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The Play:

Haynesville Shale
By Cheryl Hudak

Chesapeake is writing a new chapter in the long history of energy production in Louisiana.  After two years of scientific evaluations and petrophysical studies of more than 100 existing wells, the company announced in March 2008 the discovery of what may become the largest natural gas field in the U.S., the Haynesville Shale.

The discovery required vast amounts of seismic data (3,700 miles of licensed 2-D seismic data and 53 square miles of licensed 3-D data so far), well testing and core sampling. The Chesapeake Reservoir Technology Center (RTC) in Oklahoma City provided near real-time incorporation of results and findings to help refine processes in the lab, modeling, mapping and operations.

Driller Victor Palacios with Steve Mason, Halliburton Directional
Drilling Supervisor.

Coordination and teamwork between geology, petrophysical, operational and RTC groups made the Haynesville Shale a reality.  Now that team is working out how to efficiently apply and develop the treasure it has discovered.

A vast treasure it is: encompassing a 3.5 million acre area, this massive resource play has a total unrisked unproved net reserve potential of 29 trillion cubic feet of equivalent (tcfe). Its total risked unproved reserve potential is more than 14 tcfe – almost twice that of the Barnett Shale in north-central Texas, which is the nation’s current natural gas hot spot.
Since the opening bell rang in the Haynesville Shale, the company’s rig count has risen from four to 18 at year-end 2008 in the northwestern Louisiana parishes of Caddo, DeSoto, Red River and Sabine. The play also extends into Harrison, Panola and Shelby counties of East Texas, where the first horizontal well is currently being drilled.

Today the company already has 30 producing wells in northwest Louisiana with net natural gas production of 80 million cubic feet (mmcf). More wells are coming on line weekly, with 3,000 potential net risked wells in inventory.

A workover crew drills out frac plugs to
enhance production on the Walton 23-2

The typical Haynesville Shale well is 16,000 to 17,000 feet in total depth (between 10,000 and 13,000 feet of vertical and 4,800 feet of horizontal depth).  Long horizontals provide greater exposure to the gas-bearing formation, and since gas in the Haynesville is high pressured, each well is expected to have higher reserves – a range of 4.5 to 8.5 billion cubic feet of equivalent (bcfe), with a reasonable midpoint of 6.5.

“We are uniquely positioned here with tremendous opportunities,” said Dave Wittman, District Manager – Haynesville Shale. “This play will have a great financial impact on our company. And in a rural area like this one, it will also have a great impact on the people who live here. A lot of landowners will benefit from our activities.”

Chesapeake currently owns or has commitments for almost 500,000 net acres of leasehold, after selling 20% of its acreage to Plains Exploration & Production Company in a joint venture completed in summer 2008. The $3.3 billion cash injection from the Plains partnership will help fund a substantial portion of the leasehold, drilling and completion costs required for development, providing exceptional finding costs of less than $1 per thousand cubic feet of natural gas equivalent.

The company is developing the Haynesville Shale with 80-acre well spacing, eight wells per section, situated on what it calls “superpads.” Each superpad, located on a section line, will be home to eight wells, each featuring a single 4,800-foot lateral oriented north to south.  Gathering systems are oriented east-west along section lines. This innovative development plan provides significant advantages over traditional one-well, one-padsite development: it reduces the environmental footprint of the operation, requires fewer rig moves and helps contain location costs.

State-of-the-art gas purification tower at the
gathering station

Natural gas is transported through transmission pipelines, and those in place in the Haynesville Shale are not currently adequate to move the vast quantities of gas the play will produce. As a result, Chesapeake Midstream Partners (CMP), a gathering system operation that is part of Chesapeake Energy Marketing, Inc. (CEMI), is ramping up existing gathering systems and pipelines from 170 million cubic feet per day (mmcf/d) capacity up to 1.4 billion cubic feet per day (bcf/d).

More than 300 miles of right-of-way are proposed for the area, with transmission systems designed to accommodate Chesapeake leasehold, drillsite locations and future pipelines. The systems will include both high and dual pressure pipelines to minimize compression operating costs. Five compressor stations will eventually move Haynesville Shale gas, with two large 1.0 to 2.0 billion cubic feet per day (bcf/d) central facilities featuring compression and dehydration systems. The new gathering systems will position the company to connect with any new Haynesville Shale operations and interconnect with existing major interstate pipelines.

“We want to sell good, dry, clean gas,” said Joe Stockton, Midstream Operations Foreman for CMP. “The new facilities will include the newest amine treatment equipment to strip CO₂ and H₂O from the gas. The purer the gas, the cleaner it burns and the more valuable it is. We also want it pure down the pipeline, because CO₂ will corrode pipelines.”

Developing a play the size of the Haynesville Shale is time consuming and costly, but the people in the heart of the action enjoy every minute of it.

“The fun’s in the challenge,” said John Cogar, Production Supervisor, “Putting it together and watching it go through the pipe. Yes, there is huge cost and risk in this project. But it has the biggest upside imaginable – seeing our success.”

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The Environment:

Cool Clear Water

On or off the job, Chesapeake employees make the case for H₂O
By Cheryl Hudak

In classroom aquariums, students raise trout from eggs to fingerlings which are released into a nearby coldwater stream.  In the process, students are responsible for filling and monitoring water tanks, feeding the fish, maintaining water quality and studying stream habitats. They also keep daily logs recording pH levels, ammonia, temperatures, any changes in the fish and feeding times, signing their names each day.

One teacher wrote: “This has been one of the most delightful experiences of my teaching career! I have been able to incorporate so many different areas of our curriculum to the tank: sequencing, predictions, drawing conclusions, keeping records, chemistry, biology and responsibility. I have several reluctant writers, but the journal entries help students communicate their thoughts on paper.”

A teacher demonstrates water testing to students participating in the
Trout in the Classroom Program.

Shafer is involved in setting up tanks and equipment in the classrooms, and remains on call to teachers and students throughout the fish-raising process.

“This is one of the most rewarding projects I’ve ever been involved in,” Shafer said. “To see the faces of those young students light up when they are telling you about their fish and showing them to you is priceless.”

Chesapeake and its employees are involved in water-related conservation efforts throughout the company’s operating areas. It is an active member of the Ground Water Protection Council, a national organization dedicated to the protection and conservation of ground water resources for all beneficial uses.

In West Virginia, Chesapeake also supports the Friends of the Cheat River project.  In Arkansas, it is a major contributor to the Ozark Rivers program of The Nature Conservancy, which focuses on conservation efforts reducing siltation and sedimentation in Ozark rivers.

The company believes rivers are not only life giving, but lifestyle enhancing. As a result, Chesapeake recently helped sustain the Falcon Lake Park Project in Zapata, Texas. The 573-acre state park was created from the waters of the Rio Grande River and is home to some of the nation’s premier bass fishing.  Farther north, the Oklahoma River, which flows near downtown Oklahoma City, has become an acclaimed rowing venue with the Chesapeake Boathouse hosting international regattas in an area which 10 years ago was an eyesore.

The company carries that commitment to water conservation into its day-to-day operations.  Water is a critical element in bringing up oil and natural gas, particularly in unconventional plays like shales, which require horizontal wells and fracture stimulation to produce.

As Chesapeake ramps up development in shale gas plays from Texas to New York, its water requirements will continue to grow. On a per-well basis, shale wells require more water to drill and frac. However, each shale well can produce as much as five times the volume of one conventional well, so fewer wells can produce the same amount of natural gas.

Whitewater rafting on the Big Sandy, a tributary of the Cheat River in
West Virginia.

Chesapeake is a staunch advocate of conscientious development, including responsible water use. In each of the 17 states where it operates, the company complies with a complex array of restrictions and regulations put in place by local, state and federal entities. It works with scores of water boards, environmental agencies and commissions as well as property owners as it searches for new and better answers to water issues.

“Our goal is to develop close relationships with each of hundreds of regulatory commissions at the state and local levels, so both the states and the company can meet our goals,” said Mike Mathis, who recently joined Chesapeake as Manager – Regulatory, Water Planning. Mathis will provide leadership and technical focus to help the company’s operations specialists as they plan and identify long-range water needs and options.

“We’ve commissioned water studies in all our major shale plays: the Haynesville, Fayetteville and Marcellus shales,” Mathis said. “We’re using those studies to provide a baseline for a similar study in the Barnett Shale. Through these studies, we are looking at the regulatory framework in each area, as well as available water sources. All this information will help as we start interacting with each regulatory community, and will make it easier to work with them in the development of long-term water plans.”

In Oklahoma, legislation was recently passed to establish a technical work group to identify supplies of “marginal quality” water – water that is too brackish or has too high a saline content for some uses such as drinking, but can be used for other purposes. The group is further charged with identifying possible uses for this low-quality water and technologies being developed to use it. A member of the Oklahoma work group, Mathis will also work with other Chesapeake environmental specialists to help undertake similar initiatives in other states.

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The Technology:

Map it, Drill it, Frac it
By Cheryl Hudak

Almost anyone in the natural gas industry will agree that producing natural gas today is a three-part journey. As unconventional resources play increasingly critical roles in meeting U.S. energy needs, fracture stimulation (or hydraulic fracturing) has become the third leg of the long journey from exploration to production. It brings home the gas.

Hydraulic fracturing, commonly known as “fracing,” is a completion technique used by engineers to create a crack or fracture in rock that contains oil or gas, propping open the rock to let hydrocarbons flow out and up through the wellbore.

In 2007, about 50% of the total U.S. natural gas production came from unconventional resource plays such as tight sand, gas shale and coalbed methane. As one of the nation’s top unconventional operators, Chesapeake uses hydraulic fracturing techniques on approximately 99% of its wells.

Festooned with red pipes, the University 19-9 #2 is the star of the show
during fracture stimulation in West Texas. An army of pumper trucks,
mixing tanks and storage units for water and sand converge on the site
during the four to five days it takes to frac the well.

“Often, completions are the key to discovering new plays,” explained Jeff Fisher, Senior Vice President – Production. “There have been a lot of bypassed rocks, known depositions considered uneconomic. New completion techniques have opened up opportunities that previously didn’t exist.”

According to Fisher, Chesapeake has fraced most wells in the hard rock plays where it operates for many years. The difference is today the company combines fracing with horizontal drilling.

“That’s changed the game,” he said. “At one time, fracture stimulation was done to enhance well productivity. Today, in our shale plays, it’s required to have any production at all.”

The technique is used in newly completed wells to increase drainage rates and maximize field development. It is also used for already-producing wells in developed or mature fields to get the most out of existing infrastructure and maintain production rates.

The entire fracing process is highly complicated and can take up to four or five days to complete. It also requires enormous planning and expense.

“The coordination required to frac a well is unbelievable,” Fisher said. “I think fracture stimulation is perhaps the most intense operation in natural gas development. It is a carefully choreographed part of the business, as we have to coordinate fluids, pumps and sand, and monitor every aspect of the job to make necessary adjustments.”

The process is further complicated by the fact not all wells, locations or geology respond to fracture stimulation in the same way.

“Not all shales are the same,” Fisher explained. “For instance, the Haynesville Shale in Louisiana is hotter, deeper and over-pressured – very challenging from an operational perspective. Of course, that high pressure means it is a very productive play, but it does require higher pressure equipment.”

Regardless of location, depth or geology, every frac job is performed by experienced crews from companies that specialize in the procedure. It is an expensive finale to the development process, often adding $500,000 to over $1 million to each well’s cost. Without it, however, shale gas drilling would be fruitless.

Chesapeake is considered a leader in the use of hydraulic fracturing techniques.
“We’re doing a lot of the same things other unconventional operators do,” Fisher said, “but more of it and in more places; so we can transfer the technology from play to play.  We understand that and use it more effectively to optimize each play. We are constantly learning and reapplying new information.

“Our Reservoir Technology Center helps incorporate rock sciences into our activities. We are learning more and more about fluid sensitivities and rock mechanics, and modeling through computer programs that simulate the effects of fracing. These help us understand the many variables and economic elements involved.

“We’re also learning where in a thick formation the well should land – top, middle or bottom of the formation – for maximum results. This helps us guide the wellbore exactly where we want it to be. It’s another way our core lab provides a great advantage.”

Chesapeake production teams are experimenting with microseismic technology, which allows them to monitor and see – in real time – the rock, as it cracks during the hydraulic fracturing process.

“We’ve always tried to understand exactly what happens when we do fracture stimulation,” Fisher noted. “But we can’t actually see it occur, where it is, and how effectively it opened up the reservoir. Microseismic technology may in the future give us the ability to adjust the fracturing process on the fly. Today, we can record fracs with seismic data, which provides us better information on how the fracing process went on any specific well.”

Such information leads to innovation as operators gain experience in the powerful pairing of horizontal drilling with fracture stimulation. One such innovation is simulfracing, where more than one well is fraced at the same time.  This technique offers better diversion of fluids and more complex fracturing than isolated fracs.  Production is often enhanced and the operation is more efficient and cost effective as well.

While the fracture stimulation process may appear to use large amounts of water, those quantities are less imposing when compared with total water usages in an area.  For example, Chesapeake drilling and completion activities at projected peak development in the Marcellus Shale will account for less than 0.06% of that region’s entire water consumption.

A typical Chesapeake well in the Barnett Shale uses about 3 million gallons of water for drilling and completion – usually just once during its projected 20-30 year lifespan. In comparison, a golf course uses about 3 million gallons of water every 10 days.  The amount of water used per well varies with each area and well; but in every case, frac fluids and water are disposed of at permitted facilities or treated for re-use.

Environmental issues are of critical importance in every location where the company operates. The company meets or exceeds oil and gas regulations throughout its operations. Each hydraulic fracturing project is designed, conducted and monitored to mitigate environmental impact while maximizing natural gas production.

Natural barriers also play a role in protecting ground water. With most freshwater aquifers located less than 1,000 feet below the earth’s surface and fracturing operations conducted at levels between 4,000 and 12,000 feet below ground level, there are thousands of feet (often between one and three miles) of natural geologic barriers between Chesapeake’s productive shale formations and freshwater zones.

Simplified steps in hydraulic fracturing

1. Water, sand and additives are pumped at extremely high pressure down the wellbore.
2. The liquid goes through perforated sections of the wellbore and into the surrounding formation, fracturing the rock and injecting sand or proppants into the cracks.
3. Experts continually monitor and gauge pressures, fluids and proppants, studying how the sand reacts when it hits the bottom of the wellbore, slowly increasing the density of sand to water as the frac progresses.

4. This process may be repeated multiple times, in “stages” to reach maximum areas of the wellbore. When this is done, the wellbore is temporarily plugged between each stage to maintain the highest water pressure possible and get maximum fracturing results in the rock.
5. The frac plugs are drilled or removed from the wellbore and the well is tested for results.
6. The water pressure is reduced and fluids are returned up the wellbore for disposal or treatment and re-use, leaving the sand in place to prop open the cracks and allow the gas to flow.

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Deep Haley:

Challenges and Rewards

Loving County, Texas, gives new meaning to the term “wide open spaces.”  Less than 100 people live in the 677-square-mile county situated just south of the New Mexico border. But those Loving County folks are not lonely, because they’re outnumbered about 10 to 1 by oil and gas wells – which have given the population in this isolated area the highest median income of any county in the United States.

The Deep Haley field, where Chesapeake Energy brings up about 105 million cubic feet of natural gas equivalent (mmcfe) every day, is located in the Texas counties of Loving, Ward and Winkler. The company is exploring more than a million gross acres with 560,000 net acres of leasehold.  Currently, Chesapeake has more than 100 producing wells in the area with spacing of one well per 640 acres, although they are starting some downsizing to 320-acre spacing.

A rig is dwarfed by the fiery desert sunset

The Deep Haley is well named, since past drilling was in zones as low as 22,000 feet beneath the surface. Today most of the company’s wells extend vertically 17,000 to 18,000 feet deep into the Atoka and Morrow zones. The area is interesting from a geologic perspective in that it contains several geologic targets within the same field, with some directional wells being drilled into the 12,000-foot-deep Bone Spring formation.

“The Deep Haley is a unique area,” said Rob Jones, District Manager - Permian. “It’s a very highly pressured tight gas sand play – with bottom hole pressures exceeding 15,000 psi. That makes it very challenging drilling, as you encounter lots of gas while drilling with heavy mud weights, up to 18 pounds per gallon, and go through weaker formations that cause loss of drilling fluid. That means it can be tedious drilling. It’s finicky – the hardest place I’ve drilled in 26 years.”

Although most of the Chesapeake wells in the field are vertical, the extremely tight formations require fracture stimulation for production. Water is trucked through the desert for fracing, and a disposal system injects saltwater produced through operations into a disposal well 6,000 feet below the ground – more than a mile beneath the area’s 300-foot freshwater table. All casings on the disposal wells are tested for safety and to ensure that saltwater cannot leach into ground water sources.

A yucca is the closest neighbor to this
Chesapeake drillsite.

It usually takes 100-120 days and costs up to $12 million to drill and complete a well in the Deep Haley, but Jones believes the effort is worthwhile.

“When you hit a good well, it comes in at a very high rate – as much as 40 mmcfe a day. We like those,” he said. “And they produce 1,000 BTU gas, very dry with no impurities.”

That’s how it is in Texas’ Deep Haley field, where the challenges are extreme, the targets are deep and the gas is sweet.

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Corporate Culture:

Desmystifying Hedging

Mitigating Risks and Securing Returns

Hedging. Just say the word and many peoples’ eyes glaze over. Simple in concept, hedging is a technique designed to reduce or eliminate price-related risk. Chesapeake hedges its revenues by entering into agreements to lock in prices for a portion of its natural gas and oil production for a specific period of time.

“This eliminates risk, gives us more predictable earnings and cash flow and allows us to operate a more efficient drilling program, with less variability in capital spending and drilling activity levels,” said Jeff Mobley, Senior Vice President – Investor Relations and Research. “Hedging helps us be more of a price maker rather than a price taker.”

Chesapeake is one of the oil and gas industry’s most active and successful hedgers.

“We use hedging programs to mitigate the risks inherent in developing and producing natural gas and oil reserves, commodities that are frequently characterized by significant price volatility,” Mobley explained. “We believe this price volatility is likely to continue in the years ahead, and we can use it to our benefit by taking advantage of times when prices reach levels we think are either unsustainable for the long term or provide unusually high rates of return on our invested capital.”

Jeff Mobley
Senior Vice President – Investor Relations and Research

The company has been successful in meeting those goals. From 2001 through 2008, Chesapeake’s natural gas and oil hedging program has generated total realized gains of approximately $2.0 billion, which has greatly reduced its acquisition and financial risks and made investing for the future easier and safer.

“We generally hedge about 24 months’ production on a rolling basis,” Mobley said. “The percentage we choose to hedge varies over time, but now about three-fourths of our production is hedged for 2009, and roughly half in 2010 – and at attractive prices.

“The hedging tools we use are financial transactions and work in tandem with the physical sales of our actual production in the marketplace,” Mobley noted.  “The financial transactions generally make money when prices go lower but the gain is offset by lower prices when the production is sold to cash buyers.  Likewise, financial transactions generally lose money when prices go higher but that is offset by production that is sold at a better price. The net effect is to realize an acceptable price whether prices go up or down.”

Hedging can sometimes lead to the appearance of wide swings in a company’s revenues and profitability due to the effect of certain accounting rules on open positions, or uncompleted hedge transactions, at the end of each quarter. Those rules can be confusing to many observers.  The accounting rules place a greater emphasis on accurately reporting the value of derivative assets and liabilities on a company’s balance sheet than on matching realized revenues and earnings for each quarter on a company’s income statement.

“For example,” Mobley explained, “last year we locked in very attractive revenues, but we had open hedge positions that caused us to have very wide swings in our quarterly reported earnings. In the second quarter our net income was reported as a negative $1.6 billion. During the third quarter we reported a positive net income of $3.3 billion as the swift surge in natural gas and oil prices reversed itself.

“The size of these swings was heavily influenced by the percentage and the number of months of future production that was hedged in addition to the changes in the price of natural gas and oil. Small, noncash price changes can look like big amounts when Chesapeake has hedged a large percentage of its production over the next two years.”

Mobley added, “The company’s adjusted earnings for both quarters were almost the same, at $479 million for the second quarter and $486 million for the third quarter.

“We generally look at adjusted earnings to better understand the company’s performance from realized results on a quarter-to-quarter basis.  Those figures are not distorted by hedge accounting rules,” he noted.

Most E&P companies use a variety of hedging tools, often called “derivative instruments,” to balance their risk and capture premium pricing – just as savvy individual investors have a variety of investment tools such as stocks, options, bonds and cash.

“We use generic swaps to lock in prices as well as costless collars that lock in minimum and maximum prices rather than a specific price,” Mobley said. “Additionally, we add option features to those swaps and collars to improve pricing in exchange for accepting some incremental downside risk.  We believe that prices can’t be sustained at sub-economic price levels and choose not buy hedging insurance for that extreme an outcome.”

The secret behind natural gas volatility

Natural gas is one of the most volatile commodities in the world. Its wide price swings are often driven by fear: fear of having too much or too little natural gas in the U.S. marketplace or in storage inventories.  How this works in a nutshell:

The price of natural gas drops when the market perceives there is too much natural gas. Remember, there is limited storage for natural gas and it is not easily transported. Natural gas prices fluctuate to encourage or discourage supply and demand, in order to be sure there is adequate – but not too much – natural gas in storage each autumn in advance of the winter heating season.

The price of natural gas rises when the market perceives there is too little gas; for example, if production, storage inventories and imports cannot meet the nation’s winter heating needs and there is not enough time to refill storage before the next winter.

The weather is one of the largest variables in natural gas demand and prices can also be affected by the price of substitute fuels (think oil and coal), economic activity, geopolitical uncertainty, the activities of speculators or by other events (remember Hurricane Katrina?).

You might be a hedger if:
• You take advantage of utility company offers to lock in set prices for home heating/cooling costs each year
• You have homeowner or medical insurance
• You have a fixed-rate mortgage

You might need a weatherman to know which way the wind blows...
...if you are a natural gas exploration and production company like Chesapeake. Chesapeake’s meteorology department in Chicago works with the company to predict weather variability and estimate how much the demand for natural gas will vary for heating and/or cooling needs.