Oil and Gas Lawyer Blog

In a previous post I reported on the application of Devon Energy asking the Texas Railroad Commission to include in the new Field Rules for the Carthage (Haynesville Shale) Field a provision allowing it to drill horizontal wells across lease or pooled unit boundaries.  These new rules apply to wells drilled in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Shelby and Rusk Counties in East Texas. Devon asked that the rules provide what it calls a "default allocation method" for horizontal wells drilled across unit boundaries.The rule proposed by Devon reads as follows:

"Operators shall be permitted to drill and complete horizontal wells that traverse one or more units and/or leases as long as that operator has a lease or other mineral ownership right to produce from each such unit or lease. If such a well is not already subject to an agreement regarding the allocation of production, the following allocation formula will be presumed to constitute a fair and reasonable allocation of production from a well in this field and shall be utilized by the Commission in assigning acreage attributable to the separate units/leases traversed by the horizontal drainhole: an allocation of acreage and production to each of the units and/or leases traversed by and completed in the horizontal well based on the percent of said horizontal well from first take point to last take point that lies under each unit or lease."

The Commission concluded that it had no authority to adopt such a rule, because pooling is a contractual issue between private parties, and (except as provided in the Mineral Interest Pooling Act) the Commission has no right to impose allocations of production among different tracts penetrated by a horizontal well.

In its appeal, Devon argues that the Commission's refusal to adopt its proposed "allocation rule" is arbitrary and an abuse of its discretion, without a rational basis, discriminates against producers in the Carthage Field, and will result in the waste of oil and gas.

I believe that Devon has little chance of forcing the Commission to adopt its proposed "allocation rule." But if it is successful, it is certain that operators in the Barnett Shale and other shale fields now being developed in Texas will ask for a similar rule. Such a rule would have significant impacts on royalty owners and their rights to consent to pooling of their royalty interests.

 

Chesapeake Energy Corporation summarized its activities in the country's "Big 6" shale plays in its Operational Update issued on February 16. The report reveals the huge impact Chesapeake has had on shale plays from New York to South Texas.

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:

 

Continue reading "Chesapeake Shale Plays" »

The debate over the safety of hydraulic fracturing continues. The Environmental Working Group, a Washington-based non-profit environmental advocacy organization, has issued a white paper, "Drilling Around the Law," calling for fracking to be regulated under the Safe Drinking Water Act and to require public disclosure of chemicals used in frac fluid. The EWG claims that "companies that drill for natural gas and oil are skirting federal law and injecting toxic petroleum distillates into thousands of wells, threatening drinking water supplies from Pennsylvania to Wyoming." EWG claims that fracking has been linked to drinking water contamination and proeprty damage in Colorado, Ohio, Pennsylvania, Wyoming and other states, citing articles written by Abrahm Lustgarten in ProPublica, another non-profit organization.

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.

 

 

The Mayor of tiny Dish, Texas, north of Fort Worth, continues to stir up controversy with his claims of air pollution from oil and gas activities causing health concerns in his community. The mayor appeared at the RRC's January 12 open hearing. You can watch his testimony here (go to item 17 on the agenda). The mayor's appearance was prompted by an item placed on the agenda by Commissioner Michael Williams, which in turn had been prompted by a letter sent to the Commissioners by State Rep. Ron Burnam. Rep. Burnam's letter asked the RRC to place a moratorium on permits for wells in the Barnett Shale around Fort Worth until the Texas Commission on Environmental Quality (TCEQ) has finished its investigation of air quality in the area. In response, Commissioner Williams proposed that the Commissioners write a letter to the Texas Attorney General asking for a formal opinion whether the RRC has authority to issue such a moratorium. (Rep. Burnam has also asked the City of Fort Worth to issue a similar moratorium on well permits in the city limits.) I have written about the controversy concerning the town of Dish in a previous post.

Continue reading "Dish Mayor Calvin Tilman Testifies at Railroad Commission" »

The information below is from the Energy Information Administration.  Note the wide variation in City Gate and Wellhead Prices among different states:

 

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?

 

Exxon Mobil announced that it would acquire XTO Energy in an all-stock deal worth $41 billion. The acquisition is viewed as Exxon's decision to enter the domestic onshore gas shale play, which to date has been developed almost exclusively by independent producers. But the deal includes an exit clause in the event Congress passes legislation that would make hydraulic fracturing illegal or "commercially impracticable." Shale gas development would be impossible without hydraulic fracturing technology. Bills are pending in Congress (known as the FRAC Act) to subject fracturing to federal regulation under the Safe Drinking Water Act. The bills would require companies to publicly disclose the chemicals used in frac fluids. And U.S. Rep. Ed Markey, Dem. Massachusetts, said he would hold hearings in the House Energy and Commerce Committee to review the Exxon-XTO deal and to address environmental concerns about hydraulic fracturing.

Dish is a town of about 200 residents north of Fort Worth, Texas. The mayor and town council have recently become concerned about emissions from gas compressors in and around the town, from the Barnett Shale gas development. Large compressor stations are located near Dish; these stations have big internal combustion engines that compress gas to move it through gas transmission lines in the area. The town hired an environmental firm, Wolf Eagle Environmental, to conduct air quality tests and has complained to the Texas Commission on Environmental Quality. The small community has now become the focus of the larger debate over the impact of Barnett Shale wells on air quality in the Dallas-Fort Worth area and the impact of oil and gas drilling and production activity on the environment generally.

 

Continue reading "Tiny Town of Dish, Texas Stirs Up Hornet's Nest Over Air Pollution in Barnett Shale" »

On December 15, the Railroad Commission adopted new field rules for a newly designated field, the Carthage (Haynesville Shale) Field, in East Texas. It also consolidated several previously designated fields in East Texas that produce from the Haynesville and Bossier formations into this single RRC-designated field. These rules will govern the development of the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Rusk and Shelby Counties in East Texas. These new rules are important to landowners principally because they will give operators a basis to form pooled units of up to 640 acres or more for development of the field.

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.

Continue reading "Texas Railroad Commission Adopts New Temporary Field Rules for Carthage (Haynesville Shale) Field" »

State Representative Lon Burnam, Dem. Fort Worth, asked nine questions of the Texas Commission on Environmental Quality concerning its investigations of emissions of methane and volatile organic compounds from oil and gas operations in the Barnett Shale area and in Texas in general. Recent air quality tests by private companies for local towns in the Fort Worth area have created a stir and caused some to call for increased monitoring and additional testing of emissions from oil and gas operations. Rep. Burnam has also called for the City of Fort Worth to place a moratorium on issuing permits for drilling until additional testing has been done. A group of concerned citizens has formed the North Central Texas Communities Alliance, to press for a moratorium in the DFW area until environnmental and other concerns are addressed.

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

Continue reading "TCEQ Answers Rep. Lon Burnam's Questions on Investigations of Air Quality" »

Twenty-two U.S. House Democrats from Texas, Louisiana, Oklahoma, New Mexico, Arkansas, Utah and Idaho delivered a letter to Environmental Protection Agency Director Lisa P. Jackson, cautioning the EPA to do a "reasonable and transparent study" of whether hydraulic fracturing of wells creates risks to drinking water. EPA is required to study whether hydraulic fracturing creates risks to underground sources of drinking water under the 2010 Appropriations Act for the Department of the Interior. The producing-states Congressmen want to be sure that the EPA's study is scientific, systematic, transparent, accurate and valid.

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.

 

The International Energy Agency (IEA) issued a forecast of world energy consumption and use, and for the first time included a scenario projecting the impacts of taking steps to stabilize greenhouse gases in the atmosphere at about 450 parts per million by 2030. This "450 Secnario" would limit overall temperature increases to 2 degrees C., versus a rise in global temperature of as much as 6 degrees if no efforts to curb carbon dioxide are made. The report compares this 450 Scenario to its "reference scenario," its projections of energy production, prices and consumption assuming no policy changes are enacted.

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.

I have recently received several inquiries about the rights of unleased mineral owners whose tract is included in the boundaries of a pooled unit. There seems to be some general miss-perception about this issue. 

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?

Continue reading "Pooled Units and Unleased Mineral Interests" »

A new website, Mineral Rights Forum, provides information and discussions about topics of interest to mineral owners. It is owned by Kenneth DuBose and is run by Peter Moorman.  Looks like it will be a good resource for mineral owners. It reports on a recent documentary, Split Estate, that investigates conflicts between surface owners who do not own the underlying minerals and oil and gas companies. It has been shown on Planet Green, an independent cable channel, and will be shown again in January. Here is the movie trailer. According to the Huffington Post, a representative of the Colorado Oil and Gas Commission, Kathy Hall, resigned recently after being shown in the movie saying that fracing fluid was harmless and she had had it in her mouth with no ill effects.

This video was done by the American Petroleum Institute to illustrate the modern techniques used in the drilling, fracing and completion of a horizontal well.

In a recent Wall Stree Journal article, "America's Natural Gas Revolution," Daniel Yergin and Robert Ineson opine that gas produced from shale "is already changing the national energy dialogue and overall energy outlook in the U.S.--and could change the global natural gas balance." Mr. Yergin is the author of "The Prize: the Epic Quest for Oil, Money, & Power" which won him a Pulitzer Prize.  He is now chairman of IHS CERA.  Mr. Ineson is senior director of global gas for IHS CERA.

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.

 

Continue reading "Shale Gas - an American Revolution?" »