Recently in Texas Railroad Commission Category
Of the $70 million spent by Texas business PACs in 2011-12, $11.9 million, or 9%, was spent by PACs devoted to energy and natural resources issues/candidates. Here are the top spenders:
The above figures represent spending by these PACs both in-state and out-of-state.
Energy Future Holdings is the successor to TXU Corp., acquired by EFH in a $45 billion leveraged buyout. EFH, now threatened with bankruptcy, is one of the state's largest electricity generators. The five EFH PACs spent more than $750,000.
Valero Energy's PAC spent $729,000 of its $2 million in Texas and was a larger supporter of Senator Ted Cruz. ConocoPhillips' PAC spent $221,000 in Texas and gave large sums to Texas Railroad Commissioners.
Lawyer and lobbyist PACs were also big spenders:
In 2010, Public Citizen issued a report on political contributions to Texas Railroad Commissioners. It found that total funds raised by commissioners increased from $511,000 in 2000 to $3.5 million in 2007-2008. Industry donors increased from $230,000 in 2000 to more than $2.1 million in 2008:
Contributions to sitting commissioners increased substantially in 2006 and 2008 election cycles:
Public Citizens' conclusions:
- Most of the increase in funding of commission races is driven by industry and those who have an economic interest in the decisions made by the commission.
- Increased spending by large donors is likely putting pressure on smaller, independent operators to contribute.
- Fundraising rarely ceases, except just after an election.
The Railroad Commission has been up for review by the Texas Sunset Commission in the last two sessions of the Texas Legislature, and both times the legislature failed to enact any of the recommendations of the Sunset Commission --- save one. In 2012, the legislature passed a bill requiring commissioners to resign if they decide to run for another elective office. Governor Rick Perry vetoed that bill. Among the Sunset Commission's recommendations was that the commission should levy more fines for violation of commission rules. In the first quarter of 2013, the commission issued almost 14,000 notices of violations; it collected less than $200,000 in fines.
Final Report of Sunset Advisory Commission on Results of Recommendations on Texas Railroad Commission
The Sunset Commission's final report on the results of its recommendations for reform of the Texas Railroad Commission can be found here. The report's summary:
Summary of Final Results
S.B. 212 Nichols (D. Bonnen) -- Not Enacted
For the second consecutive legislative session the Railroad Commission's Sunset bill failed passage. Initially reviewed in 2011, the Railroad Commission's Sunset bill did not pass and the 82nd Legislature continued the Railroad Commission under Sunset review for another two years.1 In 2013, the Sunset Commission again found a need for the functions of the Railroad Commission. However, with the significant and ongoing boom in oil and gas production, the Sunset Commission concluded having a more transparent and objective regulator was more important than ever. To address these concerns, the Sunset Commission recommended changing the agency's name, limiting when Commissioners could solicit and receive campaign contributions, and requiring the automatic resignation of a Commissioner running for another elected office. The Sunset Commission also recommended several funding changes, including eliminating the statutory cap on the Oil and Gas Regulation and Cleanup Fund and creating a new pipeline permit fee to help support the agency's pipeline safety program.
The Sunset recommendations were incorporated into Senate Bill 212. The Senate passed this bill intact, but ultimately the bill was left pending in the House Energy Resources Committee.
Although the agency's Sunset bill failed passage for a second time, the 83rd Legislature did address a key Sunset Commission concern in other legislation by increasing, rather than eliminating, the cap on the Oil and Gas Regulation and Cleanup Fund. The Legislature also continued the agency for four years, subject to Sunset review again in 2017. One provision -- requiring the automatic resignation of a Commissioner running for another elected office -- was adopted by the Legislature in S.B. 219, the Ethics Commission Sunset bill, that was later vetoed by the Governor.
The following material summarizes Sunset recommendations adopted in other legislation and management actions directed to the agency that do not require statutory changes.
Continues the Railroad Commission for four years until 2017; requires the Sunset review to include an assessment of other state agencies that are able to perform the Railroad Commission's functions; and requires the Railroad Commission to pay all costs of the review. (H.B. 1675)
Directs the Commission to review its recusal policy, and revise as necessary to ensure
Commissioner's awareness of, and compliance with, these requirements. (management action- non statutory)
Increases the statutory cap on the Oil and Gas Regulation and Cleanup Fund from $20 million to $30 million, and increases the Fund's floor from $10 million to $25 million. (H.B. 3309)
Mineral and Land Owner Rights
Directs the Commission to study the use and development of telecommunication technology designed to increase the transparency of, and the public's participation in, agency hearing processes and better protect the rights of mineral owners and land owners in the state of Texas. (management action - nonstatutory)
Directs the Commission to develop a fee schedule for increased charges associated with re-filing previously withdrawn applications for forced pooling or field spacing exceptions. (management action - nonstatutory)
Once again, almost all of the Sunset Commission's recommendations were not adopted, even though comments received were almost uniformly favorable. The only significant legislation that did pass was a requirement that commissioners resign to run for another office - a bill vetoed by the Governor.
Colleen Schreiber has written an excellent article in the June 13 edition of Livestock Weekly, "Landowners Hold Off Oil and Gas Lobby on Common Carrier Bills," describing the blow-by-blow negotiations and lobbying in the pipeline industry's efforts to "solve" the problems created by the Texas Supreme Court's decision in Tex. Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC, 363 S.W.3d 192, 198 (Tex. 2012).
Lined up on one side: pipeline lobbyists supporting bills by Rep. Tryon Lewis, R. Odessa, in the House, and Robert Duncan, R. Lubbock, in the Senate, including the powerful Koch brothers, owners of Koch Enterprises.
On the other side: Texas and Southwestern Cattle Raisers Association, Texas Farm Bureau, Texas Land and Mineral Owners' Association, the Bass family, and plaintiffs' lawyers.
Ultimately, all bills failed. The pipeline industry asked the Governor to add their issue to the special session but, so far at least, pipelines have been overshadowed by abortion bills and financing of higher education projects.
In Denbury, the Supreme Court surprised the pipeline industry by holding that they actually have to prove their proposed line will be a "common carrier" before they can use the power of eminent domain to condemn right-of-way. This left the pipelines, in their view, subject to interminable delays and suits by landowners unhappy with the pipeline routes, the terms of their proposed easements and the compensation being offered.
To "fix" the problem, the pipelines proposed that a pipeline's common-carrier status be determined once for each pipeline, at a hearing held before the Texas Railroad Commission. Landowner lobbyists agreed to negotiate and agreed to consider the concept of a single hearing that would determine common-carrier status for a pipeline; but they wanted the hearing to be before the State Office of Administrative Hearings (SOAH), rather than the RRC; they wanted to be sure all landowners likely to be affected got notice of the hearing; and they wanted strict standards to determine whether a pipeline qualifies as a common carrier. In the end, the biggest sticking point was whether the hearings would be before the RRC or SOAH. Pipelines obviously favored the RRC; the landowners, believing that the RRC would not protect their interests, favored SOAH. (Most administrative hearings related to state agencies in Texas are held before administrative judges at SOAH. The RRC is one of the few agencies that has kept the right to have hearings before its own administrative judges, called hearings examiners.)
A bill might have been hammered out, but late in the game plaintiffs' lawyers, led by Wayne Reaud, a lawyer who made a fortune suing tobacco companies, weighed in and refused to compromise. Reaud at the time was fighting a condemnation action brought by CrossTex for a pipeline that would cross lands he owns in Jefferson County. Reaud claimed that CrossTex should not have the right to survey on his land until it proved that it is a common carrier. He sought and obtained a temporary injunction to keep CrossTex off his property. CrossTex appealed that injunction to the 9th Court of Appeals in Beaumont, and the appeal was pending when the pipeline bills were being considered. (The Beaumont court has since issued its opinion affirming the trial court's decision to grant the injunction. The opinion can be viewed here.) The end result was that the pipeline bills died in committee and never came up for a vote in either the Senate or the House.
Underlying the debate over the pipeline legislation is the perception by those representing landowners' interests that the RRC is not the place to have hearings on the qualifications of pipelines to exercise eminent domain, and the insistence by the pipeline interests that the RRC be the judge. The RRC has jurisdiction to enforce other laws affecting landowners' interests, and their experience has been that the RRC is not an agency friendly to landowners' complaints.
Terrence Henry, a writer for StateImpact Texas, has written a recent article, "Why Oil and Gas Lobbyists Were Big Spenders in Texas." He analyzes two reports on spending on lobbyists and campaigns compiled by Texans for Public Justice. Lobbyists for energy and natural resources companies spent between $31.4 million and $62.5 million on lobbyists during the most recent legislative session, according to the report, 19% of the total of between $155 million and $328 million spent on the session. Incredible numbers. There are no limits on such spending in Texas.
Texas Railroad Commissioners were big beneficiaries of both campaign contributions and lobbying by oil and gas interests. Sunset-recommended reforms of the Commission, opposed by the Commissioners, failed to pass once again. The only RRC-related reform that did pass (but which the Governor has vetoed) was a requirement that a commissioner resign if he/she decides to run for another office. Andrew Wheat, a researcher at Texans for Public Justice, says that's because the oil and gas industry supported that measure: "The [oil and gas industry] is interested in paying their bills while they're commissioners. But they don't want to pony up huge amounts of money every time one of these people wants to run for higher office."
One important bill supported by the energy industry did not pass. It would have limited public participation in hearings at the Texas Commission on Environmental Quality in applications for emissions permits. The bill was opposed by communities and environmental groups. And pipeline companies' bills to make it easier for them to exercise the power of eminent domain to condemn pipeline easements also failed to pass.
The session is over, and the Texas legislature has failed once again to pass sunset legislation for the Texas Railroad Commission. The legislature instead authorized continuation of the RRC for another four years, with sunset review to be repeated in the 2017 legislative session.
Under Texas sunset act, every state agency must go through a comprehensive review of its functions and performance every twelve years by the Sunset Advisory Commission, a 12-member commission appointed by the Lieutenant Governor and the Speaker of the House. The RRC underwent sunset review in 2010; the report of the Sunset Advisory Commission at that time criticized the agency for failing to vigorously enforce its rules and assess penalties for rule violations, and recommended structural reforms of the agency, including replacement of the three elected commissioners with a single appointed commissioner. But the legislature failed to pass any legislation recommended by the Commission, instead requiring that sunset review be repeated for its 2013 session.
The 2012 Sunset Commission report no longer recommended replacing the three elected commissioners with an appointed commissioner. Instead, it recommended ethics reforms, including limiting the time when commissioners could solicit campaign contributions and prohibiting commissioners from accepting contributions from any company with a contested case pending before the RRC. It also required a commissioner running for a different elective office to resign from the RRC. The commissioners vigorously opposed these recommendations and the legislation introduced to enact the reforms.
The legislation continuing the RRC does provide that the next sunset review of the RRC must consider how to dismantle the agency and assign its responsibilities to other state agencies if sunset legislation fails to pass again in four years.
Rep. Dennis Bonnen, R-Angleton, author of the interim legislation continuing the RRC, expressed his frustration at the failure of the process: "I don't see how they can go through a third time -- through sunset and no bill passes -- and we continue that agency. You just can't keep doing that. We need to have the opportunity to have a strategic, orderly plan to dismantle the agency if that's the choice they make. It's the obvious thing to do." Bonnen blamed the agency's commissioners for the failure. "I'll be candid. All of he commissioners were against any changes for ethics. I think that's one of our biggest obstacles. The industry's afraid to agree with the legislators on any policy changes we're making because they don't want to offend the Railroad Commissioners. It's a very bad situation."
Rep. Bonnen claims that Commissioner Barry Smitherman plans to run for Attorney General in 2014, a claim that Smitherman does not deny or confirm. But Smitherman expressed his relief that the RRC won't have to go through sunset review for another four years.
Meanwhile, the RRC finally passed its overhaul of oil and gas well construction rules, Statewide Rule 13, a rulemaking that has been in the works for many months. Industry and environmental advocates -- in particular the Environmental Defense Fund -- worked together on the rule changes, and both expressed satisfication with the result. Scott Anderson, senior policy advisor at EDF, said that "the rule marks a huge turning point in state regulation of the safety and environmental integrity of oil and gas wells. Texas has moved back into the leadership position on regulation of oil and gas well construction. Agencies around the country, including the federal Bureau of Land Management, are likely to learn a lot from studying these rules as well as similar rules adopted last year in Ohio." But Anderson cautioned that one big improvement is still ndeed. "For reasons we don't understand, the commission is allowing operators to leave less space around the pipes in the lower parts of wells than experts recommend. Having enough space around these pipes is important in order to get adequate cement jobs, which are needed both for economic reasons and in order to protect the environment. EDF hopes the commission will revisit this issue in the future."
The new rules don't become effective until January 1, 2014.
A client recently suggested that I should write about landfarming - the practice of disposing of drilling mud and cuttings by spreading it over land.
Drilling mud is the common term for the fluid used in the process of drilling a well. It is made up of a mixture of clay (bentonite) in a base of either water, diesel or mineral oil. It also contains an organic material such as lignite to stabilize the slurry and a material such as barite to increase its density. The drilling mud is circulated through the wellbore - pumped down the inside of the drill stem, through the drill bit, and up the outside or annulus of the hole as the well is being drilled. The drilling fluid carries the cuttings made by the drill bit back up and out of the hole, and it helps to cool the drill bit. The clay also coats the outside of the open hole to help seal off porous geologic strata. The drilling fluid is circulated through a pit or tank, where the cuttings settle out, and re-injected into the hole. Usually an earthen "reserve pit" is constructed for this purpose.
The actual content of drilling mud varies with conditions in the hole and the formations being drilled. In the Eagle Ford, for example, water-based mud is typically used for the vertical section of the hole, and oil-based mud is used for the horizontal section.
After drilling is completed, the drilling mud and cuttings in the reserve pit must be disposed of. These wastes are exempt from federal regulation, and state regulations vary. Landfarming of water-based mud is a generally accepted method of disposing of the contents of the reserve pit in most states.
In Texas, oil and gas exploration and production is regulated by the Texas Railroad Commission, and its rules regarding disposal of drilling fluids are at 16 Texas Aministrative Code Section 3.8, commonly called Rule 8, or "The Pit Rule." That rule defines "landfarming" as "a waste management practice in which oil and gas wastes are mixed with or applied to the land surface in such a manner that the waste will not migrate off the landfarmed area."
In general, Rule 8 allows wastes remaining in reserve pits to be disposed of either by burial on-site or by landfarming on-site. But the rule requires the consent of the surface owner for landfarming:
RRC Rule 8 (16 TAC, Part 1, Sec. 3.8):
(3) Authorized disposal methods.
(C) Low chloride drilling fluid. A person may, without a permit, dispose of the following oil and gas wastes by landfarming, provided the wastes are disposed of on the same lease where they are generated, and provided the person has the written permission of the surface owner of the tract where landfarming will occur: water base drilling fluids with a chloride concentration of 3,000 milligrams per liter (mg/liter) or less; drill cuttings, sands, and silts obtained while using water base drilling fluids with a chloride concentration of 3,000 mg/liter or less; and wash water used for cleaning drill pipe and other equipment at the well site.
(D) Other drilling fluid. A person may, without a permit, dispose of the following oil and gas wastes by burial, provided the wastes are disposed of at the same well site where they are generated: water base drilling fluid which had a chloride concentration in excess of 3,000 mg/liter but which have been dewatered; drill cuttings, sands, and silts obtained while using oil base drilling fluids or water base drilling fluids with a chloride concentration in excess of 3,000 mg/liter; and those drilling fluids and wastes allowed to be landfarmed without a permit.
First, the RRC does not require a permit for on-lease disposal of water-based drilling fluids. If the waste is to be disposed of by burial, the drilling fluids must be "dewatered" before burial. The rule defines "dewatering" as "to remove free water."
Second, if the operator wants to dispose of water-based drilling mud by landfarming on the lease, it must have the permission of the landowner, and the fluids must have a chloride (salt) content of less than 3,000 mg/l.
There are also commercial landfarming operations that take spent drilling mud and dispose of it for operators. Those operations do require a permit from the RRC, and many such permits have been granted. A list of recent permits can be found here. he RRC has specific requirements for such permits, including testing the soil and the drilling fluid for chloride content and heavy metals. A recent story about a criminal investigation of such a commercial operation raises questions about how well the RRC regulates such sites.
Note that disposal of reserve pit contents by burial does not require consent of the surface owner. Unless the oil and gas lease prohibits disposal by burial, the operator will be able to bury the pit contents over the objection of the surface owner. If the mineral owner also owns the surface estate, the lessee may seek to negotiate the right to landfarm pit contents in the lease itself. If the surface owner does not own any minerals, the operator may offer to compensate the surface owner for the right to landfarm pit contents.
Texas A&M's AgriLife Extension Service has published a good summary of the risks and hazards of landfarming pit wastes, which can be found here. Among A&M's conclusions:
- Oil may be contained in water-based drilling mud, part of the materials produced during the drilling operations. Excess amounts of oil - in excess of 1% of the volume of the waste disposed of - are generally toxic to plants.
- Chlorides (salts) in drilling fluid can be detrimental to soils. Soil is generally considered salt-affected or "saline" when the electrical conductivity of the saturated paste extract exceeds 4 millimhos per centimeter.
- Drilling fluids can also contain boron, arsenic, barium, chromium, copper, lead, nickel and other heavy metals that can be harmful in certain concentrations.
A&M recommends that any agreement to allow landfarming should specify testing protocols for possible harmful elements, both in the soil and in the drilling fluids, by a qualified professional; specification of the proper rate of application, and possibly requirements for application of soil amendments to promote treatment of the waste; requirements for mixing the waste into the soil; and requirements for re-seeding and reclamation when the landfarming is complete, possibly with a required bond to assure performance.
In a prior post, I wrote about a new development at the Texas Railroad Commission: granting permits for "allocation wells" - horizontal wells drilled across lease lines without pooling the leases. Since I wrote that post, our firm was retained to represent the parties protesting EOG Resources' application for a permit for an allocation well. A hearing on the application was held at the RRC on December 3. In addition to EOG and the protestants, Devon Energy appeared at the hearing supporting EOG, and the Texas General Land Office appeared opposing allocation wells on State-owned minerals. All parties have now submitted closing statements and responses, which can be viewed below:
Our firm was also retained by the Texas Land and Mineral Owners' Association and several mineral owners to file a petition for rulemaking with the RRC, asking the RRC to address the issue of allocation wells by commencing a rulemaking proceeding. The RRC has not yet responded. The petition can be viewed here: Rulemaking Petition.pdf
Texas' Sunset Advisory Commission has issued its recommendations for changes at the Texas Railroad Commission. The report can be found here.
The RRC was up for regular Sunset review in 2010, and the Sunset Commission issued a report recommending several changes then, including abolishing the three-member elected Commission and replacing it with a single appointed Commissioner. Largely due to debate over that recommendation, most of the Sunset Commission's 2010 recommendations were not enacted, and the Legislature told the Sunset Commission to issue a new report for its 2012 legislative session.
In its current report the Sunset Commission no longer recommends replacing the three elected Commissioners. It recommends changing the Commission's name to the Texas Energy Resources Commission; limiting the time when Commissioners can solicit campaign contributions and prohibiting a Commissioner from accepting contributions from any party with a contested case before the Commission; requiring a Commissioner running for another elected office to resign; and requiring the Commission to adopt a recusal policy rule.
Other proposed changes in the current report of interest to mineral owners include:
- removing the $20 million cap on the Oil and Gas Regulation Cleanup Fund, used to plug "orphaned" wells in Texas. There are an estimated 7,400 orphaned wells that remain unplugged. In fiscal 2012 the RRC plugged 764 orphaned wells.
- giving the RRC authority to impose a pipeline permit fee and to regulate the safety of interstate pipelines.
- requiring the RRC to develop an enforcement policy and penalty guidelines for oil and gas-related violations.
- requiring contested cases to be heard by administrative law judges at the State Office of Administrative Hearings, rather than by examiners who are members of the RRC staff.
In its discussion of the RRC's enforcement policy, the Sunset Commission reports that, since its 2010 Sunset review, the RRC has added 10 new full-time field inspectors (it now has 97 full-time inspectors and 55 additional staff that dedicate part of their time to field inspections). In fiscal 2012 the RRC conducted more than 118,000 inspections and found more than 55,000 violations; it issued 217 penalties and assessed more than $1.9 million in fines. The RRC also uses lease severance - revoking an operator's permit to sell production from a lease - as a method of enforcement. The RRC reported that the RRC issued 11,589 severance notices in fiscal 2012. In 63% of those cases where the RRC sent an operator a notice of severance, the violations were corrected after receiving the notice and an additional 22% of violations were corrected after the lease was severed; the remaining 15% were referred for enforcement action. The Sunset Commission notes that the RRC has adopted penalty guidelines by a new rule that assigns penalties based on the risk posed, the severity of the violation, and instances of repeat violations; and that the RRC is in the process of revising and "field testing" changes to its enforcement policies, requiring field personnel to refer all "major" violations for enforcement action even if the operator comes into compliance after the violation is found. The report says that "recent trend data does suggest an increase in the number of cases referred for enforcement." But the report notes that only 2% of the 55,000 violations were referred for enforcement in fiscal 2012. The report recommends that the Legislature require the RRC by statute to develop an overall enforcement policy that includes criteria for classifying violations and standards for which type of violations to forward for enforcement action.
I continue to believe that responsibility for enforcement of environmental laws related to the oil and gas industry should not reside in the same agency that enforces drilling and spacing regulations and is responsible for promoting development of oil and gas in the State. Moving contested cases to SOAH may help.
The RRC's reputation for enforcement was not helped by a recent report by StateImpact Texas of violations by a commercial disposal facility near Beaumont owned by Pemco Services . The Texas Environmental Enforcement Task Force, run out of the Travis County District Attorney's office, recently won a criminal conviction and a $1.35 million fine against Pemco for violation of its permit to dispose of drilling fluid by "landfarming". The facility was permitted by the RRC, but the RRC failed to require Pemco to comply with its permits for several years, according to the article. ""For over a decade the company was out of compliance with their permit and there was little done to regulate them," said Patricia Robertson, the task force's environmental crimes prosecutor." Pemco was pumping unauthorized stormwater from the landfarm into Peveto Bayou, in voilation of the permit. The prosecutors alleged that, from 2002 to 2009, nearly 57 million gallons of drilling fluids were deposited on the landfarm in voilation of the permit, yet the RRC failed to take any enforcement action. RRC spokesperson Ramona Nye responded to a reporter's request for comment, saying that the RRC "tries to get voluntary compliance to correct violations 'before enforcement action is sought.'" Nye said that the RRC decided not to take enforcement action "as long as Pemco complied with Commission directives to stop accepting waste at the facility and to take actions necessary to close this site." Based on this report, it appears that the RRC still has work to do on its enforcement policy.
I have recently become aware of recent changes in Texas Railroad Commission policies regarding "production sharing agreements" and "allocation wells" that deserve some comment. Some background is necessary to understand these recent developments.
Over the last couple of years I have been asked to review and explain proposed "production sharing agreements" sent to royalty owners. Operators in the Haynesville came up with the concept of production sharing agreements when they were faced with trying to drill wells in areas that were held by production from large pooled units producing from vertical Cotton Valley wells. The pooled units were not configured to allow for efficient drilling of Haynesville horizontal wells. Operators wanted to drill laterals crossing the boundaries of the pooled units, and apparently the pooled units covered the Haynesville depths as well as the Cotton Valley. So, they came up with the idea of production sharing agreements. The agreements provide that the royalty owners in the two existing units agree that production from the horizontal well will be "shared" between the two units based on the percentage of lateral length on each unit, and production allocated to each unit will be treated for lease and royalty payment purposes as if produced from the unit. Devon was a big proponent of these agreements. From the royalty owner's point of view, the agreements have advantages and disadvantages. The advantage is that the royalty owner will get royalties on production from a new well that might not be drilled unless a production sharing agreement is signed to allow drilling across lease or unit boundaries. The disadvantage is that production from one well serves to keep all of the leases in both units in effect for as long as it produces.
A well drilled across lease or unit boundaries pursuant to a production sharing agreement is referred to at the RRC as a "PSA" well, because the permit is granted based on the operator's assertion that it has production sharing agreements with royalty owners for allocation of production between or among tracts; or as an "allocation well," because production from the well is allocated to two or more separate leases or units. When operators began applying for drilling permits for these wells, there was discussion at the RRC about how to handle them, because they did not fit the standard model of pooled units. Eventually, the RRC staff adopted an informal, unwritten policy that, if the operator would represent in its permit application that it had production sharing agreements from at least 65% of the royalty owners in both units, the RRC would grant the permit. The RRC has created a new form, the "PSA-12" form, to replace the Form P-12 that operators must file to represent that they have the right to create a pooled unit. If the operator submits the PSA-12 form, the RRC grants a PSA well permit, based on its informal 65% joinder policy.
I have now learned that recently operators have asked the RRC to grant permits for allocation wells even if they don't have PSAs from 65% of the royalty owners - or even if they have no agreements from royalty owners. The RRC has granted some 40 such permits without requiring the operators to have PSAs with any of the royalty owners. Some of the permits granted for such "non-PSA" allocation wells contain the following disclaimer:
Commission Staff expresses no opinion as to whether a 100% ownership interest in each of the leases alone or in combination with a "production sharing agreement" confers the right to drill across lease/unit lines or whether a pooling agreement is also required. However, until that issue is directly addressed and ruled upon by a Texas court of competent jurisdiction it appears that a 100% interest in each of the leases and a production sharing agreement constitute a sufficient colorable claim to the right to drill a horizontal well as proposed to authorize the removal of the regulatory bar and the issuance of a drilling permit by the Commission, assuming the proposed well is in compliance with all other relevant Commission requirements. Issuance of the permit is not an endorsement or approval of the applicant's stated method of allocating production proceeds among component leases or units. All production must be reported to the Commission as production from the lease or pooled unit on which the wellhead is located and reported production volume must be determined by actual measurement of hydrocarbon volumes prior to leaving that tract and may not be based on allocation or estimation. Payment of royalties is a contractual matter between the lessor and lessee. Interpreting the leases and determining whether the proposed proceeds allocation comports with the relevant leases is not a matter within Commission jurisdiction but a matter for the parties to the lease and, if necessary, a Texas court of competent jurisdiction. The foregoing statements are not, and should not be construed as, a final opinion or decision of the Railroad Commission.
With this background, we now come to the most recent developments: EOG Resources filed an application to drill the Klotzman (Allocation) Well 1-H, in the Eagleville (Eagle Ford 2) Field, in DeWitt County. The proposed well would cross over two different oil and gas leases, neither of which authorizes the lessee to pool the leased premises with any other tract. The owners of the royalty in these two leases filed a protest to EOG's permit application. The protest stirred a discussion at the RRC and caused its staff to call an informal conference on the matter. After that conference, the director of the Hearings Division of the RRC, Collin Lineberry, wrote a letter to the parties, which can be viewed here: Lineberry letter.pdf. Mr. Lineberry said that the royalty owners' assertions "cast sufficient doubt on the applicant's assertion of a good faith claim to preclude the administrative approval of the requested permit at this juncture." He concluded that, if either party wanted to request a hearing on the matter, he would "set an evidentiary hearing to allow both parties to present evidence and argument regarding whether, on the specific facts of this case, EOG has a sufficient good faith claim to authorize issuance of an RRC drilling permit for the proposed allocation well." A hearing has now been set for December 3.
To me, the RRC's issuance of permits for "allocation wells" without requiring the operator to obtain production sharing agreements or pooling agreements from royalty owners in the tracts crossed by the wellbore is in effect allowing operators to force-pool tracts. Forced pooling in Texas is allowed only under limited circumstances and requires an application, notice to affected parties, and a hearing. Texas - unlike other producing states - has never given its regulatory body broad authority to force-pool tracts into drilling units. The RRC staff's "policy" of allowing such permits appears to have been adopted without any hearing and without consideration by the Commissioners themselves. As evidenced by the comments quoted above from one of the allocation permits, the applicants appear to have convinced the Commission staff that the proper allocation of production between tracts on which an allocation well is drilled is a matter of private contract between the parties over which the RRC has no jurisdiction and does not affect its decision whether to grant the permit. This appears to me to be contrary to prior RRC policy and existing RRC rules regarding pooled units, which require the operator to assert in the permit that it has authority to pool the tracts included in the proposed drilling unit.
I expect that there will be further developments on this issue in the near future.
In its 2009 Legislative Session, the Texas Legislature passed House Bill 2259, whose stated purpose is to ensure that inactive oil and gas wells get plugged and that surface equipment associated with those wells gets removed. I provided a summary of the bill's terms in a post on this site. A summary of the bill's requirements from the Texas Railroad Commission may be found here. The Texas Land and Mineral Owners Association, which lobbied for the bill, has now issued its report card: the Railroad Commission is not doing its job.
HB 2259 does not actually require that inactive wells be plugged. It imposes requirements on operators of inactive wells, depending on how long the wells have been inactive, to: disconnect the wells from electricity; post additional bonds to assure that the wells will eventually be plugged; and remove surface equipment from the wells. These provisions are phased in over a 10-year period. HB 2259 provides that an operator who does not comply with the new requirements will lose its operating permit (known as a P-5) -- meaning that it will not have the right to continue to operate any wells in the State.
Recently, TLMA asked the RRC how many P-5 permits have been denied because of failure to comply with HB 2259. The answer: none. Even though, according to TLMA, almost 1,500 operators failed to comply with the statute.
After HB 2259 was passed, operators complained to the Lege that they could lose their P-5 for simple paperwork violations that were not substantive. So the Lege in 2011 amended the statute to provide to the operator an opportunity to appeal the RRC's denial of an operating permit.
TLMA asked the RRC how many violations of the statute resulted from paperwork problems and how many were substantive violations. The RRC was unable to provide that information.
According to the RRC's website, there are 38,854 inactive wells in Texas that have been inactive for 10 years or more. Inactive wells pose a hazard to the environment, including groundwater resources, and are an eyesore on Texas land.
Under a typical oil and gas lease, the operator has no obligation to plug a well as long as the lease remains in effect. When leases reach their later stages of production they are often transferred to smaller operators who continue to operate the active wells on the lease as "stripper" wells. When a lease is transferred, the RRC requires that the permit to operate wells on the lease be transferred to the new operator. As long as the wells are in compliance with RRC rules and the new operator has a valid operating permit, the transfer will be approved. Once transfer of the permits for the wells is approved, the prior operator has no further obligation with respect to the wells transferred. So the prior operator in effect has transferred the obligation to plug any inactive wells on the lease to the new operator. Stripper well operators may have limited financial resources and will continue to defer plugging of active wells as long as they can. In many instances, the stripper operator eventually goes broke, and the obligation to plug the wells falls on the State. The wells become "orphan" wells.
I have struggled to find an appropriate way to address inactive wells in my oil and gas leases. Operators naturally want to delay spending the money to plug inactive wells. One solution I have used in oil and gas leases is to impose a "rental" on inactive wells. The lease provides that the lessee must pay the landowner for the right to keep a well unplugged and inactive. The annual rentals increase over time, thus increasing the operator's incentive to either plug the well or put it back into production. Failure to pay the rental may result in termination of the lease.
With the new drilling boom in Texas, the problem of inactive wells will only continue to increase. It remains to be seen whether HB 2259 will improve the situation.
The Texas Railroad Commission this week approved publication of proposed rules establishing guidelines for admistrative penalties for violations of Commission rules related to pipeline safety, LP gas, CNG and LNG safety, oil and gas operations, and underground damage prevention. The proposed rules will be published February 10, and the comment period ends at noon on Monday, March 12. I encourage anyone who is interested in how the Commission enforces its rules to submit comments. To submit comments online, go to
and look for proposed rule 3.107.
The RRC was reviewed by the Sunset Commission in the last legislative session. The Sunset Commission report criticized the RRC for not assessing enough fines. Among the Sunset Commission's findings:
- RRC inspectors conducted more than 128,000 inspections in FY 2009, finding more than 80,000 violations. The field staff forwarded less than 4 percent of those violations to the central office for enforcement action. (In contrast, the TCEQ forwarded about 20 percent of its more than 11,000 violations for enforcement action in the same year.) The RRC issued 379 penalties, assessing more than $2 million in fines.
- In FY 2009, the RRC found more than 18,000 water protection violations. it took enforcement action on less than 1 percent of those violations, about 150.
- The RRC received 681 complaints related to oil and gas production in FY 2009, and found 1,997 violations based on those complaints. But those complaints resulted in only 91 enforcement actions.
The report concludes that the RRC does not make enough use of penalties for violations: "The efficient and fair use of penalties plays a key role in deterring and punishing violators, and thus increases compliance. The Commission and its field staff go to great lengths to ensure complaince through monitoring and inspections; however, the Commission takes relatively few enforcement actions, resulting in a lack of deterrence for future non-compliance."
The report notes that complaints of limited enforcement action taken by the RRC are not new. The issue was raised in the 2001 Sunset review of the RRC. The report notes that oil and gas drilling has moved into urban areas and is having greater potential impact on underground water resources, which will result in greater scrutiny for the industry and RRC enforcement. "A lack of consistent enforcement can contribute to a public perception that the Commission is not willing to take strong enforcement action."
The report also criticized the RRC for not adequately tracking violations, so that it is unable to determine when repeat violators deserve harsher penalties.
To force the RRC to increase its enforcement activities, the report recommended that
- The RRC be required to develop, by rule, an enforcement policy to guide staff in evaluating and ranking violations.
- The RRC be required to deveop and adopt a rule establishing penalty guidelines, assigning penalties to different violations based on their risk and severity.
- Hearings on enforcement actions should be conducted before the State's independent State Office of Admistrative Hearings, rather than before administrative law judges that are employees of the RRC.
- The RRC be directed to establish a method of tracking violations and enforcement actions and develop a clear and consistent method for analyzing violation data and trends.
- The RRC be directed to publish additional complaint and enforcement data on its website.
The Legislature did not act on any of the Sunset Commission's recommendations; instead, it postponed any action on the recommendations to the next legislative session.
The proposed rules now being published are in response to the Sunset Commission's proposals. Notwithstanding the Sunset Commission's criticism that the RRC does not make enough use of penalties as a deterrent to violations, however, the proposed rules provide that the RRC Commision's policy on violations is unchanged. It says that the proposed guidelines are
a formal restatement of the penalty guidlines that have been used for many years. Significantly, the rule expressly states that the Commission favors a compliance-based approach to enforcement, with safety and environmental protection being the favored outcomes of any enforcement action. Encouraging operators to take appropriate voluntary corrective and future protective actions once a violation has occurred is an effective component of the enforcement process. Deterrence of violations through penalty assessments is also a necessary and effective component of the enforcement process.
The RRC's "compliance-based approach to enforcement" in practice means that the RRC does not fine an operator when a violation has occurred, as long as the operator cooperates in correcting the violation. In my experience, this means that operators don't have to worry about being fined because the RRC will simply notify them of the violation and they can then fix the problem. The proposed rules ignore the Sunset Commission's recommendation that the RRC increase its use of penalty assessments as a deterrent to violations, thus increasing compliance.
The Texas Supreme Court has reversed a decision of the Austin Court of Appeals holding that the Texas Railroad Commission must consider traffic issues in deciding whether to issue a permit for an injection well to Pioneer Exploration, Ltd. in Wise County. In its decision, the Court held that, in considering whether issuance of the permit was "in the public interest," the RRC need not consider the adverse impact on roads and traffic caused by truck traffic to and from the injection well.
The EPA has issued its draft plan to study the impacts of hydraulic fracturing on drinking water in the U.S. Two state regulatory authorities have absolved frac'ed wells from responsibility for contaminating drinking water in Colorado and Texas. Maryland's top einvornmental regulator urged lawmakers to impose a two-year moratorium on frac'ing, as Maryland's legislature considers additional laws to regulate the practice. Meanwhile, the boom in shale gas drilling continues.
Here is the closing statement of Range Resources filed with the Texas Railroad Commission after its hearing on complaints that Range's Barnett Shale wells in Parker County have contaminated groundwater. It provides a good summary of the events to date and the evidence produced at the hearing. Range Production Company Closing Statement.pdf
Here is a link to a summary of the Range dispute prepared by Gene Powell, Editor of the Powell Barnett Shale Newsletter.