Chesapeake has asked the Texas Supreme Court to hear its appeal of Chesapeake v. Hyder, decided by the San Antonio Court of Appeals in March of this year. The Supreme Court has asked the parties to file briefs on the merits, and Chesapeake filed its brief last week. Although the Court has not yet agreed to hear the case, its request for briefs is an indication that the Court may do so.
I wrote about the Hyder case when it was decided last March. Since then, the U.S. Court of Appeals for the 5th Circuit has decided two other Chesapeake cases, Chesapeake v. Potts and Chesapeake v. Warren, ruling in Chesapeake's favor in both cases. All three cases involve deduction of post-production costs from royalties. Multiple cases have been filed against Chesapeake challenging its post-production-costs deductions, because of its aggressive method of calculating those costs. In all three cases, Chesapeake relies heavily on a Texas Supreme Court case decided in 1996, Heritage Resources v. NationsBank. The Texas Supreme Court has not discussed its opinion in Heritage since it was decided. Hyder may be its opportunity to do so.
The oil and gas lease in Hyder provides that "the royalty reserved herein by Lessors shall be free and clear of all production and post-production costs and expenses." It also states that "Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provision of this Lease." The Court of Appeals held that the lease prohibited Chesapeake from deducting transportation costs.
The Court of Appeals opinion has an interesting discussion of Chesapeake's structure for marketing and selling its gas. The owner of the lease is Chesapeake Exploration, LLC. Chesapeake Operating, Inc., drills and operates the wells and pays the royalty. Chesapeake Energy Marketing, Inc., buys the gas from Chesapeake Operating (as agent for Chesapeake Exploration). Chesapeake Midstream Partners, LP gathers the gas from the leases and delivers it to pipelines owned and operated by unrelated parties. Those pipelines in turn deliver the gas to purchasers, who pay Chesapeake Energy Marketing, Inc.
A recent investigative report by Pro Publica describes how Chesapeake spun off its subsidiary, Chesapeake Midstream Partners (which became Access Midstream), in the process raising $4.76 billion. According to the report, Chesapeake sold its network of gathering lines in Pennsylvania, Ohio, Louisiana, Texas and the Midwest to Access, and entered into an agreement with Access for Access to gather and transport Chesapeake's gas. Over a ten-year period, Chesapeake pledged by this contract to pay Access enough in fees to repay Access's purchase price plus a 15 percent return on the investment. The agreement also provides for Access to pay Chesapeake for use of certain Chesapeake equipment. According to the report, the result of these transactions was to greatly increase Chesapeake's cost of gathering its gas, to an average of 85 cents per mcf. That gathering cost greatly increased the deductions on Chesapeake's royalty owners' checks. In effect, it could be argued that Chesapeake has monetized some of its gas reserves by locking itself into a long-term gathering agreement with Access, in exchange for a $4.76 billion payment from Access, and in the process created an inflated gathering charge which can be passed on to its royalty owners.
In June, attorneys in Pennsylvania filed suit against Chesapeake, seeking certification of a class action on behalf of Pennsylvania royalty owners, alleging that the system used by Chesapeake for marketing its gas constitutes a violation of the Racketeer Influenced and Corrupt Organizations Act, or RICO. (Complaint can be viewed here.) The lawsuit claims that "defendants, under the guise of Chesapeake's subsidiaries' agreements with lessors, exploited deductions language from the lease agreements to, among other things, shift repayment of Chesapeake's off-balance sheet loan from Access Midstream to the lessors."
Last week the Texas Supreme Court heard oral arguments in Steadfast Financial v. Bradshaw, No. 13-0199. The case presents the court with another opportunity to grapple with an issue that Texas courts have struggled with since the court first addressed it in 1937 - what duty does the owner of the mineral estate owe to a non-participating royalty owner?
The term "non-participating royalty owner" is the name commonly given to a royalty interest in minerals created by a grant or reservation in a deed. "Non-participating" is really redundant; it means that the holder of the royalty estate has no right to lease the mineral estate or to receive any bonus for a lease. In fact, that is true of all royalty interests. A better name for this type of royalty interest might be "fee royalty interest," to distinguish it from a royalty interest reserved by the mineral owner in an oil and gas lease.
The owner of a fee royalty interest, having no right to lease or to drill wells, is dependent on the owner of the mineral estate out of which his/her royalty interest must be paid; the royalty interest has no value unless the mineral interest is leased and wells are drilled. In recognition of this fact, court decisions have imposed a duty on the mineral owner to protect the royalty owner's interest. How this duty is defined, and in what situations the duty is imposed, have been issues Texas courts have struggled with for many years. The cases that have addressed this issue over the years show how the common law develops -- very slowly, and with varied results for the litigants involved.
In Steadfast, Steadfast Financial owned the surface and mineral estates in 1,800 acres of land in Hood County. In 2006, Steadfast entered into a transaction with Range Resources: it sold the surface estate to Range for $8,976,600, and it granted an oil and gas lease to Range providing for a 1/8th royalty. At the time, Betty Lou Bradshaw owned a royalty interest in the 1,800 acres that she had inherited from her parents. When her parents sold the land in 1960, they reserved a royalty interest of 1/2 of the royalty; in other words they were entitled to 1/2 of any royalty reserved by the mineral owner in any oil and gas lease covering the 1,800 acres.
When Ms. Bradshaw learned about the Steadfast-Range transaction, she sued Steadfast and Range. She claimed that the going royalty rate for oil and gas leases in Hood County in 2006 was 1/4th, and that Steadfast had a duty to her to get the best royalty it could obtain. She alleged that Steadfast and Range had conspired to breach Steadfast's duty to her, and that Range should be liable for its participation in Steadfast's scheme. She argued that Steadfast got a much better deal on its sale of the land to Range by agreeing to reduce the royalty rate in its lease to Range from 1/8 to 1/4.
The trial court threw out all of Ms. Bradshaw's claims, but the Fort Worth Court of Appeals held that she was entitled to a trial and remanded the case to the trial court. Bradshaw v. Steadfast Financial, 395 S.W.3d 348 (Tex.App.-Fort Worth 2013). Steadfast appealed to the Texas Supreme Court, which agreed to hear the case. You can view the oral arguments in the Supreme Court here.
The Texas Supreme Court first considered the mineral owner's duty to a royalty interest owner in Schlittler v. Smith, 101 S.W.2d 543 (Tex. 1937), where it described the mineral owner's duty as one of "utmost fair dealing." One of the most important Supreme Court cases on the topic is Manges v. Guerra, 673 S.W.2d 180 (Tex. 1984), involving the infamous Clinton Manges. Manges leased the minerals under his ranch in Duval County to himself for 1/8th royalty, and then sold the lease, reserving an additional 1/8th royalty for himself. The Court held that in doing so he breached his duty to the Guerras, who owned a royalty interest in the ranch. The Court held that Manges breached his "duty of utmost good faith" to the Guerras.
More recently, the Supreme Court has grappled with the mineral owner's duty to royalty owners in In re Bass, 113 S.W.3d 735 (Tex. 2003) and Lesley v. Veterans Land Board, 352 S.W.3d 479 (Tex. 2011). In Bass the Court held that a mineral owner has no duty to the royalty owner to grant an oil and gas lease. In Lesley the Court appeared to backtrack on what it had held in Bass, holding that a mineral owner does have a duty to a royalty owner to lease under some circumstances.
The lawyers arguing for Steadfast and Range said that Steadfast had no duty to Ms. Bradshaw to obtain the highest royalty rate it could, and that Steadfast should have the right to enter into a lease with 1/8th royalty and the highest bonus it could negotiate, even though the result would be to lessen Ms. Bradshaw's share of production. Bradshaw's attorney said that such a rule would be contrary to the substantial body of case law that had recognized a duty of "utmost good faith" owed by the mineral owner to its royalty owner. Questions from some members of the Court indicated that they were reluctant to require Steadfast to negotiate the best royalty it could obtain. If the Court decides to rule against Ms. Bradshaw, it could show an increasing reluctance by this Court to impose implied covenants or higher standards of conduct in the relationship between mineral and royalty owners in Texas.
Trail Enterprises' efforts to collect an inverse condemnation judgment against the City of Houston have finally come to an end. The US Supreme Court has refused to hear its case. Trail Enterprises' story is instructive to parties who may be thinking of challenging cities' decisions to ban drilling within their boundaries.
The dispute has a long history. Lake Houston is a major source of drinking water for the City of Houston. In 1967, the City passed an ordinance restricting the drilling of new oil and gas wells in a "control area" around the lake. That restriction has remained in place except for an eleven-month gap in 1996-97, when the lake was annexed into the City and the City passed a new ordinance protecting the lake.
In 1995, Trail Enterprises, an owner of mineral interests in the restricted area around the lake, sued the City, claiming that the 1967 ordinance restriction amounted to a "taking" of the mineral interests in violation of the US Constitution. The trial court dismissed that suit, and the Houston Court of appeals affirmed. Trail Enters., Inc. v. City of Houston, 957 S.W.2d 625 (Tex.App.-Houston [14th Dist.] 1997, writ denied). In 1999, Trail sued again, this time arguing that the City's 1997 ordinance resulted in a taking of its property. The trial court held that the ordinance did not constitute a taking. This time the Houston Court of Appeals reversed and remanded the case for a trial. Trail Enters., Inc. v. City of Houston, 2002 WL 389448 (Tex.App.-Houston [14th Dist.] Mar. 14, 2002, no pet.). But the parties decided to dismiss that case.
Finally, in 2003, Trail, joined by other mineral owners, filed suit a third time. In 2005 a trial was finally held and a jury awarded the plaintiffs $19 million. But the trial judge dismissed the case on the ground that the plaintiffs had never applied to the City for a drilling permit. That order was again appealed. The appeal was transferred to the Waco Court of Appeals, which affirmed the trial court's dismissal. Trail Enters., Inc. v. City of Houston, 255 S.W.3d 105 (Tex.App.-Waco 2007). Trail appealed to the Texas Supreme Court, which reversed and remanded the case back to the trial court. City of Houston v. Trail Enters., Inc., 300 S.W.3d 736 (Tex. 2009). This time, the trial court, after another evidentiary hearing, entered judgment against the city for $17 million.
The City appealed again, and in an opinion in 2012 the Houston Court of Appeals held that no "compensable taking" had occurred and reversed the trial court's judgment. City of Houston v. Trail Enters., Inc., 377 S.W. 3rd 873 (Tex.App.-Houston [14th Dist.] 2012). Trail sought review by the Texas Supreme Court, but in October last year that court refused to hear the case. And this week, the US Supreme Court also refused to hear Trail's appeal. After 19 years, Trail's efforts have finally come to naught.
Why such a tortuous fight through the courts? One reason is the very murky law of inverse condemnation. The Fifth Amendment to the US Constitution provides: "nor shall private property be taken for public use, without just compensation." The US Supreme Court has struggled mightily over the years to define what this means. Its seminal case on the matter is Penn Central Transp. Co. v. New York City, 438 U.S. 104 (1978). In that case, the court attempted to define when a government's restriction of use of private property was so onerous as to require the government to pay the property owner -- when governmental restrictions amount to a "taking" of private property. The court's decision in Penn Central laid out a three-part test. Under this test, a court must evaluate a regulatory takings claim based on (1) the economic impact of the regulation, (2) the owner's "reasonable investment-backed expectations," and (3) the character of the regulatory action. Those words don't mean much until fleshed out by subsequent cases, and the factors are fuzzy and subjective. So inverse condemnation cases like Trail Enterprises become very fact-specific analyses, and the subjectivity of the test sometimes allows the biases of court judges to emerge.
I'm no expert on takings law. But recent developments in Texas and other states, centered around municipalities' increasing efforts to restrict drilling for oil and gas within their limits, may end up in takings cases like Trail Enterprises. The mineral owners' extreme difficulty in getting a final determination of their claim in Trail, and the multiple appellate opinions grappling with the takings issues, is an indication of the hurdles that other mineral owners may face in seeking compensation for cities' restrictions on drilling that affect the value of their mineral interests. In Texas, the City of Denton has a proposition on the November ballot: "Shall an ordinance be enacted prohibiting, within the corporate limits of the City of Denton, Texas, hydraulic fracturing ...." See "In Texas, a Fight Over Fracking," in the New York Times, Oct. 8. Already a group of mineral owners has sued Denton over its temporary moratorium on drilling within city limits. If Denton's referendum passes, more lawsuits are a certainty. Similar bans are being passed by cities in Colorado and Pennsylvania, and the State of New York has had a moratorium on fracking since 2008. All good news for lawyers specializing in inverse condemnation suits.
A new study published by The University of Texas' Bureau of Economic Geology compares the amount of water used in producing oil from shale plays to the water used in producing oil from conventional reservoirs. The study concludes that water use for conventional and unconventional oil production is about the same. "Comparison of Water Use for Hydraulic Fracturing for Shale Oil and Gas Production versus Conventional Oil."
The study looked at water use in the Bakken and Eagle Ford plays. The ratio of water used to oil produced ranged from 0.2 to 0.4 gallons of water for each gallon of oil produced over the lifetime of a well in both plays - or 0.03 to 0.06 gallons of water per million British thermal units of energy from the oil produced. In comparison, U.S. conventional production uses from 0.1 to 5 gallons of water for each gallon of oil produced.
The study's conclusion: "the U.S. is using more water because HF [hydraulic fracturing] has expanded oil production, not because HF is using more water per unit of oil production."
According to the study, the amount of water used per mmBtu produced in the Bakken is substantially less than in the Eagle Ford: water use per well in the Bakken is about half that in the Eagle Ford, and about one-third per mmBtu of energy produced.
Michael Brick has written an excellent article in the Houston Chronicle about the Texas Railroad Commission's new seismologist, David Craig Pearson. The article, "Vexed by Earthquakes, Texas Calls In a Scientist," relates the events leading up to his hiring, his background, and the RRC's initial foray into addressing the issue by proposing new rules on injection well operators.
Dr. Pearson grew up in McCamey, worked in the oil fields, studied at SMU, and worked at Los Alamos National Laboratory in New Mexico for 13 years. He left in 2006, returning to West Texas and ranching. He inherited some mineral rights in Upton County. When the RRC advertised for a seismologist, he applied and was hired.
So far, Dr. Pearson has published no conclusions, but the RRC has been praised for its new proposed rules. Pearson testified in August before the House Energy Resources Subcommittee on Seismic Activity that he wants to wait for reports from SMU's study of seismic and injection activity around the town of Azle, in the Barnett Shale, before drawing any conclusions.
In a letter to the Texas Railroad Commission commenting on the RRC's proposed rules on curbing earthquakes caused by high-pressure injection of waste fluids, the Environmental Protection Agency "applauded the RRC's efforts to ensure it has sufficient regulatory authority to respond to any event of the type where concerns may arise." Maybe the agencies will kiss and make up? Not likely. But the EPA agrees with proposed rules published by the RRC that would require applicants for disposal well permits to submit information about the area's risk for earthquakes as part of their application. The rules also strengthen the RRC's authority to limit or halt injection from existing wells where earthquake events occur.
Initially the RRC was slow to respond to complaints about earthquakes. At one point, citizens from the town of Azle, particularly affected by earthquakes, staged a protest before the RRC at which Azle citizens serenaded the commission with their own composition based on Elvis Presley's All Shook Up. The RRC has now hired its own seismologist, and although Commissioners are cautious about connecting earthquakes to oil and gas activity, the proposed rules are a step in the right direction.
Texas now has more than 3,600 active commercial injection wells; it granted 668 permits last year alone. Earthquakes strong enough to damage homes have occurred in the Barnett Shale region. Similar problems have occurred in Oklahoma and other regions.
The proposed rule can be found here. Other comments on the proposed rule can be found here. Texas Tribune article on the proposed rules is here. SMU is conducting a study of the quakes around Azle and has installed seismic stations in the area to monitor seismic activity.
A study published in the Proceedings of the National Academy of Sciences, examining eight clusters of contaminated water wells in Pennsylvania and Texas, found that the wells' contamination was either from naturally occurring gas deposits -- i.e., the gas is naturally occurring within the aquifer -- or from poor casing and cementing of nearby gas wells. The study concluded that the hydraulic fracturing of the wells was not a cause of groundwater contamination. The study was led by a researcher at The Ohio State University and included researchers at Duke, Harvard, Dartmouth and the University of Rochester. The researchers were able to "fingerprint" the gas by measuring the amount of "noble" gases such as helium included with the natural gas. The researchers were able to distinguish between the fingerprints of naturally occurring methane in the aquifers and gas from the Barnett and Marcellus Shale formations. Ohio State's press release about the study can be viewed here.
I have written previously about the ongoing battle between Range Resources and the Lipskys over the Lipskys' claims that Range's wells contaminated their groundwater. A facet of that battle is pending in the Texas Supreme Court. This new study will add fire to the debate.
There are always nay-sayers who predict that the current boom, whatever it may be, will soon be a bust. Recently, however, some pretty prominent voices have cautioned that all of the rosy predictions about the future of the shale boom, US energy independence, and the continued growth of US oil and gas production are false - a bubble soon to burst.
One of those is J. David Hughes, a geoscientist with the Post-Carbon Institute. He spent 32 years with the Geological Survey of Canada, and coordinated an assessment of Canada's unconventional natural gas potential. He has authored "Drill, Baby, Drill," published last year by the Post Carbon Institute and the Energy Policy Forum. It is a pretty comprehensive review of the long-term viability of the shale plays. Some excerpts:
- "World energy consumption has more than doubled since the energy crises of the 1970s, and more than 80 percent of this is provided by fossil fuels. In the next 24 years world consumption is forecast to grow by a further 44 percent--and U.S. consumption a further seven percent--with fossil fuels continuing to provide around 80 percent of total demand."
- "Shale gas production has grown explosively to account for nearly 40 percent of U.S. natural gas production; nevertheless production has been on a plateau since December 2011 --80 percent of shale gas production comes from five plays, several of which are in decline. The very high decline rates of shale gas wells require continuous inputs of capital--estimated at $42 billion per year to drill more than 7,000 wells--in order to maintain production. In comparison, the value of shale gas produced in 2012 was just $32.5 billion."
- "Tight oil plays are characterized by high decline rates, and it is estimated that more than 6,000 wells (at a cost of $35 billion annually) are required to maintain production, of which 1,542 wells annually (at a cost of $14 billion) are needed in the Eagle Ford and Bakken plays alone to offset declines. As some shale wells produce substantial amounts of both gas and liquids, taken together shale gas and tight oil require about 8,600 wells per year at a cost of over $48 billion to offset declines. Tight oil production is projected to grow substantially from current levels to a peak in 2017 at 2.3 million barrels per day. At that point, all drilling locations will have been used in the two largest plays (Bakken and Eagle Ford) and production will collapse back to 2012 levels by 2019, and to 0.7 million barrels per day by 2025. In short, tight oil production from these plays will be a bubble of about ten years' duration."
Hughes' report is filled with graphs illustrating production and consumption world-wide and by field. Here is an example:
The Haynesville, Barnett, Fayetteville, and Woodford plays, which collectively produce 68 percent of United States shale gas, are late-middle-aged in terms of the life cycle of shale plays. Unless there is a substantial increase in gas price and a large ramp-up in drilling, these plays will go into terminal decline. The prognosis for the top nine shale plays in the United States, which account for 95 percent of shale gas production, is presented in Table 2.
Hughes also discusses the two biggest oil shale plays, the Bakken and the Eagle Ford. Together, these fields produce more than 80 percent of tight oil production in the US. "Overall field decline rates are such that 40 percent of production must be replaced annually to maintain production."
Given the EIA estimate of available well locations, the Bakken, which has produced about half a billion barrels to date, will ultimately produce about 2.8 billion barrels by 2025 (close to the low end of the USGS estimate of 3 billion barrels). Similarly, the Eagle Ford will ultimately produce about 2.23 billion barrels, which is close to the EIA estimate of 2.46 billion barrels. Together these plays may yield a little over 5 billion barrels, which is less than 10 months of U.S. consumption.
Some figures from Hughes' discussion of the Eagle Ford:
"The future production profile of the Eagle Ford--assuming a total of 11,406 effective locations, a 40 percent overall field decline, and current rates of drilling with all new wells performing as in 2011--is illustrated in Figure 75. This yields a production profile which rises 34 percent from June 2012 levels to a peak of 0.891 million barrels per day in 2016 as illustrated in Figure 75. At this point, with all well locations drilled, production declines at the overall field decline rate of about 40 percent. The overall field decline may decrease somewhat over time after peak as wells approach terminal decline rates. This also assumes that 70 percent of the wells drilled to date have targeted the oil-rich portion of the
Eagle Ford play. Total oil recovery in this scenario is about 2.23 billion barrels by 2025, which agrees quite well with the EIA's estimate of 2.46 billion barrels.157 Average well production falls below 10 bbls/d in this scenario by 2021."
Hughes' report provides a wealth of data and puts the "shale boom" in perspective. He may be overly pessimistic, but he certainly makes one think about the world's unsustainable thirst for hydrocarbons.
Last month I wrote about two cases recently decided by the U.S. Court of Appeals for the 5th Circuit in which Chesapeake defeated royalty owners' efforts to prevent it from reducing their royalties by deducting post-production costs. One of those cases is Potts v. Chesapeake. The plaintiffs in that case have asked the Court of Appeals to reconsider its appeal "en banc," meaning that it has asked the other judges on the court to grant its petition for rehearing and reconsider the decision of the three-judge panel who decided the case. Plaintiffs' Petition for Rehearing may be viewed here: Potts Petition for Rehearing En Banc.pdf
Yesterday, our firm filed a friend-of-the-court brief in the Potts case, on behalf of the Texas Land and Mineral Owners Association and the National Association of Royalty Owners - Texas, asking the Court to grant the plaintiff's motion for rehearing and either consider the case en banc or refer the question to the Texas Supreme Court for its consideration. A copy of our brief may be viewed here: Potts v. CHK Amicus Brief.pdf
Meanwhile, in Pennsylvania, suit has been filed against Chesapeake claiming that its conduct in selling gas to its affiliate company at prices well below market, and then selling its affiliate company for a substantial profit, constituted fraud on its royalty owners in violation of the Racketeer Influenced and Corrupt Organizations Act, known as RICO. That petition can be viewed here: Suessenbach v. Chesapeake.pdf
With increasing frequency, my landowner clients have complained about gas flaring, especially in the Eagle Ford Shale. Landowners are beginning to insist that their leases require royalty payments on flared gas. Landowners also complain of the odors and noise from gas flares.
The San Antonio Express News has recently published a four-part series, Up in Flames, on flaring in the Eagle Ford, after a year-long investigation. Among its findings:
- Since 2009, flaring and venting of natural gas in Texas has surged by 400 percent to 33 billion cubic feet in 2012. Nearly 2/3 of the gas flared in 2012 came from the Eagle Ford.
- Gas flared in the Eagle Ford resulted in more than 15,000 tons of volatile organic compounds and other contaminants into the atmosphere in 2012 -- more than was emitted by the six oil refineries in Corpus Christi.
Part Three of the Express News report focuses on the role played by the Texas Railroad Commission in regulation of gas flaring. Under RRC regulations, a company can flare gas for 10 days after a well is completed; after that, the company must apply for a permit if it flares more than 50,000 cubic feet of gas per day from the lease. The Express News asked the RRC for records showing the 20 leases in the Eagle Ford with the most gas flared and vented in 2012, and for the permits allowing those companies to flare that gas. It turned out that seven of the 20 leases lacked the necessary flaring permits -- a fact that the RRC apparently had not noticed until the newspaper asked for the information.
The RRC's lack of enforcement of its own rules was a subject of criticism of the agency in the last Sunset Commission review of the RRC. The Sunset Commission report said that the RRC "pursues enforcement action in a very small percentage of the thousands of violations its inspectors identify each year. Part of the reason for the large number of violations is that the commission's enforcement process is not structured to deter repeat violations. The commission also struggles to present a clear picture of its enforcement activities, frustrating the public."
RRC rules provide for a fine of up to $10,000 per day for flaring without a permit. After the Express News pointed out that seven of the 20 highest flaring leases in the Eagle Ford had no flaring permit, the RRC fined two of the companies more than $60,000 and is considering action against the others.
According to the report, the RRC could not point to a single instance when it denied a permit to flare gas -- sometimes for more than 180 days.
Most of the Eagle Ford production is oil -- some natural gas is produced with the oil, but with high oil prices and low gas prices, companies don't want to shut in wells until pipelines can be laid to gather the relatively small amounts of gas produced with the oil. So, the companies flare the gas. Burning the gas produces carbon dioxide, a greenhouse gas. If the gas is not burned completely, or if it is vented, methane and volatile organic compounds are released into the atmosphere.
Last year the RRC appointed an Eagle Ford Shale Task Force to identify and make recommendations to address issues resulting from exploration and production activities in the Eagle Ford play. One of its recommendations was to modernize state regulations, reduce waste of natural gas, and make flaring an "option of last resort." One of the commissioners, David Porter, said that he had "directed commission staff to apply a higher level of scrutiny to applications for flaring and venting operations and to shorten time frames for compliance when violations are reported." No word yet from the Commission on how that "higher level of scrutiny" has affected flaring in the Eagle Ford.
Bottom line: operators will continue to flare gas as long as it is to their economic benefit to do so. The Railroad Commission will not deny permits to flare the gas. If landowners are able to require royalty payments on flared gas, the lessee's economic incentive to flare the gas will be reduced. Eventually, gas prices will rise, gathering lines will be installed, and flaring will decrease. Until then, flares continue to light up the night sky in South Texas.
I ran across an article in the New York Times about a new publication, "The Boom," becoming popular with oil field workers in the Eagle Ford. It's a good read. And it's free online. Check out the article in the August publication, "Eagle Ford Shale Takeaways." It's a reprint of an article from Drillinginfo, based on Drillinginfo's analysis of several thousand wells in the Eagle Ford play. One conclusion from that article:
The very best Eagle Ford Shale operators produce 30% to 40% better than the median FOR THE SAME QUALITY OF ROCK, and they produce three times as much as operators at the low end. ... The implications for mineral owners in this scenario are obvious. Massive gaps in production naturally lead to large gaps in royalty payments. A 25% royalty lease with an average operator is equivalent to an 18% royalty lease with the best operators. That same lease with the worst operators is the same as an 8% lease with the best.
Also check out Texas Eagle Ford Shale Magazine, another digital publication catering to the Eagle Ford play.
The 520,000-acre Waggoner Ranch is for sale for $725 million -- about $1,400/acre. It is said to be the largest contiguous ranch in the U.S., and has been owned by the Waggoner family for more than 100 years.
Ownership of the Waggoner Ranch has been in litigation for more than 20 years. The suit was originally filed in 1991 by Electra Waggoner Biggs, one of the heirs, who died in 2001. Electra was a sculptor; her sculpture of Will Rogers on his horse Soap Suds is on the Texas Tech University campus.
The colorful history of the Waggoner family was documented in an article by Gary Cartwright in Texas Monthly in 2004. It's a great read.
The ranch has its own website, www,waggonerranch.com. The ranch is located in six counties -- Archer, Foard, Knox, Baylor, Wichita and Wilbarger. Here is a map of its boundaries. Of course it has oil, which has held the ranch together, but according to Cartwright the ranch has no groundwater.
The 5th Circuit Court of Appeals in New Orleans has ruled for Chesapeake in two cases, holding that it can deduct post-production costs from gas royalties. Potts v. Chesapeake Exploration, No. 13-10601, and Warren v. Chesapeake Exploration, No. 13-10619. Both cases were decided by the same three judges, and both opinions were written by Judge Priscilla R. Owen. In both cases, Judge Owen relied on the Texas Supreme Court case of Heritage Resources v. NationsBank, 939 S.W.2d 118 (Tex. 1996). Judge Owen was on the Texas Supreme Court when Heritage v. NationsBank was decided, and she wrote an opinion in that case. Judge Owen cites her own opinion in Heritage as the principal precedent for her opinions in Potts and Warren.
The Potts and Warren cases were tried in federal district court. Because Chesapeake's home office is in Oklahoma, it has the right to remove suits filed against it in Texas to federal court. Federal courts have "diversity" jurisdiction over cases between citizens of different states. In diversity cases, federal courts must follow the law of the states. No federal law is involved. So, in deciding Potts and Warren, the 5th Circuit judges were attempting to predict what a Texas court would do, following prior precedent from Texas courts -- in this case, Heritage v. NationsBank.
Heritage v. NationsBank is a seminal case in oil and gas law, some would say infamous. The question in Heritage was whether Heritage, the lessee, could deduct transportation costs for gas from royalties owed to NationsBank. NationsBank's lease provided that royalties on gas would be "the market value at the well of 1/5 of the gas so sold or used, ... provided, however, that there shall be no deductions from the value of the Lessor's royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas." The Texas Supreme Court held that Heritage could deduct transportation costs from NationsBank's royalty. In her concurring opinion, Justice Owen said that the no-deductions proviso on NationsBank's lease was "circular" and "meaningless":
There is little doubt that at least some of the parties to these agreements subjectively intended the phrase at issue to have meaning. However, the use of the words "deductions from the value of Lessor's royalty" is circular in light of this and other courts' interpretation of "market value at the well." The concept of "deductions" of marketing costs from the value of the gas is meaningless when gas is valued at the well.
There were three opinions from the court in Heritage: a majority opinion written by Justice Baker, joined by Chief Justice Phillips, and Justices Cornyn, Enoch and Spector; a concurring opinion by Justice Priscilla Own, joined by Justice Hecht; and a dissenting opinion by Justice Gonzalez, joined by Justice Gregg Abbott. (Cornyn went on to be Texas' U.S. Senator; Justice Abbott subsequently became Texas Attorney General and is now running for Texas Governor; Justice Owen was nominated by President Bush to fill the vacancy on the 5th Circuit left by Judge Will Garwood's retirement in 2001, but she was not confirmed by the Senate until 2005.)
Several amicus briefs were filed in Heritage asking the court to reconsider its decision, but the court refused. Justice Gonzalez, however, wrote an opinion dissenting on motion for rehearing, in which Justices Cornyn, Spector and Abbott joined. It is published at 960 S.W.2d 619. In that opinion, Justice Gonzalez said that the court was evenly divided, 4 to 4, on whether to grant the motion for rehearing. Justice Enoch had recused himself from the case, for reasons not stated, and Justices Cornyn and Spector had changed their minds, now siding with Justice Gonzalez's dissent. And Justice Phillips had decided to concur in Justice Owen's opinion rather than join Justice Baker's original majority opinion. Because a vote of 5 justices is required to grant rehearing, the motion failed. But, said Justice Gonzalez, there was no longer any majority opinion. "Because we are without majority agreement on the reasons supporting the judgment," he said, "the judgment itself has very limited precedential value and controls only this case." And, he predicted, "the Court's error in this case will have far-reaching effects on the oil and gas industry in Texas, as millions of dollars will now be placed in dispute." His prediction has proven true.
Of the two cases decided by the 5th Circuit, Potts is the most interesting. The oil and gas lease from Potts to Chesapeake provided that royalties on gas would be "the market value at the point of sale of 1/4 of the gas sold or used." It also provided:
Notwithstanding anything to the contrary herein contained, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation."
Another lease provision said:
Payments of royalties ... shall be based on sales of leased substances to unrelated third parties at prices arrived at through arms length negotiations. Royalties to Lessor on leased substances not sold in an arms length transaction shall be determined based on prevailing values at the time in the area.
As I have written before, Chesapeake has created a complex relationship among its affiliate companies. One affiliate, Chesapeake Operating, operates the lease for Chesapeake. Another affiliate, Chesapeake Energy Marketing (CEMI), buys the gas from Chesapeake Operating at the wellhead. CEMI gathers the gas from Chesapeake's wells and resells it to purchasers at remote points of sale. The price that CEMI pays Chesapeake for the gas is based on the weighted average price of all gas sold at those remote points of sale, less the post-production costs CEMI incurs between the wellhead and the points of sale. Royalties were paid to Potts based on that net price, so that Potts, as royalty owner, was bearing his share of those post-production costs.
Justice Owen's opinion holds that Chesapeake is entitled to pay Potts royalties net of post-production costs, relying on her own opinion in Heritage v. NationsBank. Potts argued that Heritage was distinguishable, and he pointed to the following sentence from Justice Owen's opinion in Heritage:
There are any number of ways the parties could have provided that the lessee was to bear all costs of marketing the gas. If they had intended that the royalty owners would receive royalty based on the market value at the point of delivery or sale, they could have said so.
Potts' lease provides, as Justice Owen had suggested, that his royalty shall be based on the "market value at the point of sale." But, said Judge Owen, in this case Chesapeake's sale (to its affiliate CEMI) is at the well, so the "point of sale" is on the lease, and the market value at that point is the price received by Chesapeake from its affiliate, net of post-production costs. "Chesapeake has sold the gas at the wellhead. That is the point of sale at which market value must be calculated under the terms of the lessors' lease."
I have seen many lease clauses attempting to prohibit deduction of post-production costs. Some of those clauses include language such as this: "This provision is intended to avoid the result in Heritage v. NationsBank." I've not seen a case construing such a clause. Despite Justice Gonzalez's insistence that Heritage has very limited precedential value, companies have made the most of it, and lessors continue to try to avoid it.