Texas Oil and Gas Attorney Blog

There is more evidence from yet another study, the “Hydraulic Fracturing Study“, published in October 2012, that concludes that hydraulic fracturing, or fracing, is safe and does not pollute either air or water or cause earthquakes. This study was prepared for Plains Exploration & Production Co., an independent oil and gas company, and the Los Angeles County Department of Regional Planning, and was conducted by Cardno Entrix, an international environmental and natural resource management consulting firm. The study examined two test wells at the Inglewood Oil Field in Los Angeles County, California, and determined that there were no detectible indications that fracing might induce earthquakes or have a negative impact on air or water quality.

The Inglewood Oil Field is one of the largest urban oil fields in the United States and is adjacent to Baldwin Hills, View Park, Windsor Hills, Blair Hills, Ladera Heights, and Culver City, California. The oil field was discovered near Culver City by Standard Oil in 1924. Plains Exploration has been operating there since December 2002, and conventional fracing has been used in the field by prior operators. The field contains 1,200 acres and a total of 1,475 wells have been drilled. 469 wells are in active production and 168 waterflood injection wells are active at this time.

The Cardno study was part of a settlement in 2011 of a lawsuit filed in 2008 against Los Angeles County and Plains Exploration over land use. Schlumberger Ltd. and Pinnacle, a company owned by Halliburton, did the micro-seismic monitoring and fracture mapping. Plains Exploration also did a high-rate gravel pack job at two different wells earlier this year to help collect information for this study. The study concluded, in part, that: “(t)ests conducted before, during, and after the use of hydraulic fracturing and high-rate gravel packing showed no effects on the integrity of the steel and cement casings that enclose oil wells. There is also an ongoing program of well integrity tests at Inglewood oil field.”

American Petroleum Institute‘s Chief Economist John Felmy has warned policymakers that unnecessary duplicate regulations could obstruct the development of unconventional oil and gas plays in the US. He pointed out at a news conference in Washington, DC that these plays have already created jobs and helped improve economic conditions in many areas of the country.

Mr. Felmy restated API’s position that regulation by state agencies is best suited for shale development and techniques like hydraulic fracturing, or fracing. He particularly noted the “North Dakota Miracle,” which turned that state into the number two oil producer in the nation and reduced unemployment to three percent while increasing incomes overall. He also highlighted other successes in states such as Texas, Arkansas, Ohio, Pennsylvania, and Louisiana. API and the industry are getting involved in states to raise awareness about the economic benefits of shale, including doing workshops in shale states. API has also issued fracing best practice guidelines, which can be helpful for a discussion of safety standards and industry safeguards. These standards include information about well construction and integrity, water management, mitigating surface impact, environmental protection, and isolating potential flow zones during well construction.

Aside from these statements regarding state regulations, Mr. Felmy also spoke at a recent DC conference about the possibility that New York may lift its high-volume fracing ban. New York is home to part of the Marcellus Shale, and there is potential there for growth and development. Fracing has taken place in New York since the 1950s, and horizontal wells since the 1980s. Both are legal. But newer technology with high-volume fracing, which makes it possible to get to oil and natural gas that was unreachable before, has been banned since 2008.

Another company is increasing its presence in South Texas in the Eagle Ford Shale. Penn Virginia Corporation has increased its holdings by 4,100 net acres in Gonzales and Lavaca counties for $10 million. This brings the company to 31,000 net and 41,100 gross acres in the Eagle Ford. In Gonzales County, the new 3,200 net acres is adjacent to Penn Virginia’s development area and is estimated to have 20 horizontal well locations. The 895 net acres in Lavaca County is complimentary to existing Penn Virginia locations in nine units, with an estimated additional 10 horizontal well locations.

This activity is bringing an economic boom to South Texas. The Railroad Commission of Texas has issued an estimated 4,293 drilling permits for the Eagle Ford in 2012 alone. This has brought jobs to a region that long suffered from double digit unemployment and poverty.

“If you’re looking for a job, this is the place to be. If you want to relocate, this is the place to be,” said Diane Laplow of San Antonio. There were 48,000 new jobs created by activity in the shale last year. Aside from working directly in the oil and gas industry, this boom is bringing opportunities for small business as well, creating many jobs in other sectors of the local economy. For example, people are opening family businesses, like restaurants, to feed hungry oil workers. “It’s a very good spot to start a business,” said Sarah Cadena, a native of the area whose family now owns a burger and wings joint on a busy highway.

Sanchez Energy Corporation, a fast growing independent oil and gas company based in Houston, Texas, announced recently that it will accelerate its 2012-2013 drilling in the Eagle Ford shale play. This shale play covers 11 million acres from the Mexican border in South Texas to East Texas near Louisiana and covers 1/16th of the state of Texas. It has a unique geologic composition that allows for more production of oil and gas than other shale areas, and it is an excellent candidate for the use of hydraulic fracturing, or fracing.

Sanchez has a 95,000 net acre position in Eagle Ford, and the corporation is gathering cash from proceeds from a recent private placement of preferred stock, using the $144.6 million in proceeds to fund capital expenditures. Those expenditures focus on accelerating the drilling program across all Eagle Ford operating areas. Tony Sanchez, III, President and CEO of Sanchez, said, “Our recently closed $150 million convertible preferred offering, combined with our future cash flow from operations and modest debt from our anticipated credit facilities, provides the liquidity to continue executing and accelerating our drilling plans in 2012 and 2013.” In addition, the company will close shortly both a $250 million first lien revolving credit line, with an initial borrowing base of $27.5 million, and a second lien loan also of $250 million, with an initial commitment of $50 million, to provide more cash for the Sanchez expansion of operations.

With the money it has raised, Sanchez can grow and expand-the company has already identified 800-1200 potential drilling locations. Production has grown more than 90 percent just since the end of June, 2012, with 2300 barrels per day of oil equivalent being pumped by the end of August, 2012. The company sees a rate of 4000 to 5000 barrels of oil equivalent per day by the end of 2012, due to the more developmental-type drilling planned.

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.