Swift Energy Company 2011 Annual Report: Balance-Diversity-Focus-Growth

Letter to Stockholders

Just five years ago, the public consensus seemed to be that the U.S. oil and gas industry had passed its zenith. U.S. oil production had been in general decline since 1970, and domestic natural gas supplies had been flat for over a decade. Today, U.S. oil production is rising again, and domestic natural gas production is at an all-time high. Our industry is in the midst of a dramatic resurgence, and the outlook for domestic oil and gas is more promising than it has been in a generation.

ST Drilling  

In 2011, we enhanced our drilling performance by extending the lateral legs in our horizontal wells to as long as 6,000 feet.

 
   
Hydraulic Fracturing  

We optimized hydraulic fracturing in South Texas, cutting completion costs about $500,000 per well while simultaneously increasing well performance.

 

 

Swift Energy has stayed at the forefront of these expanding opportunities by continuing to follow a strategy honed over our 32-year history. We build value through a balanced approach to growth, relying on a diverse blend of oil and natural gas resources focused within a small number of core areas of operation. Our proven ability to simultaneously maintain balance, diversity, and focus in pursuit of growth is what provides us with competitive advantages in the midst of sweeping industry changes.

With this strategy, we generated real improvements across all fronts in 2011. Year-end proved reserves rose at an annual rate of 20% to a record high of 160 million barrels of oil equivalent (MMBoe). At the same time, annual production increased by 26% to 10.5 MMBoe, our second highest production growth rate since the year 2000. This production increase, combined with stronger prices for crude oil and natural gas liquids, helped us increase our 2011 revenues by 37% to $599 million. Sales of petroleum liquids (crude oil and natural gas liquids) accounted for about 80% of our total sales and about 50% of our production volume on a Boe basis. Even as we boosted production and reserves, we further improved our already strong safety record in the field by reducing recordable incidents by 25%.

Meanwhile, as our 2011 revenues climbed 37%, our expenses rose only 27%. We lowered drilling and completion costs, strengthened our supply chain, and advanced our technical processes and expertise. With revenues growing faster than costs, we were able to increase our net income for the year by 113% to $99 million. We also generated $373 million in cash flows from operations, an increase of 44% from the previous year. Ultimately, these financial results were founded upon our achievements in the field—including a 100% drilling success rate for the 44 wells we drilled during the year.

We ended the year with $252 million of cash on hand, up 191% from year-end 2010. Contributing to this strong financial position were our 2011 offering of $250 million in senior notes at 7-7/8% and $48.8 million in net proceeds from our divestiture of non-strategic properties late in the year. At year-end, we had no borrowings outstanding on our revolving credit facility, which was re-affirmed by our 10-member bank group in November.

BALANCE

Looking forward to 2012 and beyond, we will rely on the same balanced approach to growth that was fundamental to our success in 2011.

We have built all of our core areas through a combination of acquisitions and drilling, with the balance between the two activities determined by prevailing market conditions and strategic opportunities. Using this tandem approach has proven to be a cost-effective way to grow proved reserves, allowing us to replace 185% of our production over the last five years.

ST Oil
Nearly two-thirds of our natural gas proved reserves are located in properties that also produce a significant amount of oil and natural gas liquids.

We also strive to maintain a balance between petroleum liquids and natural gas that lets us respond to volatile prices. As the spread between oil and natural gas prices widened in 2011, we chose to focus more of our drilling efforts on liquids-rich opportunities, and in many cases, our liquids production was sold at a premium compared to the West Texas Intermediate (WTI) benchmark. Because our properties near the Gulf Coast have better access to higher-priced markets than those in other parts of the country, the average price we received for oil in 2011 was $107.00 per barrel—13% higher than WTI's average price for the year of $94.86.

By volume, our proved reserves at year-end 2011 were 36% liquids and 64% natural gas, but as some of our team members like to point out, all natural gas reserves are not created equal. Only 21% of our total proved reserves (and only about a third of our natural gas proved reserves) are in dry natural gas properties. In other words, 79% of our total proved reserves (and approximately two-thirds of our natural gas reserves) are in properties that produce a significant amount of crude oil and natural gas liquids. With current high prices for petroleum liquids, we are focusing our 2012 capital expenditures almost exclusively on these liquids-rich properties. It is important for our investors to understand that natural gas associated with petroleum liquids can be produced economically despite current low natural gas prices because of the high prices commanded by the liquids.

Other parameters that we strive to balance within our oil and gas properties include short-lived v. long-lived reserves, developed v. undeveloped reserves, geographic location (such as coastal v. inland), and access to markets. Geologically, we strive to maintain a balance between low-risk and high-risk prospects and between various types of formations.

We fund our exploration and development of these properties through a mix of financial activities that give us the flexibility to adapt to changes in external markets. We do this by emphasizing a strong balance sheet and generally relying on internally generated cash flows to fund our activities. This helps protect against industry downturns as we increasingly commit to longer-term contracts with service and equipment providers.

When needed, we implement other resources such as debt offerings, equity offerings, divestitures of non-strategic properties, joint venture agreements, and short-term borrowings, all of which we have employed in recent years. We also have a price-risk management strategy in which we use low-cost price floors, near-term forward sales, and participating costless collars to reduce our exposure to oil and gas price fluctuations when it is cost effective to do so. During the second half of 2011, however, our hedging activities were minimal due to prevailing market conditions.

SE LA Platform
Our Southeast Louisiana production is primarily oil. In 2011, we received an average of $107 per barrel for our oil production, 13% higher than the U.S. West Texas Intermediate benchmark price.
 

DIVERSITY

At the heart of this balanced approach to growth is our core area strategy, which creates diversity among our assets—from oil and gas in the tight sands and shales of South Texas to conventional oil resources in Southeast Louisiana to the liquids-rich Austin Chalk along the Central Louisiana/East Texas border.

Our South Texas core area, which drove our production and reserves growth in 2011, remains our focus in 2012. In this area, we target two formations that respond to similar technologies, the Olmos tight sand and the Eagle Ford shale. This core area is in a region that has seen an explosion of drilling activity in recent years, leading to intensified competition for services and equipment. Midstream activity, including new infrastructure required to process and transport oil and gas from the area, has also had to be scaled up in a relatively short time frame.

Though this region has been in the industry's spotlight for only a few years, we have been in South Texas since the late 1980s, drilling hundreds of hydraulically fractured vertical wells in the Olmos tight sand in the AWP field. In 2008, we drilled our first hydraulically fractured horizontal well in the Olmos formation. Following that success, we applied this combination of technologies to the liquids-rich Eagle Ford shale. During 2011 we focused our company's drilling program on this particular core area, drilling 38 wells there, six of which were drilled with a joint venture partner.

ST Rig Floor
In Central Louisiana/East Texas, we are now applying new technological advances in horizontal drilling, such as improved drill-bit steering that allows us to stay better in zone.
 

Today we have four fields in this core area. The AWP field contains both the Eagle Ford shale and the Olmos tight sand formations, with the Olmos overlaying portions of the Eagle Ford at shallower depths. The Fasken and Artesia Wells fields contain only the Eagle Ford, and the Sun TSH field contains only the Olmos. Altogether, these properties accounted for 124 MMBoe, or 78%, of our total proved reserves at year-end 2011. About one-fourth of the reserves consisted of oil and natural gas liquids and about three-fourths were natural gas.

In Louisiana, where we are one of the largest crude oil producers in the state, we have two fields in our Southeast Louisiana core area, Lake Washington and Bay de Chene. These fields target liquids-rich reserves held in multiple stacked layers of Miocene sands radiating outward from salt domes. The fields are covered by shallow inland waters and drilling is conducted with barge-based rigs. The wells in this area typically generate a relatively high margin of return, in part because of the premium prices received for our Light Louisiana Sweet crude oil and our Heavy Louisiana Sweet crude oil.

In 2001, when we first acquired Lake Washington, the field had been in operation since the 1930s and was considered a mature field with 7.7 MMBoe of booked proved reserves. Since we assumed its operation, we have produced more than 48 MMBoe of oil and gas from the field, and we had 14.4 MMBoe of proved reserves booked at year-end 2011, of which 92% were petroleum liquids.

Like Lake Washington, our Bay de Chene field, acquired in 2004, is liquids rich. At year-end 2011, we had 2.9 MMBoe of proved reserves in the field.

Looking forward, Lake Washington and Bay de Chene have multi-year potential, including some deep exploration prospects that we plan to test over the next two years. If successful, these prospects could result in significant increases in production and reserves in the future.

In our Central Louisiana/East Texas core area, where we first began operations in 1998, we now have four fields, three of which produce from the Austin Chalk trend: Burr Ferry, Masters Creek, and Brookeland. In contrast to wells drilled in fields that have long-lived reserves, Austin Chalk wells typically undergo rapid production declines after an early payout.

In two of our fields targeting the Austin Chalk—Burr Ferry and Masters Creek—we have begun transforming a mature asset into a growth area by applying newly enhanced horizontal drilling technologies, such as improved drill-bit steering that allows us to stay better in zone. In our Burr Ferry field, we have begun a multi-year development drilling program following two exploratory successes drilled in 2010 with our joint venture partner. In our Masters Creek field, we are re-assessing the field's potential in light of the success we have had in Burr Ferry.

The fourth field in the Central Louisiana/East Texas core area is our South Bearhead Creek field targeting primarily the Wilcox sands. We tentatively plan to resume drilling in this field in late 2012 or early 2013 as part of our long-term development plan for the area.

Our proved reserves in our Central Louisiana/East Texas core area totaled 18.4 MMBoe at year-end 2011, about 66% of which were petroleum liquids.

FOCUS

Our operational strategy has a core area focus that has developed over the company's history. While each of our three core areas is unique with respect to geography and geology, they provide us with the common benefits associated with having concentrated resources within large, contiguous acreage positions. One important benefit is operational flexibility, which derives from our operating 96% of these proved reserves. This allows us to efficiently adapt to changes in the external environment. Another benefit is the large inventory of prospects within each area that allows us to refine our processes, further build our expertise, and achieve higher efficiencies from the continuous improvement of repeatable operations. Finally, having multiple opportunities located in proximity to each other allows us to cut costs through economies of scale.

Our South Texas core area exemplifies the benefits we reap from this focused approach. In the late 1980s when we first acquired properties producing from the AWP field's Olmos sand, the field was considered to be close to maturity. Subsequently we began operating the properties, acquired additional adjacent undeveloped acreage, and launched an aggressive drilling program. Today, our South Texas core area is a cornerstone of our operations that promises to provide much of our growth in 2012 and beyond. We not only have substantially increased production and reserves from the "mature" Olmos tight sand but also are pursuing new opportunities in the Eagle Ford shale. In 2011, we increased production, booked additional proved reserves, decreased the drilling and completion costs per well, lowered operational costs, and continued to expand our knowledge and technical expertise in the area.

Among our specific achievements last year was decreasing drilling and completion costs by approximately $1 million per well on average. We optimized the length of the lateral legs of the horizontal wells, extending the legs of some wells up to 6,000 feet. We increased the number of hydraulic fracturing stages to as many as 17 for some wells, experimented with higher strength proppants and variable pump rates to obtain optimal fracture heights, and used micro-seismic technology to optimize fracture lengths and increase fracture productivity. To create further efficiencies in this core area, we have initiated the use of multi-well pad drilling in which one pad is used to drill several wells. To improve our hydraulic fracturing process, we plan to initiate zipper fracturing, in which wells are perforated and hydraulically fractured in sequence to lower costs and reduce down time. The upshot is that we continue to optimize the performance of our drilling and completion methods even as we accelerate our drilling program.

Map
Swift Energy currently focuses its activities in three core areas of operation: South Texas, Southeast Louisiana, and Central Louisiana/East Texas.
 

In addition to cutting drilling and completion costs, we have made significant improvements to our South Texas supply chain, some of which we apply to other core areas as well. We forged stronger relationships with equipment and service providers to help avoid production curtailments and to maintain better control over rising costs. These arrangements included contractual agreements for transportation, processing, a dedicated fracturing crew, and equipment. We also began sourcing and taking delivery of some of our fracturing proppants in-house, as well as improving the management of the large quantities of water required for the fracturing process.

To help guide our exploration and development program in South Texas, we are processing and merging multiple sets of available three-dimensional seismic data and integrating them with geologic and engineering data to develop proprietary geoscience databases. In 2011, we completed a project in which we merged and prestack time-migrated 700 square miles of data for the AWP field, and we initiated a similar project for an additional 100 square miles for the Artesia Wells field. From the resulting databases we can derive numerous attributes of the fields used in prospect identification, well placement and spacing, and geosteering during drilling.

Through all of these improvements, we have begun to forge an assembly-line process for the development of our oil and gas properties in South Texas, and we expect to begin realizing the full operational efficiencies of this manufacturing mode in the near future.

In our Southeast Louisiana core area, we have developed repeatable techniques to enhance production and prolong the life of the prolific Lake Washington field. In 2011, we performed 24 well recompletions and numerous other production enhancement projects, including sliding sleeve changes, which helped to flatten the natural production decline curve of the field's oil wells. We also drilled two development wells, which are expected to yield seven to eleven additional prospects in the future.

Our Central Louisiana/East Texas core area is an example of how we are applying technological improvements realized in one core area to other areas. As we continue to reassess our Austin Chalk fields in 2012, we are applying advanced drill-bit steering technology that we first used in South Texas. We are also analyzing how best to improve the spacing of wells in these fields. During 2011, we drilled or participated in four wells in this core area, two in the Burr Ferry field (one with a joint venture partner), one in the Masters Creek field, and one in the Brookeland field (non-operated).

GROWTH

Through our work in 2011 and previous years, we have amassed the tools needed for multi-year growth that will allow us to set new record highs in production and reserves. We have a portfolio of varied properties that achieve economies of scale and enable us to perform repeatable operations and continuously hone our skills and expertise. We have exerted much effort into building relationships with equipment and service providers to guard against competition for resources and to control rising costs. We have the most diverse project inventory in the company's history—one that offers an excellent blend of risk and reward. We have $252 million in cash on hand and an untapped credit facility, which gives us the financial flexibility to pursue opportunities. And we have the in-house talent in engineering, geoscience, operations, management, and finance needed to exploit and expand the resources that are reshaping our company's—and the nation's—future.

Our goal for 2012 is to increase production by 14% to 20% and reserves by 10% to 15%. Having fulfilled our near-term leasehold drilling obligations on most of our acreage prospective for dry natural gas production, we can now focus on oil and liquids-rich opportunities. We plan to devote three-fourths or more of our 2012 capital expenditures of $575 million to $625 million on higher-return, liquids-rich acreage in South Texas. About a fourth of our budget is planned for other liquids-rich opportunities located in Southeast Louisiana and Central Louisiana/East Texas. Also, through our discretionary capital, we are considering drilling up to three wells in pursuit of strategic growth opportunities outside of our core areas. By the end of this year, we expect that our production will be more evenly weighted between petroleum liquids and natural gas as we make this shift toward drilling liquids-rich prospects almost exclusively.

Most importantly, we have a strategy that has been time-tested. All of the elements needed to deliver growth—balance, diversity, and focus—are in place. We believe it is reasonable to expect that in 2012 we will deliver the highest annual production levels in the company's history and lay the groundwork to achieve further growth in the years to come.

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


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Last modified: Friday, November 30, 2012 10:34 AM