Articles Posted in Oil and Gas Law

As we’ve seen time and time again, at least in Texas, state government is in the best position to regulate the energy industry in areas such as hydraulic fracing. Texas has done a good job of using its laws and its court system to deal with the issue in a reasonable and sensible way, promoting the oil and gas industry for economic growth and energy independence while also making sure Texans, their property rights and their environment are safe.

North Dakota Senator John Hoeven’s new bill is a welcome move in Washington for those of us working in oil and gas law. Senator Hoeven, who is on the Senate’s Energy and Natural Resources Committee, is calling it the Empower States Act. He told reporters in Bismarck, North Dakota that “(t)he legislation also recognizes that states have a long record of effectively regulating oil and gas development, including [fracing], with good environmental stewardship.” He went on to assert that “(w)ith the right policies, I believe we can get our country to energy independence in five to seven years.”

Senator Lisa Murkowski of Alaska immediately signed up to cosponsor the bill. “Senator Hoeven’s bill provides for local accountability, local knowledge, and local communication instead of a one-size-fits-all federal approach to regulation” Senator Murkowski said while she was in North Dakota for a two day tour of the technological advances used in the Bakken shale region. She said that it “makes sense” to let the states take the lead on regulations in oil and gas development.

There is good news for anyone wanting to make a career in the growing field of gas development! This year, after more than a dozen years, students will be able to study for a degree in natural gas engineering at Texas A&M University, Kingsville.

When the university’s engineering program started in the 1930s, this natural gas degree was among the first introduced by Frank Dotterweich, a former dean and now the namesake of the engineering school. For most of the 20th century, countless engineers graduated with this degree and went to work in the oil and gas industry. As the Kingsville university president said, “We were internationally famous for that program.” But it started to become less popular in the 1990s when fuel prices were very low and led to a weak market for job seekers. Texas A&M suspended the degree in 2000, but still kept a graduate degree in the area for those wishing to specialize.But things have changed, and now Texas is in the middle of an energy boom, which is especially advantageous for the Kingsville campus of Texas A&M because of its proximity to the Eagle Ford shale. The boom in natural gas industry jobs have created renewed interest in getting this type of engineering degree. And the fast pace of technological advancement in this field has increased the need for well educated professionals who are able to use the specialized technologies that gas production uses today. There is also a need for people who know how to design pipelines to take natural gas to the market, and at the moment there is a void of qualified candidates. Currently, many companies are training engineers from other fields in gas and gas pipeline engineering themselves.

By January 2112, the Texas A&M was getting at least five calls a week inquiring about a degree in natural gas engineering. Former students and also energy industry groups took the initiative to push for the return of this degree option, which was approved by the Texas Higher Education Coordinating Board in June 2112. Stephen Nix, the current dean of the Dotterweich College of Engineering said, “We are certainly excited to offer this type of opportunity for students in South Texas.”

Texas gas retailers are in for a tough time. The federal Court of Appeals for the DC Circuit ruled earlier this year in favor of the Environmental Protection Agency (EPA) on a challenge to the introduction of a higher corn ethanol blend in gasoline. The new higher blend would contain 85% gasoline and 15% ethanol, and is nicknamed “E15”. It is an increase over the old 10% ethanol standard. The EPA approved this new blend in 2011 for cars and light trucks made since the model year 2000, but banned it for light equipment and older vehicles. Bio-fuels makers sought the higher blend rate as a way to satisfy a federal guarantee of a share of the gasoline market, set at 13.2 billion gallons in 2012 and rising to 15 billion gallons annually from 2015. The EPA gave its final regulatory approval of E15 in June 2012.

In the legal challenge before the DC court, food businesses claimed that E15 would raise the price of corn. Governors from four poultry-raising states asked the EPA for relief from this E15 mandate because of its impact on feed. The worst drought in 50 years has seen the corn crop decrease by 13% this year, and the governors say that this crop is too small to withstand 40% of it being used in fuel without a severe economic disruption.The engine manufacturers claimed they could be open to liability if their engines malfunctioned due to the new fuel blend. Charles Drevna, the president of the American Fuel & Petrochemical Manufacturers, and Bob Greco, a director at the American Petroleum Institute, both claimed that E15 approval comes before testing of E15 in vehicles is complete and that it has already been shown to cause damage to engines. Vehicle manufacturers are already putting warnings on their gas caps that using E15 could void their vehicle warranties.

The opinion of the three judge panel on the DC Court of Appeals ruled two to one that the petroleum industry, engine manufacturers and the food industry did not have legal standing on the matter. The Court stated that these industries failed to sufficiently demonstrate how they were harmed by the approval of E15. Critics find this astonishing, especially for the petroleum industry, which is required to comply with the federal mandate on ethanol in the 2007 Energy Independence and Security Act.

A few recent cases involving Chesapeake Energy Corporation backing away from potential oil and gas leases are raising alarms. Obviously a contract is only as good as its enforceability. It goes without saying that landowners need to be diligent so that they are not taken advantage of by large oil companies. Many complex legal issues are involved in contract disputes, and experienced legal help is always crucial. For example, in one case from earlier this year, Kantner v Chesapeake Energy Corp., a Texas Court of Appeals found that individual landowners lacked standing to bring a breach of contract claim when the contract was between Chesapeake and a landowners committee.

In this particular case, the plaintiffs were owners of property in Deer Creek Estates in Crowley, Texas. In 2007 and 2008, a Deer Creek Estates Residents Oil and Gas Lease Committee was formed to negotiate oil and gas leases with Chesapeake. The Committee and Chesapeake negotiated and agreed to two documents, a Supplemental Agreement Regarding Gas Leases and a “form lease.” However, the Committee did not have the authority to bind any of the landowners to the terms of either document. The form lease actually stated that none of the landowners were required to sign it, allowing each landowner the right to negotiate his or her own lease.

Because of its own financial issues, Chesapeake decided not to proceed with leases in Deer Creek Estates, and the landowners sued for specific performance of what they claim was a contract negotiated between their Committee and Chesapeake. The documents negotiated by the Committee provided for a $27,000 per net mineral acre signing bonus, a 25.25% royalty, and a three year term with no renewal option. The signing bonus was to be paid by a thirty day bank draft at signing.

The United States Geological Survey (USGS) released a new estimate last week on the US’s oil and gas reserves. The new estimate for 2012 is part of the Reserve-Growth Assessment Project. It found 32 billion barrels of crude oil, 291 trillion cubic feet of natural gas, and 10 billion barrels of natural gas liquids as potential undiscovered US reserves. The USGS estimate stated that these amounts represent about 10% of the overall US oil and gas endowment and do not include reserve growth estimates for federal offshore areas.

Most reserve growth results from the delineation of new reservoirs, field extensions, improved technology that enhances efficiency, and recalculation of reserves due to shifting economic and operating conditions. For this estimate, fifty-five large oil fields and thirty-five large gas fields significantly contributed to the reserve growth. Within the fifty-five oil fields, sixty-eight individual conventional accumulations (i.e. reservoirs or groups of reservoirs) were identified and assessed. In the gas fields, two accumulations were individually assessed. The sixty-eight individually assessed oil accumulations accounted for seventy percent of the potential reserve growth in the United States. The other thirty percent is from smaller accumulations estimated by the regression methods.

The estimate noted that no attempt was made to gauge economically recoverable resources, so resources such as shale gas, tight gas, tight oil, and tar sands were not included in the USGS’s study. The USGS used detailed analysis of geology and engineering practices, which departs from the methods of previous reserve growth estimates which relied entirely on statistical extrapolations of growth trends. The USGS used both public and commercial geologic information and field production data.

The Denbury case was one of the most important developments in Texas oil and gas law in the past year, and this blog reviewed the March, 2012 Texas Supreme Court ruling here. In summary, the Denbury case involves a landowner who objected to a private energy company’s use of the eminent domain statute to appropriate his land for a gas pipeline. The Court found for the landowner.

The decision in March not only denied Denbury Green Pipeline‘s motion for a rehearing, but also clarified the Court’s original opinion (see my post here) in several respects. The Court added that “private” means a pipeline that is limited in its use to wells, stations, plants, and refineries of the owner. The Court went on to say that a “common carrier” means that the company is transporting gas for hire and therefore implies more customers for the gas than just the owner of the pipeline. The Court upheld its view from the prior ruling that the Denbury pipeline was for private use only.

In August, the latest decision by the Texas Supreme Court ruling in Denbury was issued, written by Justice Wainwright with Justice Johnson concurring. The two justices joined the main decision issued in March and reaffirmed that simply checking a box on a Texas Railroad Commission form is not sufficient to make a company a “common carrier” under the law. However, they issued this separate opinion to distinguish their views on the scope of the Court’s holding.

A new report by IHS Inc., a global information and analysis company, states that Eagle Ford in South Texas is a contender for the best tight oil play in the US. This is based on strong drilling results, a large prospective area and the magnitude of the resource potential.

At the moment the number one position is held by the Bakken formation, located in North Dakota, Montana, and Saskatchewan. Bakken has been number one because it opened up development of unconventional resources using high-tech drilling methods and hydraulic fracturing. Andrew Byrne, the director of equity research at IHS and the author of this study, said “The results from the Bakken were so strong that it set the standard by which all others will be measured. It was the one play that incited the industry into pursuing these opportunities.” But now that title is shifting to Eagle Ford.

The study looked at 27 tight oil plays and assessed the emerging and mature tight oil plays in North America which have the largest impact on investment patterns and North American oil and gas supplies. The study is intended to help clients estimate the resource potential and recoverable hydrocarbons of each play. It’s also meant to help clients understand performance metrics and future supply potential and establish metrics to compare the performance and value of each play. The study enables clients to determine play strategies, determine potential partners and merger and acquisition strategies, and also to develop analogs for global tight oil potential.

A report of the US Energy Information Administration issued within the past few months indicates that horizontal drilling and hydraulic fracturing in shale have helped US and Texas oil and gas reserves grow at a record pace in 2010. This was the biggest single year increase since the organization began publishing oil and gas reserve estimates in 1977. These figures identify how much oil or natural gas can be produced with reasonable certainty, given current economics and existing technology.

The EIA Report stated that domestic crude and condensate proved reserves rose by 2.9 billion barrels, from 22.3 billion barrels in 2009 to 25.2 billion barrels in 2010, which is an increase of 12.8%. The wet natural gas proved reserves rose by 33.8 trillion cubic feet, from 283.9 trillion cubic feet in 2009 to 317.6 trillion cubic feet in 2010, an increase of 11.9%.

EIA Administrator Adam Sieminski told the US House Energy and Commerce Subcommittee last week that the increasing ratio of oil to gas prices in the US had led oil producers to focus on liquid-rich areas in 2010. The trend has continued for 18 months after that. In other words, higher oil and gas prices make drilling more profitable and increase production.

A Houston company, Crimson Exploration Inc., has provided an update on its successful operations in east Texas, including Woodbine, Eagle Ford and other programs. This is important information for the growth of the oil and gas industry in Texas, a crucial component to economic growth and energy independence.

Crimson has 18,500 acres in the Woodbine section that cover three areas the company refers to as Force, Iola-Grimes, and Chalktown. In these areas, the company has been developing the Woodbine, and production tests have confirmed the oil potential in all three areas. Crimson has identified 115 potential drilling locations. Assuming the average output is an ultimate recovery of 400,000 BOE (barrell of of oil equivalent) per location, with 90% oil and natural gas liquids, total net potential exceeds 34 million BOE. That is five times the average for Crimson in 2011.In the Force area, in Madison County, 50 wells have completed since January 2009 using modern horizontal drilling and fracture simulation completion techniques. These wells have had initial rates of 600 b/d of oil. The first two producing Crimson wells initially averaged over 900 b/d of oil, and the area is considered substantially derisked. In Crimson’s first horizontal Woodbine well in this area, the well produced 128,000 barrels in its first four months.

Crimson has 5,100 net acres in the Chalktown area in Madison County as well. It is testing the Lewisville sand, a lower Woodbine objective that has produced vertical wells in the area. One of the wells there is producing extraneous water, possibly from a natural fracture. The company is working to shut off the source of the water to better test the oil potential.

Another study, entitled “Review of EPA Hydraulic Fracturing Study Plan“, is questioning the validity of the Environmental Protection Agency’s (EPA) data on hydraulic fracturing (“fracing”) and drinking water. The impact of fracing on drinking water has been a hot political topic for a while now, and more and more scientific studies are showing that the EPA’s data is either overblown or just plain wrong.

The Battelle Memorial Institute, a non-profit science and technology research and development organization, released a study recently concluding that the EPA did not define important quality requirements in its study process. The EPA used its discretionary authority to broaden its study significantly beyond what Congress requested in fiscal year 2010, which was originally only to include fracing and drinking water. Instead the EPA reached beyond, encompassing numerous peripheral elements related to oil and gas exploration and production activity, including various upstream and downstream stages of the water life cycle, site preparation and development, and standard oil and gas production and other industrial activities. The Battelle study stated that a broader study increases complexity and risk. Battelle warned that ambitious schedules, driven by various 2012 reporting goals, could make data collection and analysis less robust and thus scientific conclusions less sound. It also noted that site data collected during 2006 to 2010 could become obsolete by the time the EPA issues its final report in 2014.

The Battelle study was commissioned by the American Petroleum Institute (API) and America’s Natural Gas Alliance (ANGA) due to concerns about the direction of the EPA study. Stephanie Meadows, API upstream policy senior advisor, said, “Battelle’s analysis of the plan for EPA’s study reinforces many of our previously stated concerns about the study and raises new ones. It finds deficiencies in the rigor, funding, focus and stakeholder inclusiveness of the plan.” She told reporters that API and ANGA intend for Battelle’s report to help EPA produce “the most scientifically sound study possible” and hopes that this study can encourage the EPA to make sure their final report is done right.