We identified over 150 wells in the AWP Field as candidates for this program and by year-end we had performed additional fractures on 29 wells at an average cost of less than $250,000 per well. The average production rate of the wells after the fracturing procedure was 0.543 MMcfe per day, which was 10% higher than the average initial production rates of the same wells when they were first completed.

2009 Southeast Louisiana E&D Activities. In the Southeast Louisiana area, we initiated programs to maximize production from existing wells in the Lake Washington Field and mitigate the effects of natural production declines while no new drilling was occurring. As we reported earlier, we had already begun addressing reservoir pressure issues in the Lake Washington Field during 2008 and had applied for permits from the state of Louisiana to provide additional water injection wells in the Newport reservoir during 2009. However, from a series of multidisciplinary studies of the reservoir, including simulation modeling, it became apparent that the injection program should be delayed until we fully understand the depositional environment of the reservoir. These studies are still on-going.

In first quarter 2009, we initiated a production optimization program in the Lake Washington Field in which we made sliding sleeve changes to access different productive zones in ten wells. These changes, together with gas lift enhancements on four wells, increased the field’s production approximately 1,000 Boe per day at a cost of only $3,000 to $5,000 per well. This program was continued throughout the year, with a total of 29 sliding sleeve changes, nine gas lift modifications, and three acid jobs. In addition, we performed two recompletions.

Late in third quarter 2009, we initiated a program of drilling to shallow Miocene sands in the Lake Washington Field, completing four of five wells drilled by year-end. These wells reached measured depths ranging from 6,023 feet to 7,240 feet and had initial daily average production rates of approximately 350 gross Boe.

Meanwhile, the throughput capacity of Lake Washington’s new Westside production facility, which had been commissioned in the second quarter of 2008, was doubled during first quarter 2009 to 20,000 barrels of oil per day and 40 MMcf of gas per day and production from the older SL 212 facility was redirected to the new facility. Production from the 2008 Shasta discovery well, located between the Lake Washington Field and the Bay de Chene Field, was also directed to this facility when the well was placed on line on April 26. For the month of July, this well, in which we have a 50% working interest, produced at an average daily rate of 4.6 gross MMcf of gas and 331 gross barrels of oil at 9,600 psi on a 14/64-inch choke.

Other production was added in the Southeast Louisiana core area when a 2008 well, the BDC UC#8, was completed and connected to high-pressure gas production lines in the Bay de Chene Field during second quarter 2009. This well, which was drilled to a depth of 14,176 feet in the Miocene sands and encountered 66 feet of true vertical pay in two Miocene sand zones, produced at an average daily rate of 5.3 gross MMcf with a flowing tubing pressure of 1,220 psi during the month of July. While the Bay de Chene infrastructure had been heavily damaged during the 2008 hurricane season and no oil or low-pressure gas was produced from the field until the beginning of fourth quarter 2009, high-pressure gas production from the field continued throughout the year.

The many infrastructure repairs and replacements required in the Bay de Chene Field after the hurricane damage included the replacement of the field’s production facility. This facility, whose structural design copied that of the Lake Washington Westside facility commissioned in 2008, was brought on line on August 28 and oil and low-pressure natural gas production from the field began for the first time during the year.

2009 Activities in Other Core Areas. No specific E&D activities were undertaken in our South Louisiana core area or in our Central Louisiana/East Texas core area during 2009; however, during second quarter 2009 we entered into a joint venture agreement with Anadarko E&P Company LP for development and exploitation in and around our Burr Ferry Field in our Central Louisiana/East Texas area. As fee mineral owner, we leased a 50% working interest in approximately 33,623 gross acres to the joint venture partner. We retained a 50% working interest in the joint venture acreage, as well as its fee mineral royalty rights.

2009 Geoscience Databases. For two of our core areas, our 2009 E&D activities included further work in developing and applying three-dimensional geoscience databases to help us select optimum drilling sites. Prior to 2009, we had developed one geoscience database that covers the fields in the Southeast Louisiana core area and two databases that cover the fields in the South Louisiana core area (see Louisiana Geoscience Databases). We perform several types of analyses on the databases to produce and identify three-dimensional images of subsurface structures with hydrocarbon-bearing characteristics. During 2009, we completed prestack depth migration (PreSDM) analyses with updated salt models for all three databases which together cover a 4000-square-mile area. This seismic processing combined with seismic pore pressure predictions has increased our confidence in planning and drilling of wells that are increasingly deeper and larger.

With an intention of logically extending this geoscience methodology, we began acquiring three-dimensional seismic datasets for our South Texas core area in 2008. No additional datasets were acquired in 2009 (see South Texas Seismic Datasets).

2010 E&D Plans

Our 2010 capital expenditures are currently budgeted at $300 million to $375 million, net of minor non-core dispositions and excluding any property acquisitions. (See update on 2010 capital budget.)

Our capital plans include drilling up to 50 wells and performing well recompletions and fracture enhancements as follows:

First Quarter 2010 E&D Activities

During first quarter 2010 we (1) finished drilling and completed two South Texas horizontal exploration wells in the Eagle Ford shale with 100% working interest, (2) prepared to assume operation of the first South Texas horizontal exploration well that our joint venture partner finished drilling in the Eagle Ford shale with a 50% working interest, and (3) drilled five vertical development wells with two completions, one in South Texas and another in Southeast Louisiana. We also continued several activities designed to boost production. In addition, much of the first quarter was spent optimizing the project management processes we believe are necessary to maximize the value of our assets, particularly in the Eagle Ford and Olmos formations. These processes include batch drilling techniques, large-scale water-handling systems and stronger alliances with our service providers and vendors, all of which should improve our drilling and completion efforts.

First Quarter 2010 South Texas E&D Activities. Our horizontal drilling program in the South Texas Eagle Ford shale begun in fourth quarter 2009 continued in several locations, primarily in the AWP Field in McMullen County but also in the Las Tiendas Field in Webb County. In total, our first-quarter Eagle Ford shale position encompassed 97,670 gross and 79,164 net acres, some of which existed below prospective Olmos acreage that we also held.

During first quarter 2010 we finished drilling and completed two horizontal wells in the Eagle Ford shale, both with 100% Swift working interests. The Fasken EF 1H, our first Eagle Ford shale discovery well, was drilled in the Las Tiendas Field and had an initial production rate of 9.4 MMcf of gas per day with flowing casing pressure of 4,550 psi on a 22/64-inch choke. (In early May it was producing at a curtailed rate of 1 MMcf per day owing to sales line limitations.)

The PCQ 1H, our second Eagle Ford shale discovery well, was drilled in the AWP Field and had an initial production rate of 1,134 barrels of oil per day and 1.1 MMcf of gas per day with a flowing casing pressure of 1,750 psi on a 24/64-inch choke. This well requires that additional facilities be installed before it can be placed on production.

An Eagle Ford shale discovery well drilled by the company’s joint venture partner, Petrohawk, also finished drilling in first quarter 2010 on the 26,000-acre portion of the AWP Field covered by the joint venture. This well, the Bracken JV 1H well, was completed early in the second quarter and had an initial production rate of 9.0 MMcf of gas per day with a flowing casing pressure of 5,815 psi on a 24/64-inch choke. The well was subsequently restricted to 6.4 MMcf per day of gas and a 17/64-inch choke while awaiting the installation of further production facilities. We hold a 50% working interest in the well and will assume its production operations.

We began the second phase of our horizontal drilling program targeting the AWP Olmos sand with the drilling of a sixth well, the Huff 1H well. This well will be completed during the second quarter.

We also continued our two production optimization programs in the AWP Field during first quarter 2010. In the program to drill shallow vertical wells targeting oil in the Olmos sand in the northern portion of the field, we drilled and completed one well, the Henry #1, and placed it on line. In the program of applying additional fracture stimulations to existing vertical well bores, we fracture stimulated six wells, with plans to perform 24 more in 2010.

First Quarter 2010 Southeast Louisiana E&D Activities. A group of four development wells were drilled during first quarter 2010 in the Lake Washington Field as part of the shallow drilling program initiated in third quarter 2009. Of these, one well, the CM #410, was completed. Drilled to a measured depth of 5,388 feet, the well encountered 79 feet of true vertical net pay and averaged approximately 350 gross barrels of oil per day over 30 days. Another well encountered commercial quantities of hydrocarbons but was plugged because of mechanical failure. It was re-drilled early in the second quarter as the CM #411 well with a measured depth of 5,481 feet and logged 334 feet of true vertical net pay.

Also during first quarter 2010, seven Lake Washington wells were recompleted and one gas lift modification and six sliding sleeve changes were performed. Average initial production from these operations was approximately 339 gross Boe per day. We plan to perform six additional recompletions during the current year.

The company’s preventative maintenance program identified a small leak at the bulk separator for Lake Washington’s 6700 production processing facility, which normally handles 2,500 barrels of oil per day. Unplanned repairs required that this unit be out of service for 10 days but eliminated the risk of a larger problem. To increase capacity and service additional gas lift volumes, a new amine treating system, which will double treating capacity to 36 MMcf of gas per day, was installed at the CM3/Caseload facility.

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 the fourth quarter of 2011, we drilled twelve operated development wells and participated in two non-operated wells. In our South Texas core area, eight operated horizontal development wells were drilled to the Eagle Ford shale: three wells in McMullen County, three in Webb County and two in LaSalle County. Three operated development wells were drilled to the Olmos formation in McMullen County. Two non-operated development wells were drilled to the Eagle Ford shale in McMullen County.

In our Central Louisiana/East Texas core area, one operated well targeting the Austin Chalk formation was drilled in the Masters Creek field.

We currently have six operated rigs drilling in our South Texas core area and one operated barge rig drilling in our Southeast Louisiana area.

South Texas Area

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).

Southeast Louisiana Area

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.

Central Louisiana/East Texas Area

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.

2012 Plans

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. Our preliminary plans for 2012 project capital expenditures of $575 to $625 million. These expenditures will be allocated primarily towards drilling and completion activities, 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 the 2012 expenditures are expected to be directed towards drilling oil wells in our Southeast Louisiana core area 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.

South Texas Area. In our South Texas area during the third quarter of 2011, we drilled ten operated horizontal development wells 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. We currently have four operated rigs and one nonoperated rig drilling in our South Texas core area. A fifth contracted rig is undergoing repairs and should return to this area during the quarter.

Also in South Texas during the third quarter, we completed nine operated wells and one nonoperated well: four operated Olmos wells, two operated Eagle Ford wells, and one nonoperated 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.

Initial Production Test Rates of South Texas Horizontal Wells
Completed in Third Quarter 2011

Initial Production Test Rates of South Texas Horizontal Wells
Completed to Date in Fourth Quarter 2011

During the first week of November, we resumed production and sales of natural gas from the Eagle Ford shale in the Fasken field in Webb County, TX. This production had been shut in as a result of a third-party pipeline failure, which was announced on September 29. Intermittent production curtailments are expected in this area as work necessary to ensure the integrity of the system is performed by the operator.

Central Louisiana/East Texas Area. In our Central Louisiana/East Texas core area, one operated well and one non-operated well were drilled, both targeting the Austin Chalk formation in the Burr Ferry field in Vernon Parish, LA.

The GASRS 16-1 well, a non-operated well, was completed in the Austin Chalk and had an initial production rate of 207 barrels of oil per day and 1.3 MMcf of gas per day with flowing casing pressure of 1,250 psi on a 25/64-in. choke. This well, drilled near the southern extent of our joint operating area, encountered fewer natural fractures than the wells drilled farther north. This well is important in understanding the geology in the area, which is essential to future development plans.

The GASRS 20-1, an operated well, finished drilling operations during the third quarter and was completed in the Austin Chalk. A mechanical problem occurred during the initial cleanup of the well that required a workover rig to resolve. A workover rig is currently on this well and work is under way to remedy the issue. This well bore remained in zone for the extent of the 4,254 foot lateral leg and encountered high natural fracture density and strong tubing pressure.

Southeast Louisiana Area. In our Southeast Louisiana core area, recompletion and production optimization work continued during the third quarter in the Lake Washington field. The work included six recompletions, one gas lift modification, one well returned to production, and eight sliding sleeve changes. The combined average initial production response from these operations was approximately 5,000 Boe per day. As a result of these low-cost operations and the impact of two new wells placed on line during the second quarter, Lake Washington’s third-quarter production remained flat compared to its second-quarter production. We will continue to focus on relatively low-risk, low-cost oil activity in this area and also plan to re-commence drilling in the Lake Washington field in the fourth quarter of 2011 and during 2012.

Capital Expenditures. Our capital expenditures in the first nine months of 2011 were $368.8 million, compared to $228.4 million spent in the same period of 2010.  The increase of $140.4 million was mainly due to additional drilling and completion activity in our South Texas core region.  These 2011 expenditures were primarily funded by $288.5 million of cash provided by operating activities and remaining cash proceeds from our stock offering in November 2010.

We currently plan to finance the remainder of our 2011 accrual based capital expenditures with our 2011 cash flow, cash on hand, proceeds from our October 2011 asset divestiture and potential line of credit borrowings.  Our 2011 capital expenditures are currently budgeted at $480 million to $520 million, which is net of disposition activity.  Approximately 80% of our capital budget is targeted for our South Texas core region. The company may enter into joint venture arrangements, pooling agreements for particular prospects, and consider non-strategic property dispositions, in each case to accelerate drilling and development of its assets and diversify its risk profile.

Divestitures. 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.

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; 2011 SECOND QUARTER FORM 10Q; 2011 SECOND QUARTER WEBCAST. During the second quarter of 2011 all of our drilling and completion activities were performed either in the AWP field in our South Texas core area or in the Lake Washington field in the Southeast Louisiana field. While no drilling and completion activities were carried out in our Central Louisiana/East Texas core area (which now includes our former South Louisiana core area), drilling in the Burr Ferry field has begun in the third quarter.

As a result of more efficient operations and a faster than anticipated pace of well completions in our South Texas area, we returned our dedicated frac fleet to its vendor for approximately 50 days during the second quarter.  By the end of the second quarter, when this frac fleet returned to Swift Energy operations, we had a backlog of seven drilled but not yet completed wells.  We do not anticipate releasing this frac fleet again in 2011, and with the current pace of drilling and completion activity in the South Texas area, we expect that 12 or more wells will be fracture stimulated during the third quarter—an average of at least four well completions per month.

Reviewing Swift Energy’s 2011 second-quarter results, CEO Terry Swift commented, “Swift Energy now has four, soon to be five, operated rigs running in South Texas, a dedicated frac fleet and crew, and additional dedicated natural gas processing and transportation coming online by the end of the third quarter.   We expect to grow our [company] 2011 production between 28% to 34% over 2010 levels, and are just beginning to see the benefits of a tightly coordinated project management and development program…….We expect to quickly ramp up our daily production rate once a previously announced pipeline that will provide up to 90 million cubic feet per day of dedicated processing and transportation capacity [for the AWP field] is completed by the end of the third quarter.”

South Texas Area

During the second quarter of 2011 we drilled one operated and two non-operated horizontal development wells to the Eagle Ford shale and six operated horizontal development wells to the Olmos formation in our South Texas core area, all in the AWP field in McMullen County, TX.  We currently have four operated rigs drilling in the South Texas core area.

Also during the second quarter and early in the third quarter we completed a number of horizontal wells in the South Texas area as described in the paragraphs below.  

AWP Olmos Wells (Operated). During the second quarter, we completed two operated horizontal development wells in the Olmos formation in the AWP field. The R Bracken 38H well, drilled during the second quarter, had an initial production rate of 7.5 MMcf of natural gas per day and 578 barrels of natural gas liquids per day, with a flowing casing pressure of 5,475 psi on an 18/64-inch choke.  The SMR 1H Olmos well, also drilled during the second quarter, had an initial production rate of 1.2 MMcf of natural gas per day and 552 barrels of oil per day, with a flowing casing pressure of 2,450 psi on a 20/64-inch choke.

Additional horizontal development wells have been fractured to date in the third quarter, including the following second-quarter AWP Olmos wells: the R Bracken 40H well that had an initial production rate of 6.2 MMcf of natural gas per day, 480 barrels of natural gas liquids per day, and 12 barrels of oil per day, with a flowing casing pressure of 5,800 psi on a 20/64-inch choke; the Siddons 3H well that had an initial production rate of 5.1 MMcf of natural gas per day and 398 barrels of natural gas liquids per day, with a flowing casing pressure of 5,400 psi on a 20/64-inch choke; and the Whitehurst 3H well that had an initial production rate of 608 barrels of oil per day, 1.4 MMcf of natural gas per day, and 106 barrels of natural gas liquids per day, with flowing casing pressure of 2,685 psi on a 20/64-inch choke.

AWP Eagle Ford Well (Operated).  During the second quarter we completed the first-quarter SMR EF 3H development well in the AWP field in the Eagle Ford shale. The well had a lateral length of 4,850 feet and an initial production rate of 1,230 barrels of oil per day, 0.78 MMcf of natural gas per day, and 60 barrels of natural gas liquids per day, with a flowing casing pressure of 1,975 psi on a 18/64-inch choke. 

AWP Eagle Ford Wells (Nonoperated). During the second quarter our joint venture partner completed two horizontal Eagle Ford development wells in the AWP field: the second-quarter Bracken JV 8H well that had an initial production rate of 10.9 MMcf of natural gas per day with a flowing casing pressure of 6,575 psi on a 20/64-inch choke; and the first-quarter Anthony JV 1H well that had an initial production rate of 8.2 MMcf of natural gas per day with a flowing casing pressure of 4,922 psi on a 20/64-inch choke.

Southeast Louisiana Area

During the second quarter of 2011, our Southeast Louisiana drilling and completion activities all occurred in the Lake Washington field. They consisted of the drilling and completion of the CM-420 development well, the completion of the first-quarter LL&E #5 extension well, and a continuation of well recompletion and production optimization activities.

We drilled and completed the CM-420 (“Hershey”) development well during the second quarter on the west side of the Lake Washington field. It reached a measured depth of 9,882 feet and encountered 150 feet of true vertical net pay in five productive horizons.  The initial production rate of this well was 399 barrels of oil per day and 0.12 MMcf of natural gas per day with a flowing tubing pressure of 230 psi on a 40/64-inch choke setting.

We drilled the LL&E #5 extension well during the first quarter in the Jelly Bowl area in the southern portion of the Lake Washington field and completed it in the second quarter. Previously identified as the SL-1464 #8 well (see May 5, 2011, press release),  the LL&E #5 had an initial production rate of 2,294 barrels of oil per day and 1.2 MMcf of natural gas per day with a 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 natural gas per day with a flowing tubing pressure of 1,020 psi on a 32/6-inch choke setting.

Both of these wells have opened up areas where we expect to drill additional wells over the next several years.

Also during the second quarter we recompleted four wells in the Lake Washington field that yielded an average initial production response of 280 gross Boe per day.

In addition, we performed 24 production optimization projects that included sliding sleeve changes, gas lift enhancements and returning shut-in wells to production. These projects had an average initial production response of 126 gross Boe per day.

Central Louisiana/East Texas Area

We had no drilling or completion activity in the Central Louisiana /East Texas core area during the second quarter of 2011; however, we are currently (in the third quarter) drilling one operated well and participating in one non-operated well that are both targeting the Austin Chalk formation in the Burr Ferry field.

Also in the third quarter, we have expanded our original joint operating area in the Burr Ferry field with our partner (Anadarko E&P Co.) from 33,623 gross acres to approximately 73,000 gross acres.  We own a 50% working interest in the joint area and also own approximately 39,000 fee mineral acres in the area.

In addition, we have entered into a second agreement to jointly develop approximately 32,000 gross acres adjacent to the first operating area.  We own a 45% working interest in the second joint area.

Drilling activity currently under way in the first operating area is expected to continue with up to two drilling rigs being active across both areas by the end of 2011.

July 25, 2011: PRESS RELEASE. During the second quarter of 2011 our drilling was focused in McMullen County, Texas, and Plaquemines Parish, Louisiana.

South Texas Core Area

Maintenance projects by a large pipeline operator that currently provides processing and transportation for our natural gas production in McMullen County, Texas, caused a shut-in of our operated production for approximately four days at the end of the second quarter.  Additionally, this same pipeline operator experienced periodic capacity constraints throughout the quarter, also limiting the company’s 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.

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. 

Southeast Louisiana Core Area

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; 2011 FIRST QUARTER 10-Q. During first quarter 2011 we continued to focus on further development of our liquids-rich Olmos sand and Eagle Ford shale properties in our South Texas core area.  With the exception of one deep well drilled to the Miocene sands in the Southeast Louisiana core area, all our drilling and completion activities during the quarter were located in South Texas. In addition, we participated in nonoperated well drilled to the Austin Chalk trend in our Central Louisiana/East Texas core area.

South Texas Core Area

In our South Texas core area, we have begun extending the lateral lengths of our horizontal wells in the area from approximately 4,000 feet to 6,000 feet. As a result of better than expected performance of the dedicated fracturing fleet we have had since fourth quarter 2010, the year-end drilled but not completed well backlog was reduced substantially during the quarter. This allowed us to return the dedicated fracturing fleet to its vendor for a period of approximately 30 days during the quarter.  As we bring our drilling and completion capabilities into balance during the year, we expect to return the fleet to the vendor one more time for approximately four to six weeks.  We have added a smaller, “spudder” rig in the area, and we are evaluating accelerating our drilling pace further by adding a fourth rig capable of drilling horizontal wells. 

Our first quarter 2011 drilling activities in the South Texas area were limited to the AWP field in McMullen County and included wells drilled both to the Olmos tight sand and to the Eagle Ford shale. A total of eight wells were drilled, two of which were nonoperated. Our well completion activities were performed in both the AWP field and the Fasken field in Webb County. A total of nine wells were completed in the fields—three drilled during first quarter 2011 and six wells drilled in 2010.

AWP Olmos Wells (Operated). Two of the newly completed operated wells were the R Bracken 37H and the AFP 5H, which were drilled in the Olmos formation in fourth quarter 2010 and first quarter 2011, respectively. The R Bracken 37H well had an initial production rate of 4.8 MMcf of natural gas, 226 barrels of natural gas liquids, and 8 barrels of oil per day, with flowing casing pressure of 5,525 psi on a 16/64-inch choke after it was completed with a nine-stage fracture stimulation.  The AFP 5H well had an initial production rate of 2.7 MMcf of natural gas and 216 barrels of oil per day, with flowing casing pressure of 3,705 psi on a 20/64-inch choke after it was completed with a 16-stage fracture stimulation. 

AWP Eagle Ford Wells (Operated). A third newly completed operated well was the SMR EF 2H, which was drilled in the Eagle Ford shale in the northern portion of the field during first quarter 2011. It was completed with a 16-stage fracture stimulation and had an initial production rate of 1,080 barrels of oil and 0.6 MMcf of natural gas per day with flowing casing pressure of 2,300 psi on a 18/64-inch choke.  This well was drilled to a lateral length of 5,660 feet and was our first operated extended-lateral completion. A second operated SMR well, the SMR EF 3H, also drilled in first quarter 2011, was completed in the second quarter (April) with a lateral length of 4,850 feet.  The initial production rate of this well was 1,300 barrels of oil and 1.2 MMcf of natural gas with flowing casing pressure of 2,900 psi on a 16/64-inch choke.  As a result of the better-than-modeled performance of these recently drilled SMR Eagle Ford wells in the northern portion of the AWP field, an additional rig may be contracted in 2011 and dedicated to drill Eagle Ford and Olmos oil wells full time in this part of the AWP field. 

AWP Eagle Ford Wells (Nonoperated). Of the three nonoperated wells completed during first quarter 2011, all had been drilled to the Eagle Ford shale by our joint venture partner in late 2010. The Bracken JV 5H and the Bracken JV 6H were completed using a newly designed fracture stimulation technique.  The initial production rate of  the Bracken JV 5H was 7.6 MMcf of natural gas, 437 barrels of natural gas liquids, and 48 barrels of oil per day, with flowing casing pressure of 5,800 psi on a 20/64-inch choke after a 19-stage fracture stimulation.  The initial production of the Bracken JV 6H was 5.1 MMcf of natural gas with flowing casing pressure of 6,520 psi on a 16/64-inch choke after a 16-stage fracture stimulation. 

The third joint venture well was completed by our contracted fracture stimulation fleet.  This well, the Whitehurst JV 1H, had an initial production rate of 8.4 MMcf of natural gas with flowing casing pressure of 6,300 psi on an 18/64-inch choke after a 16-stage fracture stimulation.

AWP Refracturing Program. We also continued our production optimization and refracturing program in the AWP field during first quarter 2011.  This program mitigates base production declines and improves overall project economics.

Fasken Eagle Ford Wells (Operated). During first quarter 2011, we completed two operated horizontal wells in the Eagle Ford shale in the Fasken field in Webb County, both of which had been drilled during fourth quarter 2010. The first well, the Fasken EF 4H, had an initial production rate of 9.3 MMcf of natural gas per day with flowing casing pressure of 4,610 psi on a 20/64-inch choke after a 12-stage fracture stimulation was performed.  The second well, the Fasken EF 5H, had an initial production rate of 10.7 MMcf with flowing casing pressure of 4,600 psi on a 13/64-inch choke after a 13-stage fracture stimulation.  Both of these wells have performed above expectations.

Southeast Louisiana Core Area

During first quarter 2011 we drilled the SL 1464 #8 (Jelly Bowl prospect) in the Lake Washington field to a measured depth of 11,846 feet and encountered 93 feet of true vertical net pay in four productive horizons. This well has been completed and will be connected to production facilities shortly.

We also performed five recompletions in the field with an average initial production response of approximately 480 gross Boe per day. In addition, we carried out 14 optimization projects (sliding sleeve changes, gas lift enhancements, and returning shut-in wells to production) that averaged an initial production response of approximately 224 gross Boe per day.

With no new wells brought on line during the quarter, these low-cost operations led to a 4% sequential increase in the field's daily net production rate from the previous quarter.

Central Louisiana/East Texas Core Area

During first quarter 2011, we participated in a non-operated well targeting the Austin Chalk trend in the Brookeland field in East Texas.  This well is currently producing minimal amounts of hydrocarbons. 

In the Burr Ferry field in Central Louisiana, we are making plans to move an operated rig into the area during the second quarter. We also expect our joint venture partner to begin drilling a third well in the area during the summer months. The first two wells drilled by our joint venture partner continue to perform very well.

(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. Swift Energy announced that in the fourth quarter of 2010, the company drilled 12 operated development wells and participated in two nonoperated development wells.  The company also drilled one operated exploration well and participated in one nonoperated exploration well. 

In our South Texas core area in McMullen County, one operated horizontal development well was drilled to the Eagle Ford shale, and two operated horizontal development wells and one vertical well were drilled to the Olmos sand.  One nonoperated horizontal development well was drilled by a joint venture partner to the Eagle Ford shale.  In Webb County, four operated horizontal development wells were drilled to the Eagle Ford shale.  In LaSalle County, one operated horizontal exploration well was drilled to the Eagle Ford shale. 

In our Southeast Louisiana core area, three development wells were drilled in the Lake Washington Field. Of these, one was completed and two were plugged and abandoned. 

In our Central Louisiana/East Texas core area, one operated and one nonoperated development well were drilled to the Austin Chalk formation in the Brookeland Field in East Texas.  In the Burr Ferry Field in Vernon Parish, LA, one nonoperated exploration well was drilled by a joint venture partner to the Austin Chalk formation.

South Texas Operations. During the fourth quarter and through the date of this release (Feb. 24, 2011), the company fracture stimulated 10 operated wells and one nonoperated well drilled to the Eagle Ford shale formation and seven wells drilled to the Olmos formation, all in South Texas. The initial average production rates for these wells are included in the following table:

Initial Production Test Rates of Horizontal Eagle Ford and Olmos Wells

The test rates in the table above were all consistently measured after the company implemented a specific reservoir management initiative that includes producing all of its horizontal wells in this core area at restricted choke settings.  Initial choke settings are as low as 12/64” and are gradually increased to a setting of up to 20/64” and produced at this level for an extended period of time.  This technique has resulted in higher initial pressure measurements and shallower initial production declines. 

Completion efficiencies realized by a contracted fracture stimulation crew have reduced the company’s current backlog of uncompleted wells to three operated and one nonoperated.  While drilling activity is accelerated to build a sufficient inventory to maintain full utilization of this crew, the crew and equipment have been returned to the service provider (as contractually allowed) for a period of approximately one month.  This will assist Swift Energy in balancing its drilling and completion activity for the rest of the year, while at the same time providing a slight financial benefit to the company.

The company is currently drilling three operated horizontal wells in McMullen County, with two wells targeting the Eagle Ford shale and one well targeting the Olmos tight sand. The company is making plans to contract a shallow drilling rig in this area during the first quarter of 2011.

Southeast Louisiana. In our Southeast Louisiana core area at the Lake Washington Field, we completed one of three wells drilled.  Three recompletions were performed during the quarter resulting in an average production increase of 183 gross barrels of oil equivalent per day per recompletion. 

Alsoduring the quarter at the Lake Washington Field, 12 field optimization projects were carried out resulting in an average production increase of 75 barrels of oil equivalent per day per project.

At Lake Washington, gas lift and amine unit infrastructure upgrades were completed.  These types of projects are important to ensure that facilities at the field level will not be constrained as the company increases development activity and begins a deep exploitation and exploration program.

One operated drilling rig and one recompletion rig are currently active in Lake Washington.

Central Louisiana/East Texas. In our Central Louisiana/East Texas core area, a nonoperated well targeting the Austin Chalk was drilled and completed in the South Burr Ferry Field.  Initial production test rates of this well were 840 Bbls/d and 10.2 MMcf/d of gross production with flowing tubing pressure of 5,700 psi on a 32/64” choke.  This is the second well drilled in this area since the formation of a joint venture.  Swift Energy has a 50% working interest in this well but enjoys a 61.5% net revenue interest due to fee mineral rights it owns. Both wells drilled in this area are producing at restricted rates until facilities and infrastructure can be upgraded.  Activity in this area will resume during the second quarter of 2011.

In the Brookeland Field in East Texas, one operated and one nonoperated well were drilled during the fourth quarter.  The operated Donner Brown A2 well is waiting on facility upgrades before testing can be conducted.  The nonoperated Donner Brown 346 RE is being prepared for production.

One nonoperated rig is currently drilling in the Brookeland Field in East Texas.

February 10, 2011: PRESS RELEASE. Swift Energy announced that its 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. 

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. 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 Horizontal Drilling Program. 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 Horizontal Drilling Program. 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.

Third Quarter 2010 South Texas AWP Production Enhancement Activities. 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 Production Enhancement 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.

The 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 Program. 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.

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. (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 Horizontal Drilling Program. 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 underwent a seven-stage fracture stimulation and had an initial production rate of 336 barrels of oil per day and 0.5 MMcf of natural gas per day with a flowing casing pressure of 920 psi on a 22/64-inch choke.

The San Miguel Ranch 1H was completed with a 12-stage fracture stimulation and had an initial production rate of 775 barrels of oil per day and 1.1 MMcf of natural gas per day with a flowing casing pressure of 2,940 psi on a 16/64-inch choke.

The Discher 1H was completed with a 14-stage fracture stimulation and must await tie-in to sales before flow-back and testing.

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.

In total, our Eagle Ford Shale position now encompasses 100,312 gross and 80,658 net acres prospective in our South Texas region. A portion of this Eagle Ford acreage is below existing Olmos acreage that we also hold.

Second Quarter 2010 South Texas Olmos Sand Horizontal Drilling Program. 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.

The Huff 1H was located in a developed portion of the AWP Field to test field drainage assumptions and the opportunity of drilling infill wells in this field in the future. The Huff 1H underwent an eight-stage fracture stimulation and had an initial production rate of 5.4 MMcf of natural gas per day with a flowing casing pressure of 2,700 psi on a 26/64-inch choke.

The AFP 2H was drilled on undeveloped acreage and has undergone eight stages of a 14-stage fracture stimulation. The AFP 2H had an initial production rate of 6.4 MMcf of natural gas per day and 51 barrels of condensate per day with a flowing casing pressure of 4,450 psi on a 19/64-inch choke. The six stages not stimulated in this well will be pumped at a later date.

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 South Texas AWP Production Enhancement Activities. No new wells were drilled during second quarter 2010 in our production optimization program consisting of drilling shallow vertical oil wells in the Olmos sand in the northern portion of our AWP; however, in anticipation of resuming this program, early in the third quarter we contracted for an additional rig that will be active in this program for the remainder of the year.

Second Quarter 2010 Southeast Louisiana Production Enhancement Activities. 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 was drilled to a measured depth of 5,481 feet and encountered 345 feet of true vertical net pay. This well has averaged approximately 590 gross barrels of oil per day over a period of 30 days.

The SL 212 #178 was drilled to a measured depth of 7,200 feet and encountered 75 feet of true vertical net pay. It has averaged approximately 200 gross barrels of oil per day over a period of 30 days.

The CM 412 was drilled to a measured depth of 8,178 feet and encountered 267 feet of true vertical pay. It was completed early in the third quarter with an initial production rate of 574 gross barrels of oil per day.

In our second production enhancement program in the Lake Washington Field, we recompleted seven 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 Program. During second quarter 2010, the first well was spudded by Anadarko in our joint venture to develop the Austin Chalk trend in the Burr Ferry Field.

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.

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