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In January, the El Paso Court of Appeals decided the appeal of Lazy R. Ranch, LP, et al. vs. ExxonMobil Corporation. The court reversed a summary judgment in favor of Exxon and remanded the case to the trial court for a trial on the merits. Exxon has asked the Texas Supreme Court to review the El Paso Court’s decision. Exxon argues that it has conclusively proven that Lazy R’s claims are barred by limitations.

The Lazy R Ranch is 20,000 acres in Ector, Crane, Ward and Winkler Counties. Exxon had operations on the ranch for many years. In 2009, the Ranch hired an environmental firm to investigate several sites on the property for oil-related contamination. The environmental firm found substantial hydrocarbon contamination at five sites, and found that at one of the sites the contamination had percolated down into the groundwater and that contamination at the other sites also posed a risk of leaching down into the groundwater. Lazy R sued Exxon for an injunction to require Exxon to take sufficient steps to prevent further spread of the contamination into the subsurface and groundwater.

The trial court ruled that the Ranch had waited too long to sue and dismissed its claims. The El Paso Court of Appeals reversed, holding that the statute of limitations does not apply because the Ranch is only suing for an injunction to require Exxon to abate a continuing nuisance, the spread of hydrocarbon contamination into the subsurface.

Both parties have now filed their briefs in the Texas Supreme Court, which has not yet decided whether to hear the case.

Groundwater contamination from older oil and gas operations, especially from tank batteries and compressor stations, is a big issue in Texas and has been for a long time. Once hydrocarbons, particularly condensate, leach into groundwater they are practically impossible to clean it up.

The agency in Texas responsible for enforcing cleanup of sites contaminated by oil and gas production operations is the Texas Railroad Commission. Companies found to have contaminated groundwater must obtain approval from the RRC of a “remediation plan” to remediate the property. For groundwater contamination, this usually involves taking steps to stop the spread of the contamination and then leave it to natural processes for the hydrocarbons in the groundwater to gradually degrade over time, called “natural attenuation.” That may take tens or even hundreds of years. In the meantime, the company responsible must obtain agreement from the landowner not to use the contaminated groundwater – a restrictive covenant that is binding on the property in perpetuity.

Landowners have a private cause of action for damages to the land resulting from contamination. The problem with such claims has been that the statute of limitations to bring the claims is either two or four years, depending on the claim. The landowner may not realize that the contamination, although evident on the surface of the property, has seeped into the groundwater until years after the contamination began. By then it’s too late to sue for damages.

The Lazy R Ranch has proposed a different remedy that, as far as I know, no Texas court has addressed — suing for an injunction to require the company to remediate the contamination, to prevent it from spreading further. This typically requires removal of the contaminated soil, which may be hugely expensive. Witness Exxon’s pleas to the Texas Supreme Court to dismiss Lazy R’s claims.

Exxon argues that, under established Texas precedent, the measure of damages for “permanent” damage to land is the diminution in the value of the property. It argues that the land contaminated on the Lazy R Ranch is only 1.2 acres, worth only $50/acre, but it would cost it millions of dollars to clean up the contamination. Exxon argues that Lazy R’s effort to use an injunction as a remedy is an “attempt at an end-run around the law,” which is really only a request for remediation damages that violate the measure of damages for permanent damage to land.

I have written before about my view of the inadequacy of established legal remedies in Texas for contamination like that allegedly caused by Exxon to the Lazy R Ranch.  In 2009, I filed an amicus brief (Senn v. Premrose Amicus) for the Texas Land and Mineral Owners’ Association in Primrose Operating Co. v. Senn, 161 S.W.3d 258 (Tex.App.-Eastland 2005, Pet. denied), asking the Texas Supreme Court to address the issue. That case applied the “permanent damage” measure of damages advocated by Exxon to contamination of the Senns’ ranch. The court of appeals held that the Senns’ property had not been damaged by the admittedly substantial contamination because the value of the property had actually increased from the time it discovered the contamination to the time of trial. Because the damages were “permanent,” and because there was no diminution in the value of the land resulting from the contamination, the Senns had not been harmed.

So this case may have important implications for landowners in areas of the state contaminated by legacy oil and gas operations.

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A federal judge in Dallas has ruled that Chesapeake cannot deduct post-production costs on the Plaintiffs’ leases covering lands in Tarrant and Johnson Counties, in the Barnett shale.  The order can be viewed here: Winscott – Order on MSJs 

The case is Trinity Valley School, et al. vs. Chesapeake Operating, Inc., et al., No. 3:13-CV-08082-K, in the US District Court for the Northern District of Texas, Judge Ed Winscott presiding. The order, although a partial summary judgment, appears to resolve Chesapeake’s claim of right to deduct post-production costs. Plaintiffs include Ed Bass, the Harris Methodist Southwest Hospital and Texas Health Presbyterian Hospital Dallas. The language construed in the leases varies, but all of the leases contain language dealing with sales to an affiliate.

As I have discussed before, Chesapeake sells its gas at the well to its affiliate Chesapeake Energy Marketing (CEMI). The price on which Chesapeake pays royalties is based on the weighted average price CEMI receives for the gas less gathering and transportation costs incurred by CEMI and a CEMI marketing fee.

The Bass leases at issue allowed deduction of post-production costs only if

(i) charged at arms-length by an entity unafilliated with Lessee; (ii) actually incurred by Lessee for the purpose of making the oil and gas produced hereunder ready for sale or use or to move such production to market; and (iii) incurred by Lessee at a location off of the Leased Premises …

The Court agreed with the Basses that, under Chesapeake’s marketing scheme, its sales of gas failed to meet any of these three requirements. The costs were charged by CEMI, an affiliate by an entity unafilliated with Chesapeake; the costs were not “actually incurred by Lessee,” because Chesapeake sold the gas at the well to CEMI, which incurred the charges; and the costs were not incurred “at a location off of the Leased Premises” because Chesapeake sold the gas at the well, where the charges were incurred.

Chesapeake found itself in the awkward position of arguing that the costs that were actual third-party transportation costs, as opposed to CEMI’s fees, were really “incurred” by Chesapeake, even though it created the scheme of selling at the well to its affiliate and its affiliated incurred the costs. It argued that the meaning of the lease “turns on the meaning of ‘incur’.” (Reminds me of Bill Clinton.)

The leases provide that, if Chesapeake sells to an affiliate, the royalties shall be based on the average of the two highest prices for gas being paid by purchasers in Tarrant County. The Plaintiffs said that this should, at least, be the weighted average price (WASP) for which CEMI sold their gas, without deductions for post-production costs. Chesapeake cried unfair; that price was for sales at locations remote from the wells, after post-production costs had been incurred. The price, Chesapeake argued, should be based on the value of the gas at the well.  The Court disagreed. “Because the market value is determined by a reference price, rather than a value at a geographical point, and WASP qualifies as a reference price, the Court finds that the WASP establishes a minimum price for the market value inquiry.”

In this case, Chesapeake’s sales to its own affiliate have come back to haunt it. Had Chesapeake sold its gas in the normal manner rather than through its affiliate, it would have been entitled to deduct legitimate third-party costs from the Plaintiffs’ royalty.

 

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Last week, the US Energy Information Administration provided a summary of states’ severance tax revenue (click on image below to enlarge):

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With the precipitous decline in oil prices, Alaska, North Dakota and Wyoming will be hurting.

According to EIA, Texas

collected $931 million in severance tax revenues in the first quarter of 2015—more than Wyoming collects in an entire fiscal year. The first-quarter total is down 46% from the $1.7 billion collected in the third quarter of 2014. However, severance taxes cover only 11% of the state operating budget. Texas state and local governments also derive greater oil and natural gas revenues from state land leases and local property taxes. Like Alaska and Wyoming, Texas does not have an individual income tax.

Most of the money in Texas’ Rainy Day Fund comes from severance taxes. In fiscal 2014, the Fund received more than $2.5 billion in severance taxes. In November 2014, Texas voters passed a constitutional amendment dedicating another portion of severance taxes to the State Highway Fund. Clearly, both funds will suffer from the drop in oil prices. Texas is most dependent on sales taxes for its revenue, and those too will suffer from the drop in oil prices. But Texas won’t suffer like Alaska, North Dakota and Wyoming. So far, the industry has staved off efforts in Pennsylvania to pass a severance tax.

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Big news this week about the Environmental Protection Agency’s new proposed regulations to limit emissions of methane and volatile organic compounds (VOCs) from oil and gas drilling, operating, compression and processing facilities. EPA’s proposed new rules can be viewed here. Among other things, the proposed regs would require operators to use “green completion” technology in drilling and completing wells, to reduce emissions of natural gas during those operations. The proposed rules would apply only to “new sources” of emissions, not existing facilities.

Representative Lamar Smith, R-San Antonio, called the proposed rules “yet another example of the Obama administration’s war on American energy jobs.”  Barry Russell, CEO of the Independent Petroleum Association of America, said the proposed rules would cause “unnecessary costs and added uncertainty” that would “inflict more pain on the men and women who work in the oil and gas industry at a time when market forces are already creating economic challenges.” Environmentalists praised the proposed regulations, but said that EPA needs to begin regulating emissions from existing facilities.

VOCs are carbon-based molecules that evaporate at ordinary temperatures and pressures, and are emitted into the air during oil and gas production, gathering, transportation and processing activities. They include  benzene, ethylbenzene, and n-hexane, which are harmful to human health. VOCs and methane are also powerful greenhouse gases, contributing to global warming according to scientific consensus.

Meanwhile, a study was published this week in Environmental Science and Technology, led by Colorado State University and sponsored by the Environmental Defense Fund and based on a comprehensive review of methane emissions in oil and gas facilities. It found that emissions from natural gas pipelines and processing facilities are much higher than estimated by EPA or the Energy Information Administration. The study concludes that the methane escaping from natural gas pipelines and processing facilities could to power more than 3 million homes.

It appears that most emissions of methane from production and processing facilities result from poor oversight, monitoring and maintenance. Good operating practices would greatly reduce such emissions. Other emissions can be reduced only by installing new or different equipment that does not emit methane as part of normal operations. If the industry wants to limit the intrusiveness of EPA regulations on its operations, it needs to clean up its own house by identifying bad actors and encouraging compliance with good industry standards, by increased monitoring of emissions and fixing problems when they occur,  and by cooperating with EPA in crafting regulations that allow the industry to address the problem in its own way.

The Cynthia and George Mitchell Foundation has endorsed the proposed rules. George Mitchell, now deceased, is the father of the modern method of hydraulic fracturing that has transformed the US energy industry.

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Chesapeake is spending a lot of money on lawyers.

Dan McDonald, a Fort Worth attorney, has filed some 250 cases against Chesapeake contending that it is underpaying its royalty owners. Companies affiliated with former House of Representatives Speaker Tom Craddick have now been added to McDonald’s client list. So many cases have been filed against it in Texas that Chesapeake asked the cases to be granted multidistrict litigation status, so that one judge could control pretrial discovery and motions and settings. Two judges have been appointed for that purpose, one for McDonald’s cases and another for cases brought by other attorneys. Chesapeake is settling cases as fast as it can.

Most of the claims against Chesapeake arise from its structure for selling gas. Chesapeake sells its gas at the wellhead to its wholly owned subsidiary Chesapeake Energy Marketing. Chesapeake Energy Marketing arranges for the gathering of the gas and delivery to central sales points, and pays Chesapeake for the gas based on a weighted average price of all sales at those central gathering points, less costs of compression, gathering, treating and transportation, and less a “marketing fee” charged by Chesapeake Energy Marketing. The costs incurred between the wellhead and the point of delivery to the purchaser were formerly incurred by another Chesapeake affiliate, Access Midstream. Chesapeake spun off its gathering systems into a separate company a few years ago, and as part of that deal it guaranteed a minimum rate of return on those gathering systems to the new spin-off company, thereby receiving a premium price in the market for the new company’s shares. Chesapeake pays royalties based on the new price it receives from Chesapeake Energy Marketing, after deduction of post-production costs and marketing fees. McDonald says that these “costs” are “sham sales” and “fraudulent transactions.”

McDonald’s first ten cases against Chesapeake are set for trial early next year. McDonald’s cases are mainly for wells in the Barnett Shale, where Chesapeake has sold a share in its wells to Total, the French energy company. Total is also named as a defendant, and it markets its share of gas in a manner similar to Chesapeake.

Chesapeake recently reported a $4 billion loss and has eliminated its dividend. It recently sued its founder and former CEO Aubrey McClendon for allegedly stealing trade secrets when he was fired by the company.

Chesapeake recently lost an important case in the Texas Supreme Court, Chesapeake v. Hyder, and the opinion in that case has other companies concerned about their ability to deduct post-production costs from royalties. Chesapeake recently filed a motion for rehearing in that case, and amicus briefs urging the court to reconsider its opinion have been filed by Texas Oil & Gas Association, BP, Devon, EOG, Exco, Shell, XTO and others. With low gas prices, the ability to force royalty owners to share in post-production costs can mean the difference between profit and loss for some companies.

 

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The Oklahoma Corporation Commission, the regulator of oil and gas in Oklahoma, has directed operators of 23 injection wells in a designated area to reduce rates of injection by 38% by October 2, 2015. The order covers a 15-mile-by-40-mile “area of interest,” stretching northwest from the outskirts of Oklahoma City. The Commission’s letter may be viewed here: Oklahoma Corp Commn quake letter

Earthquakes in Oklahoma have increased from 2 in 2012 to 359 in 2014; so far in 2015, 253 quakes have been detected.

Dana Murphy, one of the three elected members of the Corporation Commission, said “This is an issue completely outside the scope of the experience of not only this agency, but all our partner agencies and stakeholders, as well. There was a time when the scientific, legal, policy and other concerns related to this issue had to first be carefully researched and debated in order to provide a valid framework for such action. That time is over.”

Earthquakes have been a political hot potato in Oklahoma. See recent Energywire article.

In Texas, the Railroad Commission held show cause hearings last month to require two injection well operators in the Barnett Shale to show cause why their operations should not be halted or curtailed because of earthquake activity near their wells. The hearings examiners in those cases have not yet issued a proposal for decision.

The Railroad Commission would do well to consider Oklahoma’s experience.

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The rights of local municipalities to regulate or ban drilling activity within their jurisdictions has been a hot topic over the last few years in several states, especially Pennsylvania, Texas and Colorado. Shale development has been intense in all three states, but their reactions to urban drilling regulation have differed markedly.

In Colorado, voters threatened to force a ballot initiative to ban hydraulic fracturing in the state. In response, the governor cobbled together a compromise that included the appointment of a task force to examine the impact of drilling on urban environments and make recommendations. That task force, the Colorado Oil and Gas Task Force, issued nine recommendations in February of this year. They make for interesting reading.

The Colorado Oil and Gas Conservation Commission has been conducting hearings across the state on two of the Task Force recommendations, both of which would require the COGCC to implement regulations. Both of the recommendations would increase municipalities’ participation in the permitting process for wells within their jurisdictions. Recommendation #17 would require companies planning “Large Scale Oil and Gas Facilities” to consult with local governments to try to reach agreement on the siting of those facilities and to engage in mediation if the parties are unable to reach agreement. Recommendation #20 would require companies to provide local governments a five-year plan for their drilling and development within their jurisdictions, to allow the municipalities to include those plans in the municipalities’ own long-range plans.

Compare Colorado’s efforts to the Texas legislature’s response when Denton, Texas voted to ban hydraulic fracturing within its boundaries. The Legislature passed House Bill 40. That bill not only barred municipalities from banning fracking, it also significantly limited the authority of cities to regulate drilling within their jurisdictions.

With the exception of Denton, exploration companies and municipalities have managed to get along with each other in Texas, and urban drilling has become a common occurrence in cities like Fort Worth. Fort Worth worked with the industry to craft regulations on siting, noise, safety, emissions, light, traffic, and pipelines that all stakeholders were willing to live with and that have become a model for other cities to follow. But with House Bill 40, all of that work is called into question. Instead of engaging with municipalities to find solutions, in my view the legislature bowed to the interests of industry and gave them a tool with which to threaten cities if operators felt that cities’ regulations were too heavy-handed.

It remains to be seen whether the industry and municipalities will make peace in Colorado. But I think it is inevitable that House Bill 40 will result in expensive litigation between cities and industry in Texas.

 

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The EPA this week published a “proposed framework” for a new voluntary program for the oil and gas sector to reduce methane emissions – the “Natural Gas STAR Methane Challenge Program.” It is part of the administration’s continuing effort to reduce emissions of methane, a powerful greenhouse gas. The proposal can be found here.

I’m no expert on air emissions standards. As a citizen reading the proposal, I was struck by the increasing intensity of efforts to address emissions of methane and volatile organic compounds in the oil and gas sector.

In 1993, EPA created its Natural Gas STAR Program, a voluntary program in which oil and gas companies could commit to identify opportunities in their companies to reduce methane emissions and report on their progress. According to the EPA, Gas STAR partner companies have reported methane emission reductions of more than one trillion cubic feet through 2013.

In 2012, the EPA issued New Source Performance Standards for the oil and gas industry to achieve reductions in methane and VOC emissions.

In March 2014, the administration release its Strategy to Reduce Methane Emissions as part of its Climate Action Plan.

In 2014, the industry founded the One Future program, in which member companies make commitments to achieve methane emission targets.

A good summary of EPA efforts related to methane emissions can be seen here.

In the EPA’s new Methane Challenge, participating companies would enter into a memorandum of understanding with EPA committing to specific emission reduction goals and a plan to achieve those goals, and would commit to annual reporting on their progress.

EPA is asking for comments on its proposed framework.

I have had increasing complaints and concerns voiced by clients about air emissions from oil and gas production facilities. Landowners are more frequently demanding that their lessees take steps to limit emissions and capture gas for sale that is being vented or flared. The Environmental Defense Fund has begun a series of studies to identify methane emission sources and available technology to reduce methane emissions. If the industry wants to tout natural gas as more environmentally friendly than coal, it would do well to take steps to reduce its emissions.

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When exploration began in the Marcellus Shale in Pennsylvania, it was the wild west transported to the east. Speculators sprung up and bought oil and gas leases with the expectation of selling them for a profit. The forms of oil and gas leases I saw being used in Pennsylvania were the worst I have seen in my career. Speculators paid for leases with 90-day drafts, hoping they could find a buyer for the leases in time to pay the bonuses.

But landowners soon caught on. They organized themselves, creating informal associations in geographic areas to negotiate leases as a group. The associations hired competent counsel. Large blocks of land were offered to multiple companies, forcing companies to bid against each other. Landowners educated themselves and realized that there was power in numbers.

Texas landowners, on the other hand, are an independent lot. They don’t like to give up their autonomy. They don’t like sharing their lease terms with other landowners. Every landowner thinks his lease form is the best. Landowners don’t like regulatory authorities telling them what they can and can’t do. One riot, one ranger.

In Texas’ last legislative session, three organizations representing land and mineral owners opposed legislation seeking to legalize allocation wells, House Bill 1552: Texas Land and Mineral Owners’ Association, the National Association of Royalty Owners-Texas, and Texas Cattle Raisers’ Association. Representatives and members of those associations testified and lobbied against the bill, and it did not make it out of committee. It is my opinion that the bill would have severely eroded mineral owners’ bargaining power with exploration companies. I testified against the bill.

Texas Land and Mineral Owners’ Association and NARO-Texas also filed an amicus brief this year in Chesapeake v. Hyder, a case dealing with the ability of lessees to deduct post-production costs from royalties. TLMA and NARO-Texas hired our firm and Raul Gonzalez, retired Supreme Court Justice, to file the brief on their behalf. The Texas Supreme Court recently ruled, 5 to 4, in favor of the royalty owners in that case.

TLMA and NARO-Texas both have conventions and provide educational opportunities to their members. Their boards are volunteers who work hard to protect and advance the interests of mineral owners. The organizations have relatively small membership compared to the number of mineral and royalty owners in Texas. Their budgets are small.

Texas mineral owners could learn from Pennsylvanians. Knowledge is power. There is strength in numbers. Texas mineral owners should join and support efforts of organizations like TLMA and NARO-Texas. What happens in the courts and legislature matters. There is such a thing as good government, good regulatory policy. The exploration industry in Texas has created wealth for thousands of Texans, but the interests of oil companies are not always aligned with the interests of land and mineral owners. Oil companies in Texas have powerful lobbies – witness the recent passage of House Bill 40, severely limiting the ability of municipalities to regulate oil and gas exploration in their jurisdictions. The efforts of TLMA and NARO-Texas remind legislators that oil companies don’t vote – people do. Legislators pay attention when members of those organizations engage in letter-writing campaigns to oppose or support legislation. Mineral owners in Texas should join one or both of these organizations, and get involved. It will be time and money well spent.

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