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The Texas oil and gas industry has had a busy year. In June 2013 Kinder Morgan Energy Partners announced it was expanding its pipeline system into the Eagle Ford shale in Karnes County, Texas. This new pipeline project is the result of a long term contract with ConocoPhillips and will extend the already existing 178 mile pipeline another 31 miles from DeWitt County to ConocoPhillips distribution facility in Karnes County. Kinder Morgan also plans to build holding tanks and a truck unloading facility at ConocoPhillip’s site in Karnes County. The project began construction in July 2013 and the new section is expected to be operational by the third quarter of 2014, with a capacity of 300,000 b/d of crude and condensates.

summertime-wild-flower-meadow-1354218-s.jpg This news follows on Kinder Morgan’s announcement in May 2013 that it was expanding another pipeline to its refinery in Brazoria County. The original pipeline, part of the same pipeline system described above, went into service in June 2012 and brings Eagle Ford oil to Houston. That pipeline expansion is expected to start service by the end of 2013 and will increase the capacity to 100,000 b/d. Kinder Morgan indicated that it plans, as part of this project announced in May, to add new pumps and a storage tank in Wharton County, Texas, and offloading capabilities for trucks in DeWitt County.

In July, Exco Resources Inc. announced it was buying undeveloped oil and gas assets in Eagle Ford and also in the Haynesville shale from Chesapeake Energy Corporation. The purchased assets are located in Zavala, Dimmit, La Salle, and Frio counties in Texas, as well as some in Louisiana. Exco paid Chesapeake a total of $1 billion for these oil and gas assets.

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A new gas pipeline is planned through Texas to bring natural gas to the Gulf coast. Two companies, Kinder Morgan and MarkWest Utica EMG, have entered a joint venture for a 1,100 mile gas pipeline and to develop a fractionation plant on the Gulf coast. The facility and pipeline will process and transport liquid natural gas from the Utica and Marcellus shales in Ohio, Pennsylvania, and West Virginia.

Kinder Morgan’s CEO Richard Kinder issued a statement that “(t)he combination of Kinder Morgan’s strategically located and existing pipeline assets that traverse through the heart of the Utica and Marcellus shale plays, along with MarkWest’s existing and significant midstream footprint throughout the Utica and Marcellus shale plays, should provide significant growth opportunities for the (joint venture).”

A gas complex is planned to be built in Tuscarawas County, Ohio. The complex, on a 220 acre piece of land for which Kinder Morgan has an option, will have a 400 million-cubic-foot-per-day (MMcf/d) cryogenic processing facility. It can be expanded to accommodate one billion cubic feet per day. The first processing plant is expected to be completed by the fourth quarter of 2014. The companies are also exploring options to increase fractionation capacity in the Gulf region. MarkWest is planning to install a de-ethanization plant in its Seneca complex as well, after starting up a de-ethanization plant in Houston, Pennsylvania in July 2013. MarkWest is also expanding a gas processing plant at Mobley in West Virginia, as well as expanding at other facilities in Pennsylvania and West Virginia.

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Recently, Chevron‘s Chief Executive Officer John S. Watson spoke at the Center for Strategic and International Studies and addressed the issue of whether the current boom in the oil and gas industry could serve as an opportunity for sensible energy policy reforms by the federal government. His suggestions included reforming the federal tax code, increasing access to public lands, and more rational environmental policies.

In terms of environmental policies, Mr. Watson pointed out that these policies must be transparent and honest, discussing the controversial Renewable Fuel Standard which currently requires biofuels that can’t yet be produced. As far as the future of biofuels, he told the CSIS that, “We haven’t cracked the code yet, but we’re working on it. Renewables have their place, and they will grow. But right now, $500 billion of subsidies support them around the world. We have to make them affordable.” Mr. Watson also touched on carbon emissions on an international level, saying that wealthier economies might withstand the higher prices from carbon taxes by increasing efficiency, but this will not work with emerging economies, noting “[g]overnments want to feed and shelter their people, so their carbon use will grow.”

Mr. Watson also spoke optimistically about the energy industry as a whole, on a global scale. He said that right now, there are unprecedented opportunities to produce many different kinds of energy products, but it was crucial to have appropriate commercial terms and physical security. He said that Chevron’s key to working in countries around the world, in some cases for many decades, is sensitivity to the host government and to each country’s needs. He praised American companies like Chevron who are exploring and producing around the world, for their advanced technology and skills, but also for American values that Chevron tries to embody, such as environmental awareness, respect for the rule of law and transparency.

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There was an interesting decision issued last fall by the US Supreme Court regarding government land use control and regulation, an issue that is always significant in Texas. The case is Koontz v. St. Johns River Water Management District, and the opinion illustrates some important limitations on government land use regulations. The five to four decision, with the majority opinion written by Justice Samuel Alito, holds that in land use regulation, the government must show a nexus and proportionality between what the government demands of the landowner and the effects of the landowner’s proposed new use of the land. The decision underscores a landowner’s rights to challenge government decisions regarding land use on a constitutional basis.

In this case, Mr. Koontz bought 14.9 acres of undeveloped land in Florida in 1972. Later in 1972, Florida passed a law called the Water Resources Act which required landowners to obtain a permit and commit that what they want to build would not damage water resources. Then in 1984, Florida passed the Henderson Wetlands Protection Act which required that landowners obtain still additional government permits. Mr. Koontz wanted to develop part of his land in the 1990s. He wanted to fill part of the land to make a storm water pond, and offered to offset the environmental impact of this fill by creating a conservation easement on the rest of his land. His plan was rejected by the St. John’s River Management District, so Mr. Koontz turned to the court system and sued for monetary damages for an unconstitutional taking.

The Florida District Court and Court of Appeals held that Florida had overreached due to the nexus and proportionality requirements. Their decision was based on two prior US Supreme Court cases, Nollan v. California Coastal Commission and Dolan v. City of Tigard, both of which used the “nexus” and “rough proportionality” standards. The Florida Supreme Court reversed the two lower court decisions, and indicated that the Nollan and Dolan principles didn’t apply to Mr. Koontz’s case.

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The US Department of Interior’s Bureau of Land Management proposed new regulation for drilling on federal or Indian land. The BLM actually already amended the proposed regulation once, after there was serious criticism of their impact. To evaluate the amended proposal, the Independent Petroleum Association of America and Western Energy Alliance commissioned a study on the topic by John Dunham and Associates, an economic consulting firm based in New York City.

Under the original proposal of last year, oil and gas producers would have to pay an additional $1.284 billion in costs. Changes were made to that proposed regulation after producers, manufacturers, state regulators, and others adversely impacted by the regulation change lobbied the BLM to fix the problems. The major changes included: elimination of the requirement that all well simulations undergo the full requirements; elimination of the requirement that all oil and gas well development must be applied for through the BLM before completing a well; modification of the requirement for cement logs on all wells; and substantial changes to administrative reporting and permitting. The comment on the amended regulation closed in August 2013.

14098172-oil-well-pump.jpg Under the amended proposal, according to JDA, oil and gas producers would still have to pay $345 million more per year. JDA noted in the study that the costs of the regulations clearly exceed $100 million, at which point an economic assessment is required by law, and this has never been done. JDA calls the $345 million a “best case scenario” number, that is, in the event that BLM approves 100 percent of applications and capital costs are only 7%. Per well, JDA expects the cost of the revised proposed regulation to be $96,913. These numbers are certainly not nominal or inconsequential to the industry, and independent producers will be the hardest hit.

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A study entitled “Impacts of Delaying IDC Deductibility” was published recently by Wood Mackenzie Consulting and was commissioned by the American Petroleum Institute (API) to estimate the effects of an Obama proposal to eliminate federal tax deduction of intangible drilling costs used by the oil and gas industry and to instead require that these costs be treated as a capital expense. You can read the entire study here.

The difference between a deduction and a capital expense is huge. A deduction allows you to use the entire amount of the deduction in the year it was incurred. If these costs are treated as capital expenses, only a small portion of the total can be deducted each year over the useful life of the relevant asset. Intangible drilling costs are currently deductible like other operating costs and the deduction allows oil companies to use that saved money immediately for other projects. Intangible drilling costs include costs like wages, fuel and repairs, and accounts for 60% to 90% of costs for a given oil or gas well. Most industries deduct expenses like these in the year they were incurred. The Obama administration, however, wants to single out the energy industry for special treatment (again).

The study looks at the impact if this proposal was effective January 1, 2014. The study estimates that in the first year alone, elimination of the intangible drilling cost deduction would result in the loss of 190,000 US jobs. By 2019, the study estimates 233,000 job losses. Energy investment would be expected to drop by almost $40 billion per year between next year and 2023, for a total investment loss of $407 billion. U.S. oil production would drop by 520,000 barrels per day in the first year and 3.81 million barrels per day by 2023. There would also be 8,100 fewer wells drilled by 2019 and 9,800 fewer by 2023, contributing significantly to the drop in productivity. The study finds that some smaller companies may not be able to invest in drilling and development at all if the change were to take place.

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In Texas, and in much of the rest of the country, an oil and gas lease makes use of several different kinds of pipelines. When you are the recipient of a request for a pipeline easement, the kind of pipeline to be installed in that easement makes a night and day difference in how you negotiate the easement.

I recently spoke at a National Business Institute telephone seminar about the negotiation of pipeline easements. NBI provides “on-demand” CLE for attorneys and they have many excellent seminars on a wide variety of legal topics. You can access the audio of the seminar here, or you can register to take the seminar for CLE credit here.

The word “pipeline” can mean a variety of things, because there are several different types of pipelines. First, there are flow lines, which are lines from the well to other equipment on the well site, such as a tank or a heater-treater. Flow lines are located entirely within the well site area. The authorization for these lines is generally contained within the oil and gas lease itself. These lines are not regulated by either federal or state agencies.

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Those who follow the oil and gas industry, especially in Texas, are always interested in indicators of the health of the industry. One recent news story that caught my eye on this front was Chevron’s announcement of construction of a 50-story new office at 1600 Louisiana Street in downtown Houston, Texas, calling the city the “epicenter” of the global energy business. This is great news for the industry, the city, and the state of Texas, and it shows that Chevron is committed to continued growth and investment in our state.

The new skyscraper, set to be one of the tallest buildings in the city, will be 1.7 million square feet of office space and will be designed by the architecture firm HOK. When combined with Chevron’s current buildings at 1500 Louisiana Street and 1400 Smith Street, there will be a Chevron campus, including indoor and outdoor areas, a fitness center, and extra parking. The Texas Enterprise Fund has said it will supply $12 million towards the project. Chevron anticipates being able to move into the newly constructed building in 2016 and it is expected to have office space for as many as 4,200 workers.

downtown-houston-745017-m.jpg Despite these new plans and greatly expanded office space, Chevron says that the company will not move its headquarters to Houston, but will keep it in San Ramon, California where it has been for 130 years. However, in April, 2013 Chevron eliminated about 11% of jobs at the San Ramon location, (about 400 jobs), as it relocates more of its offices to Houston. Nine of the businesses that Chevron owns have their headquarters in Houston and overall the company employs an estimated 9,000 people in the Houston area. Bereket Haregot, president of Chevron’s business and real estate services group, said, “The announcement of our new office building underscores Chevron’s long-term commitment to Houston and Texas. The Lone Star State and its largest city play a vital and growing role in Chevron’s global business.”

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In 2008, the Texas Supreme Court heard a class action case against Phillips Petroleum Co. The case was Bowden v. Phillips Petroleum Co., in which the Plaintiffs alleged that Phillips had underpaid their oil and gas royalties. The Supreme Court remanded part of the case back to the trial court.

When the case was remanded, the representative of the class, Royce Yarbrough, amended the complaint against Phillips to allege that the company breached their implied covenant to market and that this is what contributed to the underpayment of royalties to the royalty owners. Phillips argued that to add a new claim on behalf of the class required a new class certification motion and hearing. The trial court disagreed and Phillips Petroleum appealed. The Texas Supreme Court considered this issue in Phillips Petroleum Co v. Yarbrough, et al.

The Supreme Court actually reviewed several issues, including res judicata issues from the Bowden case and whether they had jurisdiction over the interlocutory appeal on the decision by the trial court regarding the implied covenant to market. But the most interesting issue for oil and gas lawyers in Texas concerns the substantive issue of implied covenants to market vis-a-vis express covenants to market.

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Recently the Supreme Court of Texas issued a decision that is important for Texas surface owners and mineral owners and the Texas oil and gas attorneys who represent them. The case is Homer Merriman v. XTO Energy Inc. I discussed the background of the Supreme Court decision previously, and you can access that article here.

Background:

As you may recall, Homer Merriman bought a piece of land in 1996, but he bought only the surface rights, and the deed clearly reserved the minerals. XTO Energy Inc. had previously leased the mineral rights. Mr. Merriman used the land for his cattle business and used the particular tract in question to sort his cattle, with stock panels and electrical fences which he testified were not permanent fixtures. In 2007, XTO wanted to drill a well on this tract, and offered Mr. Merriman $10,000 in compensation for this use, but he refused and the case went to court.

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