Articles Posted in Oil and Gas Law

Oil and gas pipelines in Texas and throughout the country are needed to bring oil and gas to refiners and to markets, and result in cheaper fuel prices for consumers by lowering transportation costs. With the oil and gas industry flourishing, particularly in areas of the country like Texas, more pipelines are needed to transport increasing amounts of these raw materials. Without enough pipeline capacity, producers have to use trucks, barges, and trains to move oil, gas and condensate to refiners and to the market–all of which cost more than pipeline transport. There are numerous pipelines in the works right now. However, some of these pipelines are still subject to financing issues and face challenges with government approvals (such as with the high-profile Keystone pipeline project).

On the financing issue, the Association of Oil Pipelines (AOPL) has requested that the Federal Energy Regulatory Commission (FERC), the agency that oversees interstate oil pipeline tariffs, step in to fix a dispute that AOPL claims may impair the financing of new pipelines. Financing of pipelines often relies on secured revenue accrued after the pipeline is completed. This is accomplished through contracts setting the rates ahead of time for the delivery of crude oil, gas, condensate, diesel, and other products. Andrew J. Black, President of AOPL, said earlier this month that “(t)hese committed rate agreements give confidence to shippers that the infrastructure they need to deliver their production to market will be there when they need it. They also give confidence to companies and investors ready to fund new pipeline projects that their investments will be repaid.”

The problem has arisen in an ongoing pipeline case being considered by FERC, which includes testimony threatening the mutually beneficial rate contracts agreed upon by energy suppliers and pipeline companies. The case involves the Seaway Pipeline, which goes from Cushing, Oklahoma, to Houston, Texas and is expected to carry 150,000 barrels of crude oil per day initially. AOPL filed a motion asking FERC to confirm its rate contracts and to rule that the contracts are not subject to review during the pipeline’s future rate proceedings. Instead, FERC staff recommended a new rate and rate structure, throwing out the old agreements which were the basis for financing this pipeline. AOPL responded that this action could not only deter new pipeline projects, it could also bring a halt to pipelines currently under construction.

In a significant win for reasonable and sensible energy regulation, the DC Circuit Court rejected the Environmental Protection Agency’s (EPA) 2012 cellulosic biofuels projection. It is sad that this is what passes as a “win” for the energy industry however, since the Court simply acknowledged that the EPA’s requirements are based on fiction and require supplies of materials that are not even available currently!

The case being decided involved a challenge by the American Petroleum Institute (API) to the EPA’s regulation. The regulation in question was adopted under the renewable fuel standard program, which requires refiners to blend 36 billion gallons of biofuel with traditional fossil fuels by 2022. That goal has incremental targets leading up to it, and by 2012 refiners were required to blend 10.45 million biofuel ethanol gallons with their gasoline– an impossibility considering that the entire industry only produced 22,000 gallons of biofuel last year. API argued that these rules forced refiners to buy “credits” for the cellulosic biofuel since this product does not not, and may never, get produced in sufficient quantities to comply with the EPA regulations. API fairly asserted that the EPA should base the biofuel requirement on a realistic assessment of current production levels.

The decision, written by Judge Stephen Williams, stated, “We agree with API that because EPA’s methodology for making its cellulosic biofuel projection did not take neutral aim at accuracy, it was an unreasonable exercise of agency discretion.”

More advocates are spreading the message that the energy industry can help our county work though not only its energy needs but its budget shortfalls and economic problems as well. US Chamber of Commerce President Thomas J. Donohue noted in his 2013 State of American Business address that developing American energy can help our fiscal problems, including reducing the trade deficit and bringing more manufacturing jobs back to the US.

He said that he has already seen indications that lower gas prices are attracting businesses back. Donohue stated that to take advantage of these opportunities, more federally controlled land, both on and offshore, must be opened for exploration and development with a predictable and fair regulatory system in place. He also encouraged further development of alternative energy sources, such as nuclear, wind, geo-thermal, and solar. Donohue asserted that the Chamber’s top priorities for 2013 remain creating jobs and increasing economic growth. He said that “(w)e must get this economy moving faster. Growth of 1.5% to 2% is not acceptable.”

Donohue and the Chamber of Commerce are not the only ones optimistic about renewed growth in US manufacturing. Fitch Ratings analysts issued a special report called “Shale Boom: A Boost to Manufacturing but Not to Energy Independence” earlier this month. It states that low gas prices provide an advantage for some industries, including steel, petrochemicals, and other high-energy industries, as well as (to a lesser degree) copper, aluminum, and cement. Shale gas is providing the lower costs that allow this comparative advantage, particularly due to the expanded use of increasingly efficient hydraulic fracturing. The current utilities gas price is $2.50/ mcf, down tremendously from the 2008 average of $8/ mcf. The advantage is most notable in petrochemicals, because natural gas is both an ingredient in the products made by this industry as well as a source of energy to manufacture products. The report states it “appears to be a permanent advantage” in this industry and that America’s gas-run petrochemical industry is more efficient and competitive than Europe’s oil-based industry.

It seems there is an ongoing supply of positive developments in the natural gas field in Texas that are poised to make our country more energy independent. Currently, almost all the fuel used to power hydraulic fracturing is diesel. Hydraulic fracturing is credited with much of the recent dramatic increases in Texas and US oil and gas production, but the industry required more than 700 gallons of diesel last year for this purpose at a cost of about $2.38 billion. If they could use natural gas, it would save the industry up to 70% and would allow the US to import 17 million fewer barrels of oil each year. There is a viable process in the works to make that possible.

Apache Corporation, with headquarters in Houston, Texas but that operates internationally, decided this was worth pursuing. Mike Bahorich, the vice president of technology, reached out to Halliburton and Schlumberger. Both companies told Mr. Bahorich that using natural gas to power hydraulic fracing was possible, but has not been due to the complexity of both the natural gas supply and the infrastructure. Both companies also told Apache that they would do a trial for Apache without cost.

So far, Halliburton is testing with liquefied natural gas. Its new system would build a simple gas line to the necessary engines by using a quick-connect jumper and would also allow for moving the line easily from job site to job site. Schlumberger is testing with compressed natural gas.

There is new reason to be energized (excuse the pun!) about Texas’ oil and gas industry in 2013. The last several years have been exciting in this field, and Texas has benefited from its substantial natural resources. Now recent reports indicate that oil and gas companies will spend $28 billion in the Eagle Ford shale play alone in the coming year. That money will infuse the Texas economy, create many new jobs and send billions of dollars in tax revenues to local and state government.

The Eagle Ford is the second largest tight oil play in the United States. It is fifth in the country for shale gas production and is projected to account for 15% of US onshore oil production. North Dakota’s Bakken field is still the largest unconventional oil producer. Wood Mackenzie, an energy industry research and consulting firm commonly called “WoodMac”, studied and analyzed the trends to calculate these numbers for the Eagle Ford. Callan McMahon, an upstream analyst, asserted that the Eagle Ford continues to exceed analyst expectations.

The Eagle Ford has already shown impressive growth, going from 100,000 barrels per day of liquids such as natural gas in early 2011, to 700,000 barrels per day by December 2012. This dramatic increase is, according to WoodMac, due to technology and expertise. A lot of the money spent in the Eagle Ford this year will come from three major operators: EOG Resources, BHP Billiton, and ConocoPhilips. All three were early to focus on Eagle Ford’s liquids-rich areas, and have been rewarded. The Eagle Ford represents 38% of EOG’s upstream value, and 20% of BHP Billiton’s upstream value. According to WoodMac, in resource plays the key is core acreage. This certainly seems to hold true in the Eagle Ford. Most operators are realizing the quality of their acreage just recently. The leading companies, like the three above, not only hold core acreage positions but also own large numbers of acres in the key areas. Smaller companies are also getting in on the action by using joint venture and cost carry agreements to maximize their value per acre.

A few months ago, the nonprofit organization Resources for the Future sponsored a seminar entitled “The Future of Fuel: Toward the Next Decade of US Energy Policy.” The seminar highlighted the future of five key fuels over the next decade–oil, coal, natural gas, renewables, and nuclear–as well as the future of energy efficiency. The opening remarks were presented by Phil Sharp, president of Resources for the Future. Kristin Hayes, a Center Manager for Resources for the Future, moderated the event and Michael Schaal of the federal Energy Information Administration gave a presentation on energy projections.

One of the speakers was Alan Krupnick, a senior fellow and director of the Center for Energy Economics and Policy at Resources for the Future, who asserted that restricting carbon emissions could significantly slow growth in US shale gas production.

He said, “Fugitive emissions are the biggest issue, and if they are considered too high, it could reverse the potential gains.” He noted that most regulation of shale gas comes at the state level, so it can vary widely across the country. Even states with a long history of oil and gas production, like Texas, are still working out the kinks with some local governments.

The rights of Texas mineral owners can be complicated, which is why having a Texas oil and gas attorney review your options is important before you sell or lease your mineral rights or before you buy property in which you will own only the surface.

In many cases, a property owner owns both the surface and the minerals below the surface. However, it is possible to split the ownership, so two different persons or entities own the surface of the land on one hand and the minerals beneath it on the other. In Texas, the owner of the mineral rights has a right to the reasonable use of the surface to produce or extract the minerals, without the permission of the surface owner.

This is where the Texas accommodation doctrine comes in, which is an area of law that is still evolving in Texas. The Texas accommodation doctrine cases hold that, in some cases, the owner of the mineral rights must accommodate the surface owner’s pre-existing surface uses, so long as other means of production or extraction of the minerals are available. It is important to note that this doctrine applies only to the existing surface uses, not possible future uses by the surface owner.

Congress is considering whether to eliminate or limit a federal tax deduction for intangible drilling costs. Intangible drilling costs are those costs incurred to develop an oil or gas well other than the costs of the actual well. It includes costs such as surveying, clearing the land for a well pad or storage tanks, drainage modifications, fuel, and workers’ wages. Current US tax law allows oil and gas companies to deduct these operating expenses from their taxes, exactly like other businesses deduct the intangible business expenses incurred in operating their business.

Understandably, the oil and gas industry is quite concerned about the potential elimination of this deduction. Elimination of this deduction would effectively make exploration, drilling and production of oil and gas more expensive. That means that there will be less exploration, drilling and production in Texas, as well as in other states. In turn, that means that some number of Texas mineral owners who hope to lease their minerals, and who may really need the royalty income, may lose that opportunity.

A coalition of 33 national, regional and state oil and gas associations sent a letter to the leaders of two key congressional committees, the House Ways and Means Committee and the Senate Finance Committee, who are dealing with this issue. Groups who signed the letter included the American Exploration and Production Council, or AXPC, the American Petroleum Institute, the Independent Petroleum Association of America and the Western Energy Alliance, as well as ten other national and two other regional associations and 17 state organizations, including some from Texas.

During all of the budget talks in Washington, DC, I was interested to read a recent report entitled “CO2 Enhanced Oil Recovery” by the U.S. Chamber of Commerce regarding how enhanced oil recovery (“EOR”) techniques could add significant revenue to the Texas and federal budget, as well as enhance our energy security and benefit the environment!

Enhanced oil recovery is a general term that refers to techniques for increasing the oil that can be extracted from a given oil field. The type of enhanced oil recovery technique discussed in this report is carbon dioxide recovery. It works by pumping carbon dioxide into the reservoir, and the gas improves the flow of the remaining oil. Once the oil-carbon dioxide mixture reaches the surface, the two are separated and the carbon dioxide is recycled back into the reservoir. The U.S. is already leading the world in this technique and it is providing nearly 6% of our onshore oil production.

The new report was written by the Chamber’s Institute for 21st Century Energy. The report notes that the U. S. Department of Energy estimates that enhanced oil recovery could produce 67 billion barrels of oil, which is three times the size of the U.S. current proven oil reserves. If the price is $85/bbl, $1.4 trillion in new government revenue would result directly from these procedures, in addition to billions in private investment.

Recently, NuStar Energy LP announced that they are proposing a new system of oil pipelines to bring oil from the Niobrara Shale in Colorado to Texas’s oil refineries. The Niobrara Shale is a promising play and there is a need to get the oil produced there to refineries that can process the increasing amount of oil. Colorado is set to produce between 42 and 44 million barrels of oil this year, in a growing industry for the state. NuStar is calling this new pipeline project the “Niobrara Falls Project.”

The new pipeline would extend from Niobrara, which is near Platteville and Watkins, to an already existing pipeline in Denver. From there the oil would be transported via Denver to a McKee, Texas pipeline, which has a capacity of about 70,000 to 75,000 barrels per day. From McKee, the project would utilize other existing pipelines to get the oil to refineries in Wichita Falls, Texas. NuStar states that once the oil gets to Wichita Falls, it can be sent to the Nederland-Beaumont, Texas market and the Cushing hub via other third-party pipeline connections in Wichita Falls. This pipeline could also supply refineries such as Suncor Energy’s Denver refinery, Valero Energy’s McKee, Texas refinery, Ardmore, Oklahoma refineries, and WRB’s Bolger, Texas refinery. The new pipeline system could also transport oil from Granite Wash and Permian basin to Dixon, Texas, where NuStar has a tank farm.

To find out what kind of interest exists for this new pipeline project, NuStar held a binding open season the end of last year. A binding open season allows companies to make a long-term commitment to use the pipeline. Commitment terms of five, seven, or ten years are available for this project.