Chesapeake is the eighth largest E&P company ranked by total assets according to the Oil & Gas Financial Journal, behind ExxonMobil, Chevron, ConocoPhillips, Anadarko, Marathon, Occidental and XTO Energy. It also ranks eighth in exploratory spending and market capitalization, and twelfth in total revenue. (Chesapeake's market cap is 18% of ExxonMobil's.) In 2009, Chesapeake drilled 1,148 gross operated wells, which it called "the industry's most active drilling program," spending $2.941 billion. Its leashold inventory at the end of 2009 was 13.7 million net acres.

Here are some highlights from Chesapeake's report:

Meanwhile, Chesapeake has published on its website a "Fact Sheet" listing the chemicals used in its frac fluids in the Barnett Shale. The list includes "petroleum distillate," which Chesapeake describes as a "friction reducer," describing it as a product "used in cosmetics including hair, make-up, nail and skin products." The website shows that 99.5% of frac fluid is made up of water and sand, and only .5% is made up of additives, including "petroleum distillate." But the site does not show what percentage or volume of "petroleum distillate" or other additives are used in the frac fluid, or what kind of petroleum distillate is being used.

Another energy organization, Energy In Depth, has published a response to the EWG's white paper on fracking, "When Gummy Bears Attack." its author, Chris Tucker, cites data from the U.S. Department of Energy to show that "petroleum distillate" represents .088% of the volume of frack fluid. He says that petroleum distillates are used in lip gloss, sunscreen and gummy bears.

So what is "petroleum distillate"? Purdue University describes "petroleum distillates" as including all products derived from the distillation of petroleum, from diesel fuel to petroleum jelly to waxes and asphalts:

"Petroleum distillates are found in a wide variety of consumer-products including lip gloss, liquid gas, fertilizer, furniture polish, pesticides, plastics, paint thinners, solvents, motor oil, fuels and hundreds of other products. Petroleum distillates listed commonly on labels of general household products are those that distill off around naphthas. Petroleum jelly, a petroleum distillate product, is generally regarded as nontoxic.

"Petroleum distillates contain both aromatic hydrocarbons (carbon rings) and aliphatic hydrocarbons (straight carbon chains). The chemical structure of the hydrocarbon largely defines the nature and behavior of these compounds. Aromatic hydrocarbons are the most toxic compounds found in petroleum products. Most aromatic hydrocarbons are long-term toxins and known cancer causing agents. These aromatic compounds are found in all crude oils and most petroleum products. Many aromatic hydrocarbons have a pleasant odor and include such substances as naphthalene, xylene, toluene, and benzene. Aliphatic hydrocarbons are flammable and may be explosively flammable. Aliphatic hydrocarbons include methane, propane, and kerosene.

"Aliphatics and aromatics pose a special health risk if ingested and vomited. When swallowed, the lighter, more volatile distillate products can be sucked into the lungs interfering with the lung's functions and chemical pneumonia may result. Aspiration of fluid into the lungs can occur both during swallowing and vomiting of the product. Upon skin contact, petroleum distillates can produce local skin irritation and sensitivity to light in some individuals. Environmentally, many of the petroleum distillate products add to smog and water pollution due to improper disposal or during their manufacture and use."

The controversy over frac fluids has made the Wall Street Journal.

The industry claims that hydraulic fracturing is safe and is necessary to tap oil and gas reserves in the U.S. to reduce our dependency on foreign resources. Environmental groups claim that frac fluid can cause contamination of drinking water and should be closely regulated. Much of the debate appears to suffer from a lack of reasonableness and objectivity.

Below is the same information in graph form.  Why would average residential gas prices in Texas be $12.88 per mcf, while residential prices in California and Minnesota -- far from natural gas production -- be less than $10 per mcf? Why such variations in Residential prices?

A little backrgound is in order: Large portions of the land in East Texas within the Haynesville and Bossier play were previously drilled to develop the shallower Travis Peak and Cotton Valley formations. The field rules originally adopted for the Cotton Valley fields provided that only one well could be drilled for each 640 acres of land. Over time, the field rules were amended to allow operators to drill wells in the Cotton Valley with a density of as little as 40 acres per well. Operators initially formed pooled units of up to 704 acres, a size allowed by most lease standard pooling clauses. Cotton Valley wells drilled on these pooled units are still producing, thus keeping in force the leases included in the pooled units. Generally, the pooled unit designations filed by operators for the Cotton Valley wells pooled all depths under the units, including the Haynesville and Bossier formations, which lie immediately below the Cotton Valley formation. Companies now desire to develop the deeper Haynesville and Bossier formations under these Cotton Valley units.

Field rules are special rules adopted by the Railroad Commission governing the spacing of wells in a designated field. Once special field rules are adopted for a field, they govern how wells must be spaced in that field and how much acreage an operator must have to drill a well in the field. Special field rules are adopted in response to an application made by an operator of wells in the field. The operator presents evidence to hearings examiners at the RRC as to the characteristics of the formation and how much area will be drained by a well in that field, and the operator proposes rules to be adopted by the RRC. The hearing examiners review the evidence and may or may not adopt the rules requested by the applicant. The hearing examiners make a recommendation to the three RRC commissioners, and the commissioners may either adopt the recommendations of the examiners or make changes in those recommendations.

Devon Energy Production Co., LP made application to the RRC for new field rules for development of the Haynesville and Bossier formations in East Texas, and it requested that several fields previously designated by the RRC be consolidated into a single "field" for purposes of the new rules. The new rules proposed by Devon would govern wells completed in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Rusk and Shelby Counties. In effect, Devon proposed that the Haynesville and Bossier formations be treated as a single formation for RRC regulatory purposes. Devon identified the Haynesville-Bossier formation as the formation found at depths between 9,568 feet and 11,089 feet in the Devon-Hull Unit A Lease, Well No. 102 (API No. 42-365-36749), in Panola County. This interval is more than 1,500 feet in thickness.

The TCEQ's response to Rep. Burnam's questions provides some interesting data.

The EPA conducted a similar study of fracing in 2004. That study was done to investigate whether hydraulic fracturing of wells completed in coalbed methane seams posed a risk to groundwater drinking supplies. The study was in response to alleged incidents of groundwater contamination and to a judgment of a U.S. Court that, because hydraulic fracturing of coalbeds to produce methane is a form of underground injection, the EPA is required to regulate it under Part C of the Safe Drinking Water Act. That Act requires states to regulate underground injection of fluids and to develop an Underground Injection Control Program approved by the EPA. The EPA's 2004 study of fracturing of coalbed methane wells found no evidence that any water had been contaminated by fracing of wells or that fracing posed any risk to drinking water. That study was criticized by some, including scientists in the EPA. In 2005, Congress exempted hydraulic fracturing from coverage under the Safe Drinking Water Act, in part at least based on EPA's 2004 study.

The requirement for a new EPA study of fracing in 2010 has been driven, in my opinion, by the development of the Marcellus Shale play in Pennsylvania and New York. New York has placed a moratorium on permits for wells and has published its own draft study of risks to surface and underground water supplies caused by drilling in the area of upstate New York that provides drinking water to New York City. That study is still subject to comment and revision and has caused much controversy in New York. The New York draft study likewise concludes that hydraulic fracturing poses no risk to drinking water if properly regulated. In a related development, a bill in Congress, the FRAC Act, proposes to require companies to disclose the chemical content of frac fluids.

Its conclusions:

Under the reference scenario, oil prices would increase to $87/bbl in 2015, $100/bbl by 2020, and $115/bbl by 2030 (in 2008 dollars). Under the 450 Scenario, the oil price would level off at $90/bbl by 2020.

Natural gas prices would grow 17% by 3020 under the 450 Scenario, or an average of 0.7%/year.  In 2030, gas prices would be 17% lower than under the reference scenario.

Although significant additional investment would be necessary to meet the 450 Scenario, this investment would be more than offset by fuel cost savings. Oil and gas import costs for OECD countries would be much less. Oil and gas import costs for China and India would be 30% lower in China and India in 2030 than in the reference scenario.

A typical oil and gas pooling clause allows the lessee to combine separate tracts covered by separate oil and gas leases into a single pooled unit for purposes of exploration and production. This allows the lessee to treat the pooled unit as a single lease. Wells drilled anywhere on the pooled unit are considered to have been drilled on the leased premises covered by each separate lease in the pooled unit, and production from the pooled unit will keep the lease in force beyond its primary term, just as if the production were from each tract in the pooled unit. Production from wells on the pooled unit is allocated among the tracts in the unit, for purposes of paying royalty, on an acreage basis. If a tract in the unit comprises 25% of the total acreage in the pooled unit, then 25% of the unit production is allocated to that tract for royalty purposes, and the mineral owners in that tract receive their royalty on production from the pooled unit just as if 25% of the unit production were produced from the tract.

What happens, then, if the lessee has acquired oil and gas leases on only a portion of the minerals in a tract? Can the lessee include that tract in a pooled unit? If so, how are royalties paid to the owners of unleased minerals in that tract? Do the unleased mineral owners have the right to share in production from the pooled unit?

Yergin and Ineson cite the following evidence for their thesis:

-- Production of gas in the lower 48 states increased 15% from the beginning of 2007 to mid-2008 - an increase fueld mostly by shale gas discoveries, and an increase that is more than most other countries' total gas production.

-- Proven gas reserves have risen from 177 trillion cubic feet in 2000 to 245 trillion cubic feet in 2008, even though the U.S. produced nearly 165 Tcf during that time.

-- "At current levels of demand, the U.S. has about 90 years of proven and potential supply -- a number that is bound to go up as more and more shale gas is found."

Most of this new gas comes from shale plays, beginning with the Barnett Shale in North Texas, and including the Haynesville (Louisiana and Texas), Fayetteville (Arkansas), Marcellus (Pennsylvania and New York), and most recently the Eagle Ford in South Texas. Shale gas is made possible by use of horizontal drilling technology and newly developed hydraulic fracturing completion techniques.

In a related development, State Senator Wendy Davis, D-Fort Worth, has (for a second time) asked Lt. Governor Dewhurst to authorize a senate investigation of the environmental impacts of natural gas production in the Barnett Shale.  Preliminary results of testing conducted by the Texas Commission on Environmental Quality and a private study conducted by the Denton County town of DISH found elevated levels of benzene in the air near natural gas production facilities.  The TCEQ is conducting a third phase of air emissions tests in the area of the Barnett Shale, and expects to have a report by the end of the year. A fourth phase of the testing is scheduled for spring 2010. "We've had oil and gas development in Texas for a long time, but it was primarily in rurual areas," said Tony Walker, director of TCEQ's Dallas-Fort Worth Office. "Not it is in urban and in more populated areas. We're studying every aspect of gas production. We will look at the drilling and frcing process, condensate tanks, compressor stations, gas lines, valves and allother possible sources of emissions."