Letter to Stockholders

Management expert Peter Drucker once defined innovation as “the act that endows resources with a new capacity to create wealth.” As an independent oil and gas company, we have always focused on turning natural resources into value for our stakeholders, and we have long realized that sustained value creation requires constant innovation and improvement. Our vision is to be a premier oil and gas company and a top-tier performer, continually innovating and improving in every aspect of our operations.

Innovation is: "the act that endows resources with a new capacity to create wealth."                                                  –Peter Drucker

Perhaps at no time during our company’s history has the importance of innovation been more evident than during 2010. It was a year of transition for the entire oil and gas industry, and it was also a year of transition for us. In both cases the transition was driven by technology. Innovations in horizontal drilling and completion techniques have turned previously unproductive resources into vast new supplies of energy for the nation. Tight sands and shales that were uneconomical to produce a mere decade ago now represent prolific opportunities for future growth.

Innovation has created a whole new subsurface geography of potential resources that need to be explored, delineated, optimized, and produced, and the companies that succeed in this new environment will be those that prove most effective at turning those resources into value. As the theme of this year’s report implies, we think that we have assembled an extraordinary portfolio of diversified properties that provides us with tremendous opportunities for the future. Swift Energy has always been resourceful, but never so “Resource Full.”

We also have an accomplished technical staff that makes the most of the opportunities we have in hand. Our engineering and geoscience experts continually calibrate and recalibrate our methods and procedures, making them as economical and productive as possible. Value creation at Swift has become a comprehensive assembly-line process that starts with our investors, vendors, and suppliers and ends with the production and sale of our products. This process has enabled us to control rising costs, maximize operating efficiencies, apply world-class technologies, optimize well performance and, ultimately, enhance our margins.

In 2010, with this systematic approach to value creation, we increased proved reserves by 18% to 133 million barrels of oil equivalent (MMBoe), almost half of which (47%) was oil and natural gas liquids. We increased our revenues by 18% to $438 million, as we produced a total of 8.3 MMBoe of oil and gas, 61% of which was oil and natural gas liquids. We earned net income of $46 million, with cash flows from continuing operations of $259 million, and we ended the year with no funds drawn under our line of credit, as well as with $86 million of cash on hand.

The response of investors has been clear: Our stock price rose 63% from year-end 2009 to year-end 2010, closing at $39.15 per share. That was after a 43% gain the previous year. Likewise, our market capitalization increased more than 80% to $1.6 billion at year-end 2010, following a rise of more than 70% in market capitalization the year before.

Of all of our gains in 2010, what excited us most were the measurable improvements made in the field as we used our systematic approach to redefine existing core areas and to initiate a new resource play in South Texas. Major operations in this resource play – the Eagle Ford shale – were up and running within 12 months. We completed our first Eagle Ford well in the first quarter of 2010, and by year-end the Eagle Ford shale accounted for 20% of our proved reserves and 5% of our annual production.

Throughout South Texas, we reduced drilling time for our horizontal wells from around 35 days to less than 25 days, and we increased our number of multistage hydraulic fracture stimulations from an average of about one well per month to four wells per month by year-end. We reduced costs and cut the time required on nearly all phases of drilling and completion: by eliminating intermediate casing in some wells, for example, we shaved four days off drilling time and saved $500,000 per well. We established contractual relationships with service suppliers and equipment vendors on everything from pipe and diesel fuel to drilling rigs and hydraulic fracturing services, further reducing costs compared to spot market prices and also helping eliminate supply constraints. Our outstanding safety record measurably improved even as we increased our average daily production rate by almost a third during the 12 months ending in February 2011.

In our South Texas core area, a dedicated hydraulic fracturing crew works on a 17-stage completion of a well with a 6,000-foot horizontal leg.

Our achievements in South Texas are examples of how we can create value in all of our oil and gas properties using our assembly-line process. This manufacturing-style approach to the oil and gas business, as we’ve designed it, has four major stages. The first stage evaluates whether there is an opportunity worth pursuing. The second stage appraises the prospect, establishing its overall scope and quality. The third stage optimizes our operations, from drilling and production to marketing and sales, incorporating the lessons learned from the previous stages. The final stage is our manufacturing mode, in which we capture economic efficiencies by scaling up our activities. In each of these stages, we examine all aspects of our work: modeling the subsurface, drilling wells, completing wells and producing oil and gas, and developing infrastructure and marketing the commodities. As we move from one stage to the next in all of these areas, we calibrate and recalibrate our results against benchmarks, in keeping with our company value of continuous improvement. As we have demonstrated in South Texas, which is now in the third stage of this process, our focus on improvement simultaneously enhances performance and cuts costs.

In 2011 and beyond, we will increasingly apply our process to all our core areas. We have a richly diverse portfolio of core properties that offers a robust mix of resources with multiyear potential. The core area strategy we have pursued for many years makes our manufacturing approach possible by providing us with concentrated resources and operational control within large contiguous acreage positions where repeatable operations can lead to consistently improving performance from lessons learned. This core area strategy also will serve as a template as we enter into new areas in years to come.

Our current portfolio includes both low-risk development and high-upside exploratory prospects in our South Texas, Southeast Louisiana, and Central Louisiana/East Texas core areas. For 2011, we are targeting an annual increase in production volumes of 25% to 30% and reserves growth of 15% to 20% as we explore and develop these core areas with an estimated capital budget of $430 million to $480 million, net of dispositions of non-strategic assets.

In our Southeast Louisiana core area, wells are drilled and completed in shallow inland waters with barge-based rigs.

We plan to allocate about 80% of our 2011 capital budget to our horizontal drilling programs in South Texas. We have been operating in the AWP field in South Texas for more than two decades drilling, hundreds of vertical wells to the tight Olmos sand. In late 2008 we drilled our first horizontal well in the Olmos and converted to a largely horizontal drilling program in 2009. We completed nine horizontal wells and five vertical wells in the Olmos sand in 2010. We also initiated a horizontal program in 2010 to the Eagle Ford shale below the Olmos. This drilling program, conducted in our AWP, Artesia Wells, and Fasken fields, included 22 Eagle Ford wells with some awaiting completion in 2011.

Our properties in South Texas now include approximately 119,000 net acres prospective for the Eagle Ford shale and the Olmos tight sand. Most of this acreage is located in the AWP field, with some of the Eagle Ford and Olmos acreage overlapping at different depths. About 20% of this acreage is primarily oil; another 17% is primarily oil and natural gas liquids; another 34% contains a significant amount of natural gas liquids; and about 29% is dry natural gas. This is a good mix of properties that provides us with outstanding growth potential, along with the flexibility to react to volatility in crude oil and natural gas pricing going forward.

Our investments in South Texas also include a seismic database with about 800 square miles of three-dimensional data merged together from 13 surveys. This database will aid in the drilling of the more than 30 horizontal wells planned for our Eagle Ford and Olmos acreage during 2011, as well as for future wells in our multiyear development schedule. As we grow our South Texas production, we will continue to recalibrate, optimize, and improve our drilling and completion techniques. One design change we are implementing this year, for example, is extending the length of the lateral legs of these wells from 4,000 feet to 6,000 feet, which will aid us in optimizing performance and reducing costs. We anticipate that this combination of improved techniques and higher economies of scale will help us capture additional efficiencies in the months and years to come.

As shale resources in South Texas became a hotbed of industry activity in 2010, we devoted much effort to further building relationships and establishing contractual agreements with service providers and equipment vendors that will enable us to minimize rising costs and head off supply constraints. Some highlights of our results included three contracts for drilling rigs covering 12 to 18 months, a two-year contract for dedicated hydraulic fracturing services, alliances with suppliers of drilling pipe and diesel fuel, a one-year contract for coiled-tubing services, agreements for water management, and agreements for natural gas processing, transportation, and marketing. Forming these relationships was a part of our manufacturing style, which focuses on fine tuning and optimizing all aspects of value creation.

Swith Energy's Core Operating Areas as of March 1, 2011.

We are confident that in our Southeast Louisiana core area, where our reserves are 85% oil and natural gas liquids, we will also benefit from the rigorous, assembly-line approach to innovation that we have been perfecting in South Texas. Like South Texas, our Southeast Louisiana properties have multiyear potential, including some high-impact deep exploration prospects that, if successful, could lead to significant reserves and production increases in future years.

Our Southeast Louisiana core area includes the Lake Washington and Bay de Chene fields, which produce oil and gas from multiple layers of Miocene sands that radiate outward from salt domes. We have a 4,000-square-mile proprietary geoscience database in Louisiana that includes this core area and aids us in positioning wells in these fields. This seismic database was also instrumental in locating our 2008 Shasta discovery between Lake Washington and Bay de Chene.

Our Lake Washington field in particular is an exceptional example of how our staff’s resourcefulness makes us “resource full.” When we acquired the field in 2001 for $30.5 million, it had been in operation since the 1930s and was considered a mature field. After assembling and analyzing our geoscience database, applying innovative completion techniques to optimize production, and drilling new wells, our staff improved the field’s performance dramatically. Lake Washington had 7.7 MMBoe of booked proved reserves when we took over. We have since produced more than 45 MMBoe from the field, and we still had 17.7 MMBoe of proved reserves remaining at the end of 2010.

During 2010, we applied a three-pronged approach to economically reduce natural production declines in our Southeast Louisiana core area. We implemented more than 40 production optimization projects designed to boost production from existing wells at a cost of 50 cents per Boe. We recompleted 20 existing wells to tap into new zones at a cost of $10 per Boe. And we completed nine development wells at a cost of $14 per Boe. As a result of these efforts, production from our Southeast Louisiana core area has remained relatively flat for the past five months (October 2010 through February 2011).

We Looking forward over the next three years, we plan to continue this production optimization program with projected capital expenditures of $41 million to $51 million in 2011. We have identified a number of recompletions, shallow development wells, and extension wells for 2011, with additional projects for future years. Even greater potential is held by our deep exploratory prospects in this core area.

Another core area that we believe holds significant promise over a multiyear time frame is our Central Louisiana/East Texas area, where we’ve been drilling horizontally in the Austin Chalk trend for more than a decade. In 2010, we began applying recent technological advances in drill-bit steering and horizontal drilling to these Austin Chalk properties. We also redesigned our drilling process after analyzing more than 60 existing Austin Chalk wells, which typically have high initial production rates and high estimated ultimate recoveries. The lessons learned from this analysis, combined with technological advances in recent years, are enabling us to better stay in zone while drilling. The upshot was a 100% success with four wells we drilled in the Austin Chalk in 2010. Two of these wells were exploratory successes drilled with a joint venture partner in our Burr Ferry field, and two were development wells drilled in our Brookeland field.

Based on the results of these wells, we strategically expanded our Austin Chalk leasehold acreage in this core area and now own drilling and production rights on 158,000 net acres, in addition to fee mineral rights on 90,000 acres, in the Brookeland, Burr Ferry, and Masters Creek fields. Other fields in the Central Louisiana/East Texas core area that produce from various other reservoirs are South Bearhead Creek, Jeanerette, Cote Blanche Island, Bayou Sale, Horseshoe Bayou, Bayou Penchant, and High Island.

Looking ahead, we believe our Central Louisiana/East Texas core area, which currently accounts for 26% of our proved reserves, the majority of which are oil and natural gas liquids, holds low-risk development potential for significant growth in reserves and production over a multiyear timeframe. Our 2011 capital expenditures in this core area will be approximately $37 million to $47 million, as we begin redeveloping our Brookeland and Masters Creek fields and start to appraise and develop our Burr Ferry field following our exploratory successes there. We have identified five potential wells for this core area for 2011, with additional wells identified for future years.

To carry out these plans, we laid the necessary financial groundwork in 2010, maintaining financial flexibility and preserving our strong balance sheet despite the economic downturn. In September, we extended our revolving credit facility of $500 million through October 2015 (with the borrowing base currently set at $300 million). At year-end, we had no balance drawn on this credit facility and had $86 million of cash and cash equivalents. Our longer-term bank borrowings are not due for quite a few years. We have $250 million in senior notes due in 2017 and $225 million in senior notes due in 2020.

As a result, we are in the position to fund our 2011 activities primarily from cash on hand and internally generated cash flows, as we did in 2010. We have the flexibility of supplementing our 2011 budget with gains from any property divestitures as well as draws on our line of credit, if needed. We are protecting our cash flow and capital budget with our price-risk management strategy, which maintains upside potential while protecting 20% to 50% of our production volumes against declines in commodity prices. The instruments we use to protect against falling oil and gas prices include low-cost price floors, near-term forward sales, and participating costless collars.

A Swift Energy employee uses a slick line unit to finish a pressure gauge run on a horizontal well in the AWP field in South Texas.

In short, we are confident that we have assembled all the resources needed to succeed. We have a great portfolio of properties that allows us to achieve economies of scale and multiyear potential using repeatable operations that promote continuous improvement. We have an outstanding technical team and a systematic approach to value creation that has produced an excellent track record of performance. We have the financial strength to fund our operations and the demonstrated flexibility to adapt to changing industry conditions.

Terry E. Swift
Chairman and Chief Executive Officer,
Swift Energy Company