Oil and Gas Lawyer Blog

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:

Klotzman Closing Statement.pdf

EOG Closing Statement.pdf

Devon Closing Statement.pdf

GLO Closing Statement.pdf

Klotzman et al Response to Closing Statements.PDF

EOG Reply Closing Statement.pdf

Devon Reply Closing Statement.pdf

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

http://www.rrc.state.tx.us/rules/proposed.php 

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.

Continue reading "Texas Supreme Court Rules Against Citizens Complaining of 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.

 

Continue reading "More About Hydraulic Fracturing in the News" »

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.

The three current Texas Railroad Commissioners and the new incoming Commissioner David Porter all testified before the Texas Sunset Advisory Commission earlier this month, defending the RRC against criticism in the Sunset Commission staff report. The three commissioners are elected by Texas voters, and a position on the commission is often viewed as a steping-stone to higher office.  Two current commission members, Michael Williams and Elizabeth Ames Jones, both considered running for U.S. Senate when Kay Bailey Hutchinson indicated she would step down to run for Texas Governor. State Senator John Whitmire, a member of the Sunset Commission, said that their running for U.S. Senate conflicted with their duties to the Railroad Commission. "You're running for office, but while you're doing that and regulating and making decisions, you're running and actually raising money from the folks that you are regulating." The criticism mirrors the Sunset staff report, which recommends changing the law to have the RRC run by a five-member appointed board. (For my summary of the Sunset staff report recommendations, go here.) Commissioners Victor Carrillo and Michael Williams said they would support a single elected RRC to replace the three-member commission but would oppose a five-member appointed board. Commissioner Jones said she supported the current three-commissioner governance structure.

The Sunset Advisory Commission is composed of ten members: four members of the Texas House of Representatives, four Texas senators, and two private citizens:

Senate Members:

• Glenn Hegar, Jr., Chair
• Juan "Chuy" Hinojosa
• Joan Huffman
• Robert Nichols
• John Whitmire
• Charles McMahen, Public Member

House Members:

• Dennis Bonnen, Vice Chair
• Rafael Anchia
• Byron Cook
• Linda Harper-Brown
• Larry Taylor
• Lamont Jefferson, Public Member

The Sunset Commission will vote on recommendations for legislation to continue and reform the Railroad Commission at its next meeting on Wednesday, January 12.

Range Resources has written to Al Armendariz in EPA's Dallas office again asserting that it is not responsible for the groundwater contamination in Parker County.  Range's letter can be viewed here:  12-27 Armendariz letter.pdf  For my previous posts on this controversy, go here and here.

Range met with EPA staff on December 15, and it says that, as a result of the meeting, Range and EPA agree that "hydraulic fracturing in the Barnett Shale cannot be the cause of natural gas occurring in the domestic water wells identified by the EPA."  Range also made clear in the letter that, while it was complying with the requirements of EPA's order, it did not believe that the EPA had authority to issue its order, since Range was not responsible for the pollution and the order was issued "without any prior notice or opportunity for Range to present important objective facts."

The Dallas Office of the Environmental Protection Agency issued the following press release today:

The U.S. Environmental Protection Agency (EPA) has ordered a natural gas company in Forth Worth Texas to take immediate action to protect homeowners living near one of their drilling operations who have complained about flammable and bubbling drinking water coming out of their tap. EPA testing has confirmed that extremely high levels of methane in their water pose an imminent and substantial risk of explosion or fire. EPA has also found other contaminants including benzene, which can cause cancer, in their drinking water.

EPA has determined that natural gas drilling near the homes by Range Resources in Parker County, Texas has caused or contributed to the contamination of at least two residential drinking water wells. Therefore, today, EPA has ordered the company to step in immediately to stop the contamination, provide drinking water and provide methane gas monitors to the homeowners. EPA has issued an imminent and substantial endangerment order under Section 1431 of the Safe Drinking Water Act. Parker County is located west of Fort Worth, Texas.

In late August, EPA received a citizen's complaint regarding concerns with a private drinking water well. During the inspector's follow-up inquiry, EPA learned that the homeowner had previously complained to the Texas Railroad Commission as well as the company, but their concerns were not adequately addressed by the State or the company. EPA then conducted an on-site inspection of the private drinking water well with the homeowner and a neighboring residence, and returned to collect both water and gas samples. These samples were sent to an EPA certified laboratory for analysis. The data was received in late November 2010 and was carefully reviewed by EPA scientists. The EPA scientists have conducted isotopic fingerprint analysis and concluded the source of the drinking water well contamination to closely match that from Range Resources' natural gas production well.

EPA has asked the company to conduct a full scale investigation. EPA is requiring Range Resources under this order to:

• Immediately deliver potable water to the two residences;
  
• Immediately sample soil gas around the residences;
  
• Immediately sample all nearby drinking water wells to determine the extent of aquifer contamination; and
  
• Provide methane gas monitors to alert homeowners of dangerous conditions in their houses.
  
• Develop a plan to remediate areas of the aquifer that have been contaminated.
  
• And, to investigate the structural integrity of its nearby natural gas well to determine if it is the source of contamination.

EPA has data showing the presence of natural gas at two wells. EPA is ordering Range to investigate other nearby properties to determine if their drinking water is at risk. EPA has been in contact with a rural water system operator approximately 1 mile away, and they are taking steps to test their water for natural gas constituents. Residents of other homes are advised to contact EPA immediately if their wells seize up or if their water begins to effervesce. EPA will contact nearby private well home owners to advise them of our actions and to let them know that we've required the company to test their wells.

The uncontrolled release of natural gas can be dangerous since it is odorless and flammable and it escapes facilities. Uncontrolled release of natural gas inside a building or home can cause a fire or explosion. Drinking water contaminated with natural gas impurities such as benzene is unhealthy.

EPA believes that natural gas plays a key role in our nation's clean energy future and the process known as hydraulic fracturing is one way of accessing that vital resource. However, we want to make sure natural gas development is safe. As we announced earlier this year, we are in the process of conducting a comprehensive study on the potential impact of hydraulic fracturing on drinking water.

In the meantime, EPA has made energy extraction sector compliance with environmental laws one of EPA's National Enforcement Initiatives for 2011 to 2013. The initiative focuses on areas of the country where energy extraction activities such as hydraulic fracturing are concentrated, and EPA's enforcement activities will vary with the type of activity and pollution problem presented.

To my knowledge, this is the first time the EPA has directly intervened in response to a complaint by landowners of groundwater contamination from horizontal shale wells. The EPA's press release emphasizes that the Texas Railroad Commission did "not adequately address" the landowners' complaints.

The EPA's letter to Plains Resources may be found here:  http://www.epa.gov/region6/6xa/pdf/range_letter.pdf 

The EPA's emergency order may be found here: http://www.epa.gov/region6/6xa/pdf/range_order.pdf 

The two Range wells are the Butler Unit 1H and the Teal Unit 1H, both Barnett Shale wells drilled in 2009. The owner of one water well first noticed gas in his water in late December 2009, about four months after the Range wells began producing.  One of the water wells lies about 120 feet in horizontal distance from the track of the Butler well bore, and the other about 470 feet from the Butler well bore.  The EPA did a chemical analysis of the gas found in one domestic water well and found that it was substantially likely that it came from one of the Range wells.

The EPA order says that it consulted with the Railroad Commission and shared its findings with the Commission, and that "appropriate State and local authorities have not taken sufficient action to address the endagerment described herein and do not intend to take such action at this time."  The EPA ordered Range to (1) provide replacement potable water supplies for the owners of the affected water wells, (2) install meters in the landowners' dwellings to detect gas, (3) provide EPA a list of all private water wells within 3,000 feet of the two Range wells along with a plan to sample the water in those wells, (4) submit a plan to conduct testing of soils and indoor air around the dwellings served by the water wells, and (5) submit a plan to identify the gas flow pathways to the aquifer, eliminate such flows, and remediate areas of the aquifer impacted by the gas flows into the aquifer.

Update:  Range Resources has denied that its wells have contaminated groundwater in Parker County.  "The investigation has revealed that methane in the water aquifer existed long before our activity and likely is naturally occurring migration from several shallow zones immediately below the water aquifer," the company said. Two producing Range natural gas wells in the area "are completed in the Barnett Shale formation, which is over a mile below the water zone." The Texas Railroad Commission has scheduled a hearing on the matter for January 10.  http://www.star-telegram.com/2010/12/08/2690723/range-resources-denies-epa-allegation.html 

 

Texas' Sunset Advisory Commission has issued its Staff Reports on review of three of the state's most important regulatory agencies: the Texas Railroad Commission (RRC), the Texas Commission on Environmental Quality (TCEQ), and the Public Utility Commission (PUC). These reports will frame the debate on legislation to renew the mandates of these regulatory bodies in the coming legislative session. Landowners should be aware of the Sunset Commission's recommendations and be prepared to weigh in on those issues that affect landowners' interests. Links to the full staff reports of the Sunset Commission can be found on the Commission's website at http://www.sunset.state.tx.us/ . Below is a summary of some key facts and recommendations on the RRC.

Continue reading "Texas Sunset Commission Makes Recommendations on Review of Railroad Commission" »

EOG Resources has filed an application for designation of two new fields and for temporary field rules for oil wells in seven counties in South Texas (Eagle Ford proposed rules.pdf). Unlike its previous application, which sought to consolidate numerous Eagle Ford fields in Railroad Commission of Texas Districts 1, 2 and 4 and provide for temporary field rules for oil and gas, the new application seeks rules oil well rules only, for seven counties -- DeWitt, Karnes, Gonzales, Wilson, Atascosa, LaSalle and McMullen. EOG asks for expansion of the existing Eagleville (Eagle Ford) Field, renamed the Eagleville (Eagle Ford -2) Field for Karnes and DeWitt Counties, and a new Eagleville (Eagle Ford -2) Field for Gonzales, Wilson, Atascosa, LaSalle and McMullen Counties.

The proposed rules would provide for a minimum 330 feet from lease line spacing, no between-well spacing, and a minimum of 100 feet from lease line to the first and last take points in a horizontal well, a "box" rule, and a special rule for off-lease penetration of the producing formation.

The standard proration unit size for oil wells would be 80 acres, plus additional acreage for horizontal wells as allowed by RRC Rule 86. Under the proposed rules, an operator would be allowed to assign up to 360 acres to a horizontal well with a 5,000-foot lateral.

At the hearing today before the Texas Railroad Commission for consideration of EOG Resources' application for temporary field rules for a new field consolidating 27 existing fields in the Eagle Ford Shale in South Texas, the applicant EOG Resouces announced that it was withdrawing its application. (See my previous post on this application here.) EOG's lawyer said that the application was filed at the suggestion of Railroad Commission staff in order to have uniform rules for all wells drilled in the Eagle Ford, but because of the number of parties who had appeared in the hearing in opposition to the application, EOG would withdraw the application. He said that EOG plans to file a new application for temporary field rules for the Eagle Ford in eight counties where EOG has acreage: Gonzales, Wilson, Karnes, Atascosa, McMullen, La Salle, DeWitt, and Frio Counties. He said that the rules EOG would propose would apply to oil wells only, as EOG's acreage is in the oil window of the play. Other operators in the gas portion of the play are also expected to file additional applications for temporary field rules for gas wells.