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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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Texas royalty owners should get to know the website, FracFocus. This website provides a list of chemicals and other ingredients in fluids used by oil and gas well operators for hydraulic fracturing of wells both in Texas and across the country. The intent of the website is to allow the public to access this information and to provide objective and accurate data about hydraulic fracturing. FracFocus is managed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.

Twelve states currently require operators to report their data on FracFocus and eight more states are about to require reporting. The website currently has more than 45,000 records from more than 400 companies.

A new version of the website went online on June 1, 2013 that promises to be even easier to use according to witnesses who testified before the U.S. Senate Energy and Natural Resources Committee during their first natural gas forum. Some of the changes in the new version of the website include the display of data in a format that is easier to aggregate and customize. In addition, the new website will allow a search by the name of a chemical, using the Chemical Abstracts Service number, and a date range.

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The U.S. Department of the Interior issued a proposal in May 2013 for hydraulic fracturing regulations for federal and Native American land. The Department claimed that the goals were to maintain safety standards, improve integration between states and Native American tribes, and increase flexibility for oil and gas companies.

The new proposal was in response to the 177,000 comments from the public regarding the first proposal on this issue, all within the 120 day public comment period last fall. The Department said many of these comments were addressed in the new proposal, and that due to the large number of comments, they decided to start with a new proposal rather than amend the old one. (Yes, the former proposal was that flawed).

The Department claimed this latest proposal has three main elements, which are: (1) requiring operators to disclose chemicals they use in fracing on public land; (2) additional well bore integrity assurances to verify that fracing fluids do not contaminate groundwater; and (3) confirmation that oil and gas operators have a water management plan for handling flowback fluids.

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A new Texas oil pipeline started shipping condensates from Eagle Ford in May 2013. The new pipeline is owned by Double Eagle Pipeline LLC, a 50-50 joint venture between Magellan Midstream Partners and Kinder Morgan Energy Partners (KMEP). The condensates are coming from Karnes County and Live Oak County in Texas and are being transported via KMEP’s already existing 50 mile pipeline from Three Rivers, where Double Eagle’s new unloading and storage facility is also in operation, and from there to Magellan’s Corpus Christi terminal

Construction is expected to be completed on the new Double Eagle 140 mile long western leg of the pipeline, from Gardendale in LaSalle County to Three Rivers, within the next few months. The expected capacity is 100,000 b/d with a possible maximum of 150,000 with additional pumps. The project costs $150 million, to be shared equally between KMEP and Magellan. Magellan Chairman and Chief Executive Officer Mike Mears said that shipper interest in the Double Eagle pipeline has increased as completion on the new pipeline gets closer. In preparation for these expansions, Magellan improved the terminal at Corpus Christi, including construction of new 50,000 barrel condensate storage and a new dock delivery pipeline.

This is just the latest news in pipeline construction and expansion in Texas, particularly in this oil rich area of southern Texas. Last month, Plains All American Pipeline LP announced it is building a 310 mile Cactus Pipeline from McCarney in Upton County to Gardendale. The estimated cost will be $350-$375 million. The Cactus Pipeline is expected to be functional in 2015 and will have a capacity of 220,000 b/d of sweet and sour crude oil from the Permian Basin. It will connect with the Plains All American-Enterprise Products Partners Eagle Ford Joint Venture Pipeline, which serves Three Rivers and Corpus Christi as well as the Houston area through the Enterprise South Texas Crude Oil Pipeline. This will displace foreign imports of sour crude oil into the Gulf.

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