Oil and Gas Lawyer Blog

An interesting case has recently been filed in Louisiana challenging the authority of the Louisiana Department of Conservation to approve pooled units containing multiple wells. In Gatti et al. vs. State of Louisiana, et al., Number 589350, Division 23, filed in the 19th Judicial District Court in East Baton Rouge Parish, the plaintiffs sued the State Department of Conservation and several operators in the Haynesville field, including Chesapake, Encana, Exco, Conoco Phillips, Petrohawk, SWEPI, EOG, Questar, Forest and XTO, claiming that the Department of Conservation was routinely allowing the drilling of "alternate unit wells" on previously established units, in violation of Louisiana law. A copy of the petition may be found here.  Gatti v. St of Louisiana.pdf.

Louisiana has a forced-pooling statute that allows an operator to propose to the Department of Conservation a unit for a well which, if approved, forces all mineral owners in the unit to pool their interests for the drilling and production of that well. According to the plaintiffs, this statute only authorizes the Department to approve units large enough to cover an area drained by one well. The practice in Lousiana for the Cotton Valley and Haynesville fields is to obtain orders for 640-acre units, and later obtain approval to drill additoinal "alternate unit wells" on those units. The suit contends that this practice is unfair to the owners of minerals and royalties in the unit, and violates state law. The suit seeks certification of a class action on behalf of all owners of mineral rights in Haynesville Zone in Louisiana. It seeks a declaration that the Department has no authority to establish a unit having an area in excess of the area drainable by one well, and that any such unit is "null and void." The suit also seeks unspecified damages against the defendant companies.

An interesting article describing the history of forced pooling in Louisiana and arguing that multiple-well units are illegal may be found at fairdrilling.com.

I have written previously about the proceeding before the Texas Railroad Commission for adoption of field rules for the Carthage (Haynesville Shale) Field. In that proceeding, the applicants sought and obtained field rules establishing a standard proration unit of 640 acres for wells in the field, with "optional" 40-acre units. The examiners who heard the evidence opined that Devon had produced no evidence that a well in the field could drain 640 acres, and they recommended a 320-acre standard unit, but the Commissioners overruled them and agreed to Devon's request for 640-acre units.

It appears that in both Lousiana and Texas the regulators are going along with the fiction advocated by operators that wells in the Haynesville should be developed with 640-acre units, despite the fact that everyone knows the wells will in fact be drilled with 160 or 80-acre spacing. Everyone understands that this fiction is intended to accommodate the desires of the operators to construct larger units in order to (i) have more flexibility in how they space their wells and (ii) hold more acreage with a single well. I have sympathy with the first objective, but not with the second. It is impossible to drill wells with horizontal legs of 5,000 feet or more unless fairly large units are created. Conversely, it is unfair to the mineral owners in a large unit for their leases to be held by production from a single well in the unit where several wells are necessary to fully develop the reservoir under their lands.

The Bureau of Land Management has signed a settlement agreement in which it agreed to "suspend" oil and gas leases covering BLM lands in Montana until it has completed a review of the effect of oil and gas development on greenhouse gas emissions.

The settlement was entered in Montana Environmental Information Center, et al. v. United States Bureau of Land Management, Case No. 08-178-M-DWM, in the U.S. District Court for the District of Montana, Missoula Division, on March 11, 2010. The case was brought by citizens groups who contended that federal law required the BLM to consider the cumulative impacts of oil and gas development on the environment, and specifically the greenhouse gas emissions caused by oil and gas well drilling and production, before granting oil and gas leases on lands in Montana.

The plaintiffs' petition contains some interesting facts:

The State of Montana published a Greenhouse Gas Emissions Inventory and Reference Case Projections 1990-2020G, in 2007; it estimated that oil and gas operations in Montana released 4.7 million metric tons of CO2 or its equivalent in 2005, more than 12% of the state's total GHG emissions.

According to the Inventory of U.S. GHG Gases and Sink: 1990-2006, by the Environmental Protection Agency, oil and gas systems are the largest human-made source of methane emissions and account for 24% of methane emissions in the U.S. - 2% of the U.S.'s total GHG emissions. (Methane - natural gas - has 21 times the global warming impact of carbon dioxide.)

The EPA has a program called the Natural Gas STAR Program, designed to encourage oil and gas companies to voluntarily reduce their GHG emissions by following GHG reduction technologies and practices. EPA reported that industry partners in its STAR Program achieved GHG emission reductions totaling 92.3 billion cubic feet. This is equivalent to the annual greenhouse gas emissions from approximately 6.8 million passenger vehicles.

Companies producing oil and gas have reported success in utilizing a number of methane reduction measures, including replacement of high-bleed pneumatic controllers with low-bleed pneumatics, installing plunger lifts, using "green" completions (not venting gas produced during completion operations), replacing gas-actuated pumps with solar electric pumps, and utilizing vapor recovery units (devices that capture vapor emitted from storage tanks and recycle it back into the production stream), and conducting regular inspections of facilities to identify and reduce fugitive leaks from valves, flanges and other connectors.

We may expect that federal agencies like the BLM and the Minerals Management Service, who are responsible for leasing of federal lands, will move toward imposing requirements on oil and gas operators to reduce their GHG emissions by using best available technologies like those enumerated in the plaintiffs' petition in this case. Those same technologies could be used to reduce emissions in and around the Barnett Shale, where residents are increasingly complaining about emissions from oil and gas compressors and other facilities.

Speaker of the House Joe Strauss has charged the House Committee on Energy Resources as follows for the next legislative session:

"Survey current local ordinances governing surface use of property in oil and gas development. Recommend changes, if any, to the authority of the Railroad Commission to regulate the operation of oil and gas industries in urban areas of the state, particularly the Barnett Shale."

It seems evident from this charge that operators in the Barnett Shale will be asking the Texas Legislature to curtail the authority of municipalities to issue drilling permits for areas within their jurisdiction, or at least to limit what conditions they can place in those permits. Drilling ordinances such as those in Fort Worth and surrounding cities are becoming quite sophisticated, and place significant conditions on the granting of permits, including distances from houses and other structures, sound limits, handling of frac water, produced water and other wastes, safety requirements, traffic, and damage to surrounding streets. The City of Grapevine has revised its drilling ordinance to require an 8-foot masonry wall around the wellsite and shrubbery between 3 and 5 feet high along the wall. The City of Flower Mound is considering revision of its drilling ordinance to require companies to report their airbrorne emissions and use vapor recovery technology. In some cases, municipal ordinances are so stringent that as a practical matter they prevent drilling within city limits. I expect that eventually constitutional takings claims will be made against cities whose restrictions prevent any mineral development within their limits.

If the Legislature restricts municipal permitting authority, it could enlarge the requirements that the Railroad Commission must impose, or at least consider, when granting permits in urban areas, to include environmental considerations. The Austin Court of Appeals recently held that the Commission must consider the impact of traffic when ruling on an application for a disposal well permit. The Commission has appealed that decision, and the Texas Supreme Court has agreed to consider the case. Texas Citizens for a Safe Future and Clean Water v. Railroad Commission of Texas, 254 S.W.3d 492 (Tex.App.-Austin 2007, review granted March 12, 2010). It appears that the Commission would not relish the idea of regulating issues of traffic, noise, safety and pollution issues in urban settings, in connection with applications for well permits.

In a previous post I reported on the application of Devon Energy asking the Texas Railroad Commission to include in the new Field Rules for the Carthage (Haynesville Shale) Field a provision allowing it to drill horizontal wells across lease or pooled unit boundaries.  These new rules apply to wells drilled in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Shelby and Rusk Counties in East Texas. Devon asked that the rules provide what it calls a "default allocation method" for horizontal wells drilled across unit boundaries.The rule proposed by Devon reads as follows:

"Operators shall be permitted to drill and complete horizontal wells that traverse one or more units and/or leases as long as that operator has a lease or other mineral ownership right to produce from each such unit or lease. If such a well is not already subject to an agreement regarding the allocation of production, the following allocation formula will be presumed to constitute a fair and reasonable allocation of production from a well in this field and shall be utilized by the Commission in assigning acreage attributable to the separate units/leases traversed by the horizontal drainhole: an allocation of acreage and production to each of the units and/or leases traversed by and completed in the horizontal well based on the percent of said horizontal well from first take point to last take point that lies under each unit or lease."

The Commission concluded that it had no authority to adopt such a rule, because pooling is a contractual issue between private parties, and (except as provided in the Mineral Interest Pooling Act) the Commission has no right to impose allocations of production among different tracts penetrated by a horizontal well.

In its appeal, Devon argues that the Commission's refusal to adopt its proposed "allocation rule" is arbitrary and an abuse of its discretion, without a rational basis, discriminates against producers in the Carthage Field, and will result in the waste of oil and gas.

I believe that Devon has little chance of forcing the Commission to adopt its proposed "allocation rule." But if it is successful, it is certain that operators in the Barnett Shale and other shale fields now being developed in Texas will ask for a similar rule. Such a rule would have significant impacts on royalty owners and their rights to consent to pooling of their royalty interests.

 

On December 15, the Railroad Commission adopted new field rules for a newly designated field, the Carthage (Haynesville Shale) Field, in East Texas. It also consolidated several previously designated fields in East Texas that produce from the Haynesville and Bossier formations into this single RRC-designated field. These rules will govern the development of the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Rusk and Shelby Counties in East Texas. These new rules are important to landowners principally because they will give operators a basis to form pooled units of up to 640 acres or more for development of the field.

A little backrgound is in order: Large portions of the land in East Texas within the Haynesville and Bossier play were previously drilled to develop the shallower Travis Peak and Cotton Valley formations. The field rules originally adopted for the Cotton Valley fields provided that only one well could be drilled for each 640 acres of land. Over time, the field rules were amended to allow operators to drill wells in the Cotton Valley with a density of as little as 40 acres per well. Operators initially formed pooled units of up to 704 acres, a size allowed by most lease standard pooling clauses. Cotton Valley wells drilled on these pooled units are still producing, thus keeping in force the leases included in the pooled units. Generally, the pooled unit designations filed by operators for the Cotton Valley wells pooled all depths under the units, including the Haynesville and Bossier formations, which lie immediately below the Cotton Valley formation. Companies now desire to develop the deeper Haynesville and Bossier formations under these Cotton Valley units.

Field rules are special rules adopted by the Railroad Commission governing the spacing of wells in a designated field. Once special field rules are adopted for a field, they govern how wells must be spaced in that field and how much acreage an operator must have to drill a well in the field. Special field rules are adopted in response to an application made by an operator of wells in the field. The operator presents evidence to hearings examiners at the RRC as to the characteristics of the formation and how much area will be drained by a well in that field, and the operator proposes rules to be adopted by the RRC. The hearing examiners review the evidence and may or may not adopt the rules requested by the applicant. The hearing examiners make a recommendation to the three RRC commissioners, and the commissioners may either adopt the recommendations of the examiners or make changes in those recommendations.

Devon Energy Production Co., LP made application to the RRC for new field rules for development of the Haynesville and Bossier formations in East Texas, and it requested that several fields previously designated by the RRC be consolidated into a single "field" for purposes of the new rules. The new rules proposed by Devon would govern wells completed in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Rusk and Shelby Counties. In effect, Devon proposed that the Haynesville and Bossier formations be treated as a single formation for RRC regulatory purposes. Devon identified the Haynesville-Bossier formation as the formation found at depths between 9,568 feet and 11,089 feet in the Devon-Hull Unit A Lease, Well No. 102 (API No. 42-365-36749), in Panola County. This interval is more than 1,500 feet in thickness.

Continue reading "Texas Railroad Commission Adopts New Temporary Field Rules for Carthage (Haynesville Shale) Field" »

Three law firms in Dallas have joined to sue oil companies who backed out of leases covering lands in Arlington, Texas last fall. The three firms -- Petroff & Associates, Riddle & Williams, P.C., and Mathis & Donheiser, P.C. -- have so far filed two suits on behalf of two lot owners who say they had binding deals with companies to lease their property. The law firms have created a website at www.ntxleaselitigation.com, and are organizing meetings of landowners who believe they had lease deals with XTO . The interesting part of the two lawsuits filed so far is that they name as defendants not only the company that allegedly had agreed to pay for leases of the two plaintiffs' properties, but also multiple other companies and their leasing agents who were leasing in the Barnett Shale.  The suits claim that all of these companies conspired last fall to revoke their outstanding lease offers and to drive down the bonus price for leases, in violation of antitrust laws. For a story in the Fort Worth Star Telegram on the cases, see http://www.star-telegram.com/804/story/1593837.html . According to the suits, the plaintiffs were in an area of Arlington organized to negotiate leases for its landowners called the Southeast Arlington Coalition of Texas (SEACTX). SEACTX claimed that it had a deal to lease to XTO Energy for $26,517 per acre.  Here are copies of the two petitions:  08-06-09BoothOriginalPetition[1].pdf and 08-31-09MylesOriginalPetition[1].pdf

A Delaware bankruptcy judge has ruled in the SemCrude bankruptcy that the claims of Texas producers for unpaid revenues from oil sales are subordinate to the claims of SemCrude's bankers. As a result, the Texas producers (and perhaps their royalty owners) may lose up to $57 million.

SemCrude filed for protection under Chapter 11 of the Bankruptcy Code in July 2008. SemCrude was a large purchaser of crude oil in Texas and seven other states. At the time of the filing, the SemCrude entities owed their banks $2.55 billion. It also owed more than one thousand oil and gas producers millions of dollars for oil purchased but not paid for in June and July 2008, including $57 million owed to oil and gas producers in Texas.

The court in the SemCrude bankruptcy recently ruled that the claims of Texas Producers for the $57 million in unpaid proceeds of oil and gas sales are subordinate to the claims of SemCrude's Banks, who hold liens on all os SemCrude's assets, despite a Texas statute that grants the Texas Producers a lien on their production and all proceeds of sale to secure the purchaser's obligation to pay.

The arguments made in the dispute between the Banks and the Texas Producers are complicated because they involve the interpretation of Article 9 of the Uniform Commercial Code, a code that has been the bane of many law students' studies. The judge's ruling will be appealed and so is not the final word on the matter, but if the ruling stands it will adversely affect the rights of royalty owners in bankruptcy proceedings of oil and gas purchasers and producers, and could greatly reduce their rights to recover payments for their royalties.

Here is a simplified summary of the judge's ruling:

Continue reading "Delaware Bankruptcy Court Rules Against Texas Producers (and Royalty Owners)" »

Jerry Patterson, Commissioner of the Texas General Land Office, has weighed in on the side of the O'Connors in their fight against ExxonMobil. The General Land Office has filed an amicus brief urging the Texas Supreme Court to reconsider its decision in Exxon v. Emerald; Commissioner Patterson issued a press release ( press release.pdf) saying that he has requested the Texas Railroad Commission to hold hearings into ExxonMobil's "intentional sabotage of oil wells in Refugio County as well as the company's fraudulent reports covering up the damage;" and, in response to ExxonMobil's letter to the Railroad Commission ( Exxon-RRC letter.pdf) denying Commissioner Patterson's allegations and arguing that no such hearing is necessary, Commissioner Patterson has written a lengthy reply ( GLO Letter to RRC.pdf), citing evidence from the case showing ExxonMobil's false reporting of its plugging operations, and concluding that, "If these intentional false filings and improper pluggings do not result in substantial penalties by the Railforad Commission, then the oil & gas industry in Texas will be on notice that Railroad Commission's rules and forms are optional, not mandatory."

 

Continue reading "Texas GLO Commissioner Jerry Patterson Weighs in on Exxon v. Emerald" »

The Texas Supreme Court has been asked to review a case decided by the Eastland Court of Appeals, Lesley v. Veterans Land Board, that raises important questions about the duty of a mineral owner to owners of non-executive mineral interests. If the Court decides to take the case, the outcome could have important implications for future development of mineral interests in urbanized areas of Texas.

The important facts in Lesley are as follows:

Continue reading "Texas Supreme Court asked to take up duty of holder of executive rights in Lesley v. Veterans Land Board " »

In a previous post I discussed a recent Texas Supreme Court case, Exxon v. Emerald, reversing a multimillion-dollar judgment against Exxon for intentionally sabatoging wells so that they could not be re-entered. This nudged me to look at other royalty-owner related cases handed down by the Texas Supreme Court over the last ten years. The court's record is not a good one for royalty owners. Highlights of the Court's work:

HECI v. Neel (1998). HECI sued an adjacent operator for illegal production on an adjoining lease that damaged the common reservoir underlying both leases, and recovered a judgment for more than $3.7 million. HECI did not inform its royalty owners of the suit and did not share any of the judgment proceeds with the royalty owners. When HECI's royalty owners found out about the suit, they sued HECI to recover their share of the judgment. The Supreme Court held that the royalty owners had waited too long to bring their suit, even though they did not find out about the suit until five years after the trial. The Court held that the royalty owners should have known that the adjacent operator was damaging the common reservoir by its operations.

Yzaguirre v. KCS Resources (2001). Plaintiffs were royalty owners who received royalties under a lease operated by KCS. KCS sold its gas under a 20-year contract with Tennessee Gas Pipeline, and the price under the Tennessee contract greatly exceeded the spot market price of the gas. But KCS paid royalties based on the "market value" of the gas, using comparable spot sale prices, well below the price it received from Tennessee. The Court held that KCS did not owe royalties based on the Tennessee price -- and, it held that the Tennessee contract was not even competent evidence of the market value of the gas.

Wagner & Brown v. Horwood (2001). Plaintiffs sued Wagner & Brown for deducting excess compression fees from their royalties that were charged by a Wagner & Brown affiliate. The Supreme Court ruled that all claims for royalties paid more than four years prior to the suit were barred by the four-year statute of limitations. Plaintiffs argued that Wagner & Brown had falsely told them, when they inquired about the fees, that the fees were only 12 cents per mcf, rather than 25 to 30 cents, so Wagner & Brown should not be allowed to rely on the statute of limitations. The Court rejected this argument, holding that the Plaintiffs' claims were not "inherently undiscoverable," even if Wagner & Brown lied to them about the charges.

Natural Gas Pipeline Company of America v. Pool (2002). Plaintiffs sued NGPL claiming that two leases had terminated due to a lack of production. The trial court entered a judgment for lessors on a jury verdict, which the Court of Appeals affirmed. The Supreme Court reversed.  It held that, if the leases had terminated for lack of production, the lessee had subsequently re-acquired title to the leases by adverse possession. This is the first case in the country to hold that adverse possession statutes apply to recover title to an expired oil and gas lease.

In re Bass (2003). Plaintiffs owned a royalty interest under a ranch owned by the Bass family. The Basses refused to lease their land for oil and gas exploration, and the royalty owners sued them for breach of an implied duty to develop the land. The Supreme Court held that the Basses had no implied duty to lease or develop the minerals under their property.

Union Pacific Resources Group v. Hankins (2003). Royalty owners in Crockett County brought suit against Union Pacific, alleging that UPRG was selling gas to an affiliated company at a low price and then reselling it at a higher price, but paying royalties on the lower price.  The plaintiffs sought to make the case a class action brought on behalf of all royalty owners in UPRG wells in Crockett County.The Supreme Court held that the case could not be brought as a class action because the royalty language in the leases could be different.

Kerr-McGee Corp. v. Helton (2004). Kerr-McGee drilled a well, the Holmes 17-1, in Wheeler County which produced more than 8.7 billion cubic feet of gas. The well was located 660 feet from the Heltons' lease. Kerr-McGee did not drill an offsetting well on the Helton lease, and the Heltons sued Kerr-McGee for failing to protect their lease against drainage from the Holmes 17-1. The trial court awarded $860,000 in damages, and the Court of Appeals affirmed.  But the Supreme Court reversed, ruling that the plaintiffs should have no recovery.  The Court held that the plaintiffs' expert witness had not adequately explained how he had measured the amount of gas that would have been produced from a well on the Helton lease if Kerr-McGee had drilled it;  the Court said that there was "simply too great an analytical gap between the data [relied on by the expert] and the opinion proffered."  The Court refused the plaintiffs' request to remand the case for a new trial.

Forest Oil Corp. v. McAllen (2008). In 1999, Forest Oil settled a lawsuit with McAllen and others who own the McAllen Ranch in Hidalgo County, over claims for royalties and leasehold development. In 2004, McAllen filed a separate suit against Forest to recover for damages caused by burying mercury-contaminated and radioactive material on the ranch.  Forest claimed that McAllen was obligated by the 1999 settlement to arbitrate any disputes over its operation of the lease. McAllen claimed that he was fraudulently induced to sign the settlement and was not bound to arbitrate his claims. The Supreme Court held that McAllen was contractually bound to arbitrate. It held that language in the settlement agreement, providing that McAllen was not relying on any statement or representation of Forest in executing the agreement, prevented McAllen from arguing that he was fraudulently induced by Forest to sign the settlement agreement. In so holding, the Court overruled a prior case it had decided in 1997, in which it held that a settlement agreement must "clearly express .. the parties' intent to waive fraudulent inducement claims" in order to preclue a fraudulent inducement claim.

I was unable to find any Supreme Court case in the last ten years that ruled in favor of royalty owners.

On March 27, the Texas Supreme Court issued its opinions in two related cases, both styled Exxon Corporation v. Emerald Oil & Gas Company. The cases were argued before the court more than two years ago, and the decisions were awaited with much anticipation. The Court reversed a judgment against Exxon for $8.6 million in actual damages and $10 million in punitive damages.

The facts in the case are remarkable. In the 1950's Exxon's predecessor Humble Oil & Refining Company obtained oil and gas leases covering several thousand acres in Refugio County owned by the O'Connor family. The leases were quite unusual;  among other things, they provided for a 50% landowners' royalty. Exxon drilled 121 wells and produced more than 15 million barrels of oil and 65 billion cubic feet of gas from the O'Connor lands. In the 1980's Exxon asked the O'Connors to reduced their royalty, claiming that the leases were becoming uneconomical.  Those negotiations failed, and in 1989 Exxon notified the O'Connors that it intended to start plugging wells and abandoning the leases. Negotiations for the O'Connors to take over operation of the wells were not successful, and Exxon began plugging wells and abandoning the leases.

 

Continue reading "Exxon v. Emerald" »

A recent decision of the Texas Supreme Court, Wagner & Brown, Ltd. v. Sheppard, has caused quite a stir in oil and gas legal circles.  The court was faced with a question never before answered by a Texas appellate court, what is known as a "case of first impression."  Such cases are always interesting to oil and gas lawyers, so I thought I would weigh in on the arguments.

The facts in the case are these:  Jane Sheppard owns a 1/8th mineral interest in 62.72 acres in Upshur County.  She leased her 1/8th interest, and her lease - along with leases of the other 7/8ths interest in the 62.72 acres and leases of other lands- was pooled to form the W.M. Landers Gas Unit, containing 122.16 acres.  Two wells were drilled on Sheppard's tract, both producing gas. 

Sheppard's lease contains a provision requiring payment of royalties within 120 days of first sales of gas, failing which the lease would terminate.  She was not paid on time, and her lease terminated.

Texas law is clear that, if there had been no pooled unit, upon termination of her lease Sheppard would become what is known as a "non-consenting co-tenant" in the two wells on her tract.  She would be entitled to receive her 1/8th share of proceeds of sale of gas from the wells, less 1/8th of the costs of production and marketing.  But Wagner & Brown contended that Sheppard's tract was still bound by the pooled unit, even though her lease had expired.  Under the pooling clause in Sheppard's lease, her royalty would be calculated based on the number of acres of her tract compared to the total number of acres in the unit - in this case, 62.72/122.16, or 51.34% of the wells' production.  Wagner & Brown contended that Sheppard should receive 1/8th of 51.34% of production from the wells, less that same fraction of the cost of production and marketing.  The Supreme Court agreed with Wagner & Brown, holding that "the termination of Sheppard's lease did not terminate her participation in the unit."

Continue reading "What happens to a pooled lease when the lease terminates?" »