The Energy Law Blog

EPA Issues New Air Regulations for the Oil and Natural Gas Industry

Kelly Becker — Fri, 20 Apr 2012 08:46:25 -0500

By Stephen Wiegand

On April 17, 2012, the United States Environmental Protection Agency (EPA) finalized New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) for natural gas wells that are hydraulically fractured.

The rule aims to reduce levels of volatile organic compounds (VOCs) released during well completion. Prior to January 1, 2015, operators may use flaring to reduce such emissions. Beginning January 1, 2015, however, operators must reduce emissions by installing equipment that captures natural gas during completion and makes it available for use or sale.

The rule also establishes new notification and reporting requirements for well completions. It requires that owners or operators of hydraulically fractured and refractured natural gas wells notify EPA by e-mail no later than two days before completion work begins. Additionally, each year owners or operators must submit a report on their well completions that is certified by a senior company official attesting to the report’s truth, accuracy, and completeness.

The rule retains existing NESHAP standards for large glycol dehydrators at well sites and also sets new NESHAP standards for small glycol dehydrators (ones with an annual average natural gas throughput of less than 85,000 standard cubic meters per day, or actual annual average benzene emissions of less than 1 ton per year). Small dehydrators must meet a unit-specific limit for emissions of BTEX (benzene, toluene, ethylbenzene, xylene) that is based on the unit’s natural gas throughput and gas composition.

In addition to the new standards for hydraulically fractured wells, the rule also updated existing standards for natural gas processing plants, storage tanks, and transmission lines.

For more information, see www.epa.gov/airquality/oilandgas/actions.html

Supreme Court of Texas Revises Opinion in Pipeline Common-Carrier Case

Robert Theriot — Thu, 12 Apr 2012 14:48:13 -0500

By Carlos Moreno:

The Supreme Court of Texas recently delivered a revised opinion discussing the power of eminent domain exercised by a common carrier CO2 pipeline. In Texas Rice Land Partners, LTD v. Denbury Green Pipeline-Texas, LLC, No. 09-0901, 2012 Tex. LEXIS 187 (Tex. Mar. 2, 2012), the Court was asked if a landowner can challenge in court the eminent domain power of a CO₂ pipeline owner with a common carrier permit from the Railroad Commission of Texas (“RRC”). The Court decided in favor of the landowner.

Denbury Green Pipeline-Texas LLC, a subsidiary of Denbury Resources, applied with the RRC for a permit to build and operate a CO₂ pipeline in Texas. Denbury Green noted in its permit application that the CO₂ pipeline would be operated as a “common carrier”, and indicated that the gas would be “owned by others, but transported for a fee.” Denbury Resources had plans to purchase CO₂ from third parties in the future, but the immediate plans were to only transport CO₂ owned by Denbury Resources. The RRC approved the permit, including common carrier status. Denbury Green then attempted to condemn a pipeline easement from land owned by Texas Rice Land Partners, Ltd. (“Texas Rice”). However, Texas Rice refused entry. Litigation ensued, with the lower courts finding in favor of Denbury Green.

The Court began its discussion by examining the power of eminent domain in Texas. The Court noted that Texas law prohibits the taking of property for private use, and requires just compensation for public use takings. The Legislature can grant eminent-domain power, but if the statute leaves doubts about its scope, the Court held that the statute will be strictly construed in favor of the owner of the condemned land.

At the outset, the Court also had to determine whether the Commission’s common-carrier finding could be challenged in court. The Court first noted that the statute does not state that the Commission’s decision to grant a common-carrier permit is conclusive and unreviewable by the courts. In addition, the Court described the process to obtain common-carrier status from the RRC as “one of registration, not of application” with no adjudication, notice, or hearing. Texas Rice, at *18. The Court found that this process by itself failed to meet constitutional requirements.

Finding that the landowner could judicially challenge the eminent domain finding, the Court then determined what the proper judicial test for common-carrier status should be. To be a common carrier, the Court said, the pipeline must serve the public and not just the pipeline owner or its affiliates. Denbury Green argued that making the pipeline available for public use is sufficient to obtain common-carrier status. The Court found this interpretation to be inconsistent with the statutory language. In addition, the Court found that merely stating that the pipeline is available for public use could allow a carrier to obtain eminent domain powers even if it knows that no other party would ever desire to use the pipeline.

However, the Court went further and said that “a carrier is not a common carrier if it transports gas only for its own consumption.” Thus the Court found that even if Denbury buys CO₂ gas from third parties, common carrier status is not proven if after transportation all the CO₂ is then used by the owner of the pipeline. Therefore, in order to be a common carrier, some of the CO₂ being transported must be owned by a third party (not including subsidiaries of the pipeline owner), then either retained by the third party or sold to a party other than the carrier or its affiliates.

The Court held that for a CO₂ pipeline carrier to qualify as a common carrier, “a reasonable probability must exist that the pipeline will at some point after construction serve the public by transporting gas for one or more customers who will either retain ownership of the gas or sell it to parties other than the carrier.” Texas Rice, at *26. A granted common-carrier permit will still be prima facie valid, but a landowner can challenge it in court. If there is a judicial challenge, the pipeline company would have to burden to prove that it is indeed a common carrier before it can exercise the power of eminent domain.

In the case at bar, the Court found that Denbury Green did not meet the requirements for common-carrier status as a matter of law. The evidence showing that Denbury could be transporting CO₂ from third parties was not enough to show a reasonable probability. Even if Denbury transported CO₂ from third parties, its intention was to use all the CO₂ in Denbury’s oil fields for tertiary recovery. Thus, Denbury would be the only end user of the CO₂, making it a private carrier.

The Court explicitly stated that its opinion is limited common-carrier status for pipelines transporting CO₂ or hydrogen gas under Section 111.002(6). However, if the reasoning were extended in the future to other pipeline operations, common-carrier status would require companies to not only transport products other than its own, but also have one or more third-party end users after pipeline transportation.

EPA Proposes Significant Changes to NPDES Permit for Oil and Gas Facilities in the GOM OCS

Robert Theriot — Thu, 12 Apr 2012 14:41:58 -0500

By Carlos J. Moreno

On March 7, 2012, the Environmental Protection Agency (“EPA”) published in the Federal Register a proposed NPDES general permit for discharges from oil and gas facilities in the western and central portion of the Outer Continental Shelf of the Gulf of Mexico (the “proposed permit”). See 77 Fed. Reg. 13601 (Mar. 7, 2012), available at http://www.epa.gov/region6/water/npdes/genpermit/index.htm. Affected companies may wish to comment on proposed changes to the permitting and reporting process, and to the effluent limitation and monitoring requirements. Comments are due by May 7,2012. Some of the most significant proposed changes are described below.

Notice of Intent and Discharge Monitoring Reports

Under the proposed permit, any party that meets one of the following criteria would need to obtain coverage as an “operator”: (1) possession of lease block and operational control over activities, (2) day-to-day operational control of activities necessary to ensure compliance with the permit, or (3) operational control over a vessel or Mobile Offshore Drilling Unit (“MODU”) subject to Cooling Water Intake Structures (“CWIS”) regulations. As for Discharge Monitoring Reports (“DMRs”), the proposed permit states that “monitoring results for each facility within the particular lease block shall be reported on DMRs for each individual outfall authorized that has a monitoring requirement.” Proposed Permit, at p. 52 (emphasis added). This language suggests a potential need for separate permit coverage for any MODU subject to CWIS requirements.

Effluent Limitations and Monitoring

The proposed permit includes new effluent limitations and monitoring requirements for specific discharges, as well as a number of clarifications about the authorization status of specific waste streams. For example:

· Operators must conduct a Produced Water Characterization Study (individual or joint study);

· All hydrate control fluid discharges now require toxicity testing;

· Facilities subject to CWIS requirements must submit a CWIS-specific quarterly report;

· Operators should implement spill prevention Best Management Practices (“BMPs”);

· Propping agents used in hydraulic fracturing are considered to be produced sand; and

· Fluids used for testing fluid handling equipment cannot be discharged.

The public comments period runs until May 7, 2012. EPA will be holding two public hearings on the proposed permit: April 11 in Houston, Texas and April 12 in Metairie, Louisiana.

Fifth Circuit holds purchase and sales agreement complies with Statute of Frauds

Robert Theriot — Mon, 20 Feb 2012 17:53:43 -0500

By Joanna Nelson:

Preston Exploration Co., L.P. v. GSF, L.L.C., Cause No. 10-20599, 2012 U.S. App. LEXIS 1873 (5th Cir. Tex. Feb. 1, 2012)

The Fifth Circuit recently vacated a judgment in the U.S. District Court for the Southern District of Texas, holding that the lower court had improperly conflated “two distinct principles – whether parties come to a meeting of the minds as to the subject matter of a contract with whether a writing’s legal description is sufficient to meet the statute of frauds.” Preston Exploration Co., L.P. v. GSF, L.L.C., Cause No. 10-20599, 2012 U.S. App. LEXIS 1873, *12 (5th Cir. Tex. Feb. 1, 2012). The parties’ dispute involved uncompleted exhibits to three Purchase and Sales Agreements (“PSAs”) entered into for the sale/purchase of certain oil and gas leases. Id. at *2. The exhibits, which were specifically referenced and incorporated into the PSAs, included a document “describing oil & gas leases to be conveyed and a reference to a different exhibit as the document setting out the form of the assignments to be delivered at closing. Id. at *4. The Seller, who had executed all three PSAs without complaint despite the PSAs providing for payment of a non-refundable deposit that amounted to $11 million, ultimately refused to close on the sale. Id. This suit followed.
After a three-day bench trial, the District Court determined that exhibits to the PSAs “did not contain enough information to be statute of frauds compliant” and that “the exhibits were not finalized at the time the PSAs were executing . . . [and thus] could not be incorporated into the PSAs.” Id. at *5. Without the exhibits, the District Court held that PSAs were not enforceable because they did not furnish “the means or data by which to identify the leases to be conveyed with reasonable certainty.” Id. at *5-6. The District Court also held that the Seller was not entitled to a return of the $11 million down payment, which holding was not challenged on appeal. Id. at *6.
The Fifth Circuit disagreed with the District Court on enforceability because “the PSAs do contain some indication of what is to be conveyed . . . [and] specifically provide that [Seller] is to convey all of Seller’s right, title and interest in and to all oil and gas leases as defined in Exhibit A.” Id. at *9-10. Internal quotes and brackets omitted. The Fifth Circuit noted that the “assignment documents could not be final at the signing of the PSAs because it was clearly intended by the parties that title work remained to be completed” and that the “PSAs specifically include provisions for curing title defects and for adjusting the contract price for any title defects which could not be cured.” Id. at *11. The “PSAs clearly reflect the intention of the parties and a recognition that there was still some title work to be done before a final determination could be made as to the leases which would ultimately be conveyed.” Id. The District Court thus “misconstrued this lack of finality as to the assignment documents as evidence that there was no meeting of the minds as to the subject of the contract.” Id. at *11-12. If, however, there had been no meeting of the minds, “there would be no contract whatsoever and the statute of frauds issue would be moot.” Id. at *12.
Because the intentions of the parties were clear by the terms of the PSAs and the “attached exhibits were all part of the same transaction and should be construed together,” the lack of finality of the exhibits did not prevent their consideration as part of the contracts to convey the property. Id. at *14-15. Though limiting enforcement of the PSAs to “those leases identified by recording information,” the Fifth Circuit held that the Buyer “may obtain specific performance” of the PSAs and remanded the case for “proceedings consistent with this opinion.” Id. at *15-16.

Texas case holds seller bound to terms of forged document

Robert Theriot — Wed, 08 Feb 2012 15:55:50 -0500

By James T. Kittrell

The Texas Court of Appeals for the Eleventh District of Eastland has recently held that a seller of an oil and gas property may be held to the terms of a forged purchase agreement if the seller properly signs an assignment that specifically incorporates the terms of the forged document. Raven Resources, LLC v. Legacy Reserves Operating, LP, No. 11-09-00348-CV, 2012 Tex. App. LEXIS 310, (Tex. App. Eastland, Jan. 12, 2012).

Raven Resources (“Raven”) was interested in selling certain oil and gas related-properties to Legacy Reserves Operating LP, (“Legacy”). Raven employed Michael Lee as its primary contact in negotiations with Legacy over the sale of the property involved in the case. After a negotiation period, Legacy sent a draft of a purchase agreement to Raven. The document was dated June 22, 2007 and it was not signed. The draft purchase agreement did not describe the property in question, but did state that the purchase price was $26.626,000. Id. at *2 David Stewart, Raven’s sole managing member, signed the draft purchase agreement and sent it to Legacy. While Stewart thought this concluded the negotiation of the agreement, Legacy continued to conduct its own due diligence, and ultimately came to the conclusion that certain revisions to the draft purchase agreement were required. Id. Among those revisions was a reduction in the purchase price to $20,300,000. These changes were reflected in another purchase agreement, this one dated July 11,2007, which was sent from Legacy to Lee. At this point, Lee failed to tell Stewart about the agreement and forged Stewart’s signature to the document and returned it to Legacy. Id. at *2-3 The record indicated that only David Stewart had the authority to bind Raven to any agreement.

The two sides closed the transaction by mail, in which Raven transferred the various interests and properties included in the July 11 agreement via thirty-five “assignments and bills of sale” dated August 3, 2007. These assignments specifically incorporated the terms of the July 11 agreement. Id. at *3 Several weeks later, Raven discovered the discrepancy between the price included in the June 22 draft agreement and the amount Legacy had actually paid Raven, which was the amount of the July 11 agreement. Raven then filed a lawsuit against Legacy, and Legacy filed counterclaims against Raven. Both sides moved for partial summary judgment, and the trial court granted Legacy’s motion, entered a take-nothing judgment against Raven, and severed Legacy’s remaining counterclaims to create a final ,appealable judgment. The court did not give a reason for its decision to grant the summary judgment motion. Id. at *5

On appeal, Raven claimed that the trial court erred in granting summary judgment because the July 11 agreement was forged, and thus void as a matter of law. Legacy responded by noting that the terms of the July 11 agreement were properly incorporated into the assignments, which were legal and enforceable. Id. at *6 Originally, the court of appeals issued an opinion overturning the grant of summary judgment for Legacy. However, the court granted Legacy’s motion for rehearing and withdrew its former opinion. Id. at *1 Ultimately, the court of appeals affirmed the trial court. It found that while the July 11 agreement itself was forged, and thus invalid, the incorporation was still effective. Id. at *8 The opinion noted that while a reference to a void agreement references nothing, the assignments in question did more than simply mention the July 11 agreement. Instead, by incorporating the terms of that agreement, the parties had made the actual language a part of the content of the assignment. Id. at *9 Thus, those terms, which include the sale price, are treated as equal to any other language in the assignment, regardless of whether or not the original July 11 agreement was void. Since the assignments themselves were valid, the court of appeals upheld the grant of summary judgment. Finally, the court rejected Raven’s argument that the assignments could be rescinded because of a mutual mistake as to price. Id. at *10-11 Noting that a party is presumed to know the contents of any document it signs, the court rejected Raven’s claims, holding that based on an objective standard, there was not enough evidence to indicate mutual mistake.

Update to the December 20, 2011 Liskow & Lewis E-Newsletter

Kelly Becker — Mon, 09 Jan 2012 10:34:16 -0500

By Megan Spencer

In our December 20, 2011 E-Newsletter, we reported on the status of: (1) EPA’s Cross-State Air Pollution Rule; and (2) the EPA Inspector General’s report, “EPA Must Improve Oversight of State Enforcement.” Some recent developments in those areas merit an update:

(1) On December 30, 2011, the United States Court of Appeals for the D.C. Circuit stayed EPA’s Cross-State Air Pollution Rule (CSAPR). The Court stayed CSAPR until it could resolve the petitions for review. In the meantime, EPA will continue to administer the Clean Air Interstate Rule. Click here for the complete ruling (PDF).

(2) Peggy Hatch, Secretary of the Louisiana Department of Environmental Quality (LDEQ), sent a response letter to the Inspector General of the EPA responding to the publication of EPA’s report, entitled “EPA Must Improve Oversight of State Enforcement.” The purpose of the response letter was to highlight some of the errors and omissions in the report criticizing Louisiana’s enforcement record. In her response, Secretary Hatch identified 14,454 enforcement actions that EPA did not take into account in evaluating the LDEQ’s enforcement record, and stated that Louisiana has seen tremendous improvement in ambient air and water quality in the recent past. Click here for the complete ruling (PDF).

EPA Proposes Modifications to Oil & Gas Air Pollution Standards

Robert Theriot — Mon, 03 Oct 2011 14:56:00 -0500

By Carlos J. Moreno:

On August 23, 2011, the Environmental Protection Agency (EPA) published in the Federal Register a proposed rule that significantly expands the applicable air emissions standards for the Oil and Natural Gas Sector. See 76 Fed. Reg. 52738 (Aug. 23, 2011), available at http://epa.gov/airquality/oilandgas/actions.html. Specifically, EPA is proposing changes to the New Source Performance Standards (NSPS) in 40 CFR part 60 and technology-based National Emissions Standards for Hazardous Air Pollutants (NESHAP) in 40 CFR part 63 that apply to oil and gas production, processing, transmission and storage facilities. According to EPA, the rules would result in a net savings for industry of $29 million because of the increased natural gas and condensate available for sale. The public comments period for the proposal ends on October 24, 2011.

New Source Performance Standards

Currently, two New Source Performance Standards apply to the oil and gas industrial category. Subpart KKK covers Volatile Organic Compound (VOC) emissions from leaking components in onshore natural gas processing plants, while Subpart LLL covers SO₂ emissions from onshore natural gas processing plants. EPA conducted reviews of both standards as required by the Clean Air Act, and is now proposing changes to each. Specifically, EPA is proposing to update the Leak Detection and Repair (LDAR) requirements in Subpart KKK, and modify Subpart LLL to require greater SO₂ control in facilities that process natural gas with high sulfur content.

In addition, the proposal would create a new NSPS Subpart OOOO to regulate VOC emissions from all oil and gas operations not already covered under Subpart KKK that commence construction, reconstruction, or modification after August 23, 2011. The new Subpart OOOO would include operational standards for completions of hydraulically-fractured gas wells. Non-exploratory and non-delineation wells would need to use reduced emission completion, commonly referred to as “green completion,” while exploratory and delineation wells would be allowed to use pit flaring. For purposes of the rule, a completion associated with refracturing performed at a well existing prior to August 23, 2011 is considered a modification, subjecting the well to the new standards. The rule also requires a 30-day advance notification for each completion or recompletion of a hydraulically fractured gas well. EPA is also proposing VOC emissions limits for gas-driven pneumatic devices, equipment standards for centrifugal compressors, operational standards for reciprocating compressors, and a 95% VOC emission reduction requirement for some condensate and crude oil storage tanks. Finally, the proposal exempts some “non-major” sources that would be subject to Subpart OOOO from having to obtain Title V permits.

NESHAP Technology-Based Standards

Under 40 CFR part 63, there are two technology-based NESHAP standards that apply to sources in the Oil and Gas sector. Subpart HH covers oil and natural gas production facilities that are major or area sources of Hazardous Air Pollutants (HAP). The rule includes standards for the following emission points: glycol dehydrator vents, storage vessels, and natural gas processing plant equipment leaks. On the other hand, Subpart HHH covers natural gas transmission and storage facilities that are major sources of HAP, and only includes standards for emissions from glycol dehydrator process vents. These NESHAP standards require major sources to use Maximum Achievable Control Technology (MACT). As required by the Clean Air Act, EPA conducted technology reviews and residual risk assessment reviews for both standards. Based on the findings from the reviews, EPA is proposing changes to both MACT standards for major sources.

The proposal establishes new emissions limits for small glycol dehydrators at major sources, which were previously exempted under Subpart HH and HHH. EPA is also proposing to eliminate the alternative compliance option under Subpart HH and HHH, which allows sources to reduce benzene emissions from large glycol dehydrators to less than 0.9 Mg/yr in lieu of achieving 95% emissions control. In addition, the rule proposes to eliminate the existing Startup, Shutdown and Malfunction (SSM) exemption that made emission standards inapplicable during periods of SSM. However, EPA proposes to add an affirmative defense to civil penalties and exceedances of emission limits caused by malfunctions. Finally, the proposal would modify Subpart HH to require all crude oil and condensate tanks at major sources to control their HAP emissions by at least 95%, and requires inclusion of all tank emissions when performing major source determinations.

EPA's Cross-State Air Pollution Rule Will Have A Dramatic Impact on Texas and Louisiana

Kelly Becker — Thu, 15 Sep 2011 10:46:18 -0500

By: Lesley Foxhall Pietras

On August 8, 2011, the Environmental Protection Agency (EPA) published a far-reaching Clean Air Act rule intended to address the interstate transport of sulfur dioxide (SO2) and nitrogen oxides (NOx) from upwind to downwind states. See 76 Fed. Reg. 48208 (Aug. 8, 2011). Specifically, the Cross-State Air Pollution Rule (CSAPR) requires 27 states, including Louisiana and Texas, to make dramatic cuts in power plant emissions. Emissions reductions will take effect quickly, starting January 1, 2012 for SO2 and annual NOx reductions, and May 1, 2012 for ozone season (May-September) NOx reductions. Texas power plants must meet the January 1, 2012 deadline for SO2 and annual NOx emissions, and the May 1 deadline for ozone season NOx emissions. Louisiana power plants must meet the May 1 deadline to reduce ozone season NOx emissions.

As promulgated, CSAPR will have dramatic impacts on Texas and Louisiana. According to the Texas Commission on Environmental Quality, CSAPR requires Texas power plants to lower SO2 emissions by 46 percent and NOx emissions by 7 percent compared with 2009 levels. See Kate Galbraith and Ari Auber, Controversial Pollution Rule Still on Track for Texas, The Tex. Tribune, Sept. 5, 2011. As for Louisiana, the Louisiana Public Service Commission’s consultant notes that CSAPR requires Louisiana power plants to reduce NOx emissions by 42 percent compared to 2010 levels. See David E. Dismukes, Acadian Consulting Group, Commissioner Briefing & Proposed Staff Recommendation: EPA’s Recently-Proposed Cross State Air Pollution Rule, Louisiana Public Service Commission Business & Executive Meeting (Sept. 7, 2011). Making these cuts by the highly compressed deadline could jeopardize the ability of the Texas and Louisiana electric grids to supply sufficient power to businesses and consumers. The reductions could even lead to rolling blackouts. For example, the Electric Reliability Council of Texas (ERCOT), the independent power system operator for the state, estimates that implementing CSAPR could result in a power generation capacity reduction of as much as 1,400 MW during the summer peak months. A reduction of that magnitude would have resulted in rotating outages during some days in August 2011. See ERCOT, Impacts of the Cross-State Air Pollution Rule on the ERCOT System at 5 (Sept. 1, 2011). Additionally, Luminant, the largest power generator in Texas, recently announced that it will need to close certain facilities to comply with CSAPR, which will cause the loss of approximately 500 jobs. See Luminant News Release, Luminant Announces Facility Closures, Job Reductions in Response to EPA Rule (Sept. 12, 2011). Moreover, in light of the substantial capital that power plants will need to spend on pollution control technology to comply with CSAPR, the rule will significantly increase the cost of electricity for all consumers, including businesses and individuals.

Numerous parties are considering challenges to CSAPR. Under the Clean Air Act, the deadline to file petitions for review of the rule is October 7, 2011. Petitions for reconsideration also must be filed by that same date.

Texas employers will welcome the decision in Marsh USA Inc. v. Cook

Andrew Wooley — Wed, 03 Aug 2011 16:10:08 -0500

By Andrew Wooley

The Supreme Court of Texas’ recent decision in Marsh USA Inc. v. Cook, 54 Tex. Sup. Ct. J. 1234, 2011 WL 2517019, 2011 Tex. LEXIS 465 (Tex. June 24, 2011), will make it easier for employers to enforce a Texas employee’s post-termination covenant not to compete. The decision was not unanimous, however, and it leaves some questions still to be answered.

One of the requirements for an enforceable covenant not to compete in Texas has long been that it be “ancillary to or part of an otherwise enforceable agreement at the time the agreement is made….” Justin Belt Co. v. Yost, 502 S.W.2d 681, 685 (Tex. 1973); Tex. Bus. & Com. Code Ann. § 15.50 (Vernon 2011) (“Covenants Not to Compete Act”). Commercial real estate leases and agreements to employ someone, to settle a dispute, and to sell a business have been recognized as “otherwise enforceable agreements” to which a covenant not to compete can be ancillary. In a decision 17 years ago though, the state supreme court added two requirements for enforcement of an employee’s non-compete that are not found in the Covenants Not to Compete Act itself:

(1) the consideration given by the employer in the otherwise enforceable agreement must give rise to the employer’s interest in restraining the employee from competing; and (2) the covenant [not to compete] must be designed to enforce the employee’s consideration or return promise in the otherwise enforceable agreement.

Light v. Centel Cellular Co. of Texas, 883 S.W.2d 643, 647 (Tex. 1994). Since Light was decided in 1994, the only combination of employer consideration and employee return promise that has been generally recognized to satisfy Light’s additional requirements for enforcement of an employee’s post-termination noncompete is an employer’s fulfilled promise to disclose confidential information to the employee and the employee’s return promise not to disclose or use such information other than for the employer’s benefit.

In Marsh, the court of appeals had affirmed the trial court’s summary judgment that an employee’s agreement not to compete in consideration of a grant of stock options was unenforceable as a matter of law for failure to satisfy the first part of the Light two-prong test. The supreme court reversed, holding that (i) a grant of stock options in consideration of the recipient’s covenant not to compete after termination of employment was reasonably related to the employer’s interest in protecting its goodwill, and (ii) the employee’s covenant not to compete was therefore not per se unenforceable for failure to satisfy the first part of the Light test. As is discussed below, Marsh did not undo entirely Light’s additional requirements for an enforceable employee non-compete. The court only held that the restrictive covenant in Marshwas not per se unenforceable (not that it was enforceable) and remanded the case to the trial court for further proceedings. Nevertheless, the holding in Marsh is favorable to employers, because it increases the likelihood that a Texas employee’s post-termination covenant not to compete will be enforced and sharply reduces the probability of a summary disposition in favor of the employee based on the nature of the consideration for the noncompete.

There are three opinions in Marsh. A five-justice majority overruled Light’s requirement that the consideration for a covenant not to compete must give rise to the employer's interest in restraining an employee from competing and held that (i) the consideration for an employee’s noncompete need only be reasonably related to an interest of the employer worthy of protection, (ii) good will is an interest worthy of protection, and (iii) the stock options that Marsh granted its employee in consideration for his agreement not to compete agreement were reasonably related to Marsh’s interest in protecting its goodwill. Marsh, 2011 WL 2517019, at *9,11-12 & 14, 2011 Tex. LEXIS 465, at *28-30, 32 & 41-42.

Justice Willett concurred only in the judgment to remand, stating his view that the record was underdeveloped and the trial court should “take first crack at assessing whether today's noncompetition covenant ‘contains limitations as to time, geographical area, and scope of activity...that are reasonable and do not impose a greater restraint than is necessary.’” Marsh, 2011 WL 2517019, at *14, 2011 Tex. LEXIS 465, at *42. And it is clear from his opinion that he shares the dissent’s view that pure financial incentives, such as bonuses or salary increases, will not justify a restraint of trade. Marsh, 2011 WL 2517019, at *16, 2011 Tex. LEXIS 465, at *56-57.

Justice Green wrote the opinion for the three dissenting justices and expressed their view that the judgments of the courts below should be affirmed because Light’s holding regarding the kind of consideration that is required for an enforceable covenant not to compete is a correct statement of the law. Marsh, 2011 WL 2517019, at *19, 2011 Tex. LEXIS 465, at *67-69.

The majority’s holding that the covenant not to compete at issue in Marsh is not per se unenforceable extended only to the first part of the Light test for enforceability. On remand, the trial court will have to decide whether the covenant satisfies the second part of Light’s test for enforceability, and it will also have to take into account the requirements in the Covenants Not to Compete Act and the considerations raised by Justice Willett in his concurring opinion in Marsh. Whatever the trial court decides, a further appeal is likely, unless the parties reach a settlement. It is also likely that the law concerning employee noncompetes in Texas will remain somewhat confused until a broader consensus emerges among the nine justices on the court.

In addition to the citations above to the Texas Supreme Court Journal, Westlaw^®, and LEXIS^®, copies of the majority, concurring, and dissenting opinions in Marsh are available on the web site for the Supreme Court of Texas:

http://www.supreme.courts.state.tx.us/historical/2011/jun/090558.pdf (majority)

http://www.supreme.courts.state.tx.us/historical/2011/jun/090558c.pdf (concurring)

http://www.supreme.courts.state.tx.us/historical/2011/jun/090558d.pdf (dissenting)

Parties May Agree to Expanded Judicial Review Under Texas Arbitration Act -- Nafta Traders, Inc. v. Quinn

Andrew Wooley — Fri, 27 May 2011 11:18:05 -0500

One of the prominent features of arbitration under the Federal Arbitration Act (“FAA”)[1] and the arbitration statutes of most states is a stringently limited right of appeal, which is integral to the goal of expeditious and economical dispute resolution. Some parties choose to arbitrate for reasons other than cost and efficiency, however, such as a desire for privacy, to avoid a forum perceived to be hostile, or to present their case to a tribunal with special expertise, and those parties often would also like to reserve the right to appeal the arbitrators’ award under a traditional judicial standard of review for errors of law and the sufficiency of the evidence to support the findings underpinning the award.

The United States Supreme Court foreclosed the possibility of traditional judicial review under the FAA in 2008, when it held that the limited grounds for vacatur or modification of an arbitration award specified in the FAA are exclusive and may not be supplemented or expanded by agreement. Hall Street Assocs., L.L.C. v. Mattel, Inc.[2] The Court made clear though that it was simply construing the text of the FAA and not ruling out other avenues of expanded review of arbitration awards.[3] “The FAA is not the only way into court for parties wanting review of arbitration awards: they may contemplate enforcement under state statutory or common law, for example, where judicial review of different scope is arguable.”[4]

The Supreme Court of Texas recently confirmed that review of arbitration awards under the Texas General Arbitration Act (“TAA”)[5] is indeed different from review under the FAA, notwithstanding the substantial similarities between the FAA and the TAA.[6] It held in Nafta Traders, Inc. v. Quinn that the TAA does not limit judicial review of an arbitration award to the grounds specifically stated in the TAA and that the FAA does not preempt expanded judicial review of an arbitration award under the TAA.[7] Consequently, parties whose agreement to arbitrate is within the scope of the TAA may preserve the right to traditional judicial review of the arbitration award by restricting their arbitrators’ powers to those typically possessed by a judge or by expressly agreeing that the arbitration award will be subject to a traditional judicial standard of review.[8] Of course, they will also need to make a verbatim record of the arbitration proceeding and should consider specifying in their arbitration provision that the TAA governs any proceeding thereunder and that any suit to confirm, modify, or vacate an award must be brought in a Texas state court.

--------

9 U.S.C. §§ 1-16.
552 U.S. 576, 578 & 584 (2008).
Id. at 586-88.
Id. at 590.
Tex. Civ. Prac. & Rem. Code Ann. §§ 171.001-098.
The statutory grounds for vacating an arbitration award are substantially the same under both the FAA and the TAA: (1) it was procured by corruption, fraud, or undue means, (2) there was evident partiality or corruption in the arbitrators, (3) the arbitrators were guilty of misconduct in refusing to postpone the hearing, upon sufficient cause shown, or in refusing to hear evidence pertinent and material to the controversy; or any other misbehavior by which the rights of any party have been prejudiced; or (4) the arbitrators exceeded their powers, or so imperfectly executed them that a mutual, final, and definite award upon the subject matter submitted was not made. 9 U.S.C. § 10, Tex. Civ. Prac. & Rem. Code Ann. § 171.088.
The statutory grounds for modifying an arbitration award are likewise similar under the FAA and the TAA: that the arbitrators made an award on a matter not submitted to them or there was an evident material miscalculation of figures or an evident material mistake in the description of any person, thing, or property referred to in the award. 9 U.S.C. § 11, Tex. Civ. Prac. & Rem. Code Ann. § 171.091.
Nafta Traders, Inc. v. Quinn, No. 08-0613, 2011 WL 1820875, at *7 & *10, 2011 Tex. LEXIS 361, at *33 & *45-46 (Tex. May 13, 2011).
The issue presented for decision in Nafta Traders was the availability of judicial review concerning whether an arbitrator had exceeded his powers, but the supreme court characterized its holding more broadly: “The TAA, as we have construed it, permits parties to agree to expanded review, or to a corresponding limit on the arbitrator’s authority, as in this case . . . .” Nafta Traders, 2011 WL 1820875, at *10, 2011 Tex. LEXIS 361, at *45.

Procedural History of Nafta Traders

Following the termination of her employment by Nafta Traders, Margaret Quinn filed suit in Texas state court for alleged gender discrimination in violation of the Texas Commission on Human Rights Act (the Texas analog to federal anti-discrimination statutes). Nafta Traders’ employee handbook included a provision requiring that any dispute arising out of the employment relationship or its termination be arbitrated in Dallas, Texas, but did not indicate whether federal or state law should apply to the arbitration. Nafta Traders moved to compel arbitration of Quinn’s claims under the FAA, which Quinn did not oppose, and the Texas district court signed an agreed order compelling arbitration.

The parties selected an arbitrator through the American Arbitration Association^® and, after hearing evidence, the arbitrator awarded Quinn back pay, mental anguish damages, “special damages,” and attorney’s fees and costs. The parties then went back to Texas district court. Quinn moved to confirm the arbitration award and Nafta Traders moved to vacate it “under the FAA, the TAA, the common law, and a provision in the arbitration section of the employee handbook stating that ‘[t]he arbitrator does not have authority (i) to render a decision which contains a reversible error of state or federal law, or (ii) to apply a cause of action or remedy not expressly provided for under existing state or federal law.’”

A verbatim record had been made of the proceedings before the arbitrator, and, based on the record, Nafta Traders asserted that (1) the arbitrator had mistakenly applied federal law even though Quinn had alleged only a violation of Texas law, (2) the evidence did not support an award of mental anguish damages, (3) the award of “special damages” was really a double recovery of lost wages, and (4) the attorney’s fee award was improper. Quinn responded that none of the grounds asserted by Nafta Traders was a basis for vacating an award under the FAA or the TAA. In rejoinder, Nafta Traders argued that by agreeing to the above described limits on the arbitrator’s authority, the parties had in effect agreed to expand the scope of judicial review beyond that otherwise provided by the FAA and the TAA. The district court confirmed the award with a brief order that gave no indication of the basis for the decision. Nafta Traders appealed.

While Nafta Traders’ appeal to the Dallas Court of Appeals was pending, the United States Supreme Court decided Hall Street Associates.[1] The state court of appeals applied the TAA rather than the FAA in Nafta Traders’ appeal, but concluded that “similarities between the two statutes weighed heavily in favor of construing the TAA as Hall Street had construed the FAA.” It held accordingly that “parties seeking judicial review of an arbitration award covered under the TAA cannot contractually agree to expand the scope of that review and are instead limited to judicial review based on the statutory grounds enumerated in the statute.”[2] Nafta Traders petitioned the Supreme Court of Texas for review of the court of appeals’ decision in August 2008.

The supreme court requested briefs on the merits, granted the petition for review, and in October 2009 heard the parties’ oral arguments in the case. The appeal languished from then until May 13, 2011, when the court issued a decision. Justice Hecht authored the opinion for a unanimous court and Chief Justice Jefferson wrote a three-paragraph concurring opinion not directed to the merits of the case. The court distinguished the arbitration provision in Nafta Traders from the provision in Hall Street Associates on the basis that the parties in Nafta Traders had not tried to expand the standard for review of their arbitrator’s award; they had instead denied the arbitrator the power to (i)render a decision containing a reversible error of state or federal law or (ii) apply a cause of action or remedy not expressly provided for under existing state or federal law. The court held that because one of the statutory grounds for vacating an arbitration award under the TAA is that it exceeds the arbitrator’s powers,[3] the award under the arbitration provision in Nafta Traders could therefore be reviewed for errors of law and to confirm that any relief granted was based on a cause of action or remedy expressly authorized under existing federal or state law.[4] The court also held that such review under the TAA is not preempted by the FAA.[5] Based on its holdings, the supreme court remanded the case to the court of appeals for it to consider the merits of Nafta Traders’ challenges to the arbitration award in favor of Quinn, so there may be yet another chapter in this saga.

The Criticism of Hall Street Associates

The Supreme Court of Texas could have limited its opinion in Nafta Traders to an explanation of its holding that judicial review to determine whether an arbitrator exceeded his powers is available under the TAA and is not preempted by the FAA. The court went further, however, and expressed its view that the United States Supreme Court’s textual analysis of the FAA in Hall Street Associates is flawed and that neither the FAA nor the TAA precludes review of an arbitration award under traditional judicial review standards if the parties agreed to such a standard.[6] That portion of the Texas court’s opinion may be persuasive, but it is not binding (even in a Texas court applying the FAA) because federalism prevents state courts from construing a federal statute contrary to a construction of it by the United States Supreme Court.[7]

In addition to the Westlaw^® and LexisNexis^® citations shown above, the majority and concurring opinions of the Supreme Court of Texas in Nafta Traders are also available on the court’s web site at the following hyperlinks: http://www.supreme.courts.state.tx.us/historical/2011/may/080613.pdf and http://www.supreme.courts.state.tx.us/historical/2011/may/080613c.pdf.

The decision in Hall Street Associates was released after the parties had submitted their briefs and presented oral argument in Nafta Traders, but before the Texas court of appeals had issued its opinion. Nafta Traders, 2011 WL 1820875, at *2, 2011 Tex. LEXIS 361, at *7.
Nafta Traders, Inc. v. Quinn, 257 S.W.3d 795, 798-99 (Tex. App. – Dallas), rev’d, No. 08-0613, 2011 WL 1820875, 2011 Tex. LEXIS 361 (Tex. May 13, 2011).
The FAA contains a substantially similar provision. 9 U.S.C. § 10(a)(4), Tex. Civ. Prac. & Rem. Code Ann. § 171.088(a)(3)(A).
Nafta Traders, 2011 WL 1820875, at *7, 2011 Tex. LEXIS 361, at *33.
Nafta Traders, 2011 WL 1820875, at *10, 2011 Tex. LEXIS 361, at *45-46.
Nafta Traders, 2011 WL 1820875, at *4-*6, 2011 Tex. LEXIS 361, at *18-*27.
Nafta Traders, 2011 WL 1820875, at *3, 2011 Tex. LEXIS 361, at *17.

EPA and Army Corps of Engineers Issue Draft Guidance on Waters Protected by Clean Water Act

Kelly Becker — Tue, 17 May 2011 12:09:43 -0500

By Lesley Foxhall Pietras

On April 27, 2011, the Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers (the Corps) released new proposed guidance on how the agencies will identify waters protected by the Clean Water Act (CWA) in light of Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers, 531 U.S. 159 (2001) (SWANCC) and Rapanos v. United States, 547 U.S. 715 (2006). Although EPA and the Corps have previously issued guidance interpreting SWANCC and Rapanos (EPA’s earlier guidance on Rapanos is discussed at www.theenergylawblog.com/2007/07/articles/environmental/epa-and-army-corps-of-engineers-publish-joint-guidance/ ), the agencies believe “previous guidance did not make full use of the authority provided by the CWA to include waters within the scope of the Act, as interpreted by the Court.” Guidance at 2. The agencies therefore expect that, under the new proposed guidance, “the number of waters identified by the [CWA] will increase compared to current practice.” 76 Fed. Reg. 24479, 24479 (May 2, 2011). Accordingly, the proposed guidance appears to substantially expand the agencies’ jurisdiction when compared to the prior guidance. Public comment on the proposed guidance must be received on or before July 1, 2011. Id.

In SWANCC, the Supreme Court addressed the question of CWA jurisdiction over isolated, non-navigable, intrastate ponds, and concluded that CWA jurisdiction could not be based solely on the presence of migratory birds. In Rapanos, the Court addressed CWA protections for wetlands adjacent to non-navigable tributaries, but issued five opinions with no single opinion commanding a majority. The proposed guidance emphasizes that the plurality opinion concluded that “waters of the United States” extends beyond traditional navigable waters to include “relatively permanent, standing or flowing bodies of water.” Rapanos, 547 U.S. at 731-32; see also id. at 739. The proposed guidance also highlights the plurality opinion’s conclusion that only wetlands with a “continuous surface connection” to other jurisdictional waters are considered “adjacent” and protected by the CWA. Id. at 742. In contrast, Justice Kennedy’s concurring opinion, the proposed guidance notes, concluded that “waters of the United States” includes wetlands with a “significant nexus” to traditional navigable waters. Rapanos, 547 U.S. at 780. The agencies continue to believe that they can assert jurisdiction over waters that satisfy either the plurality standard or Justice Kennedy’s standard, because a majority of justices would support jurisdiction under either standard. Guidance at 2.

Under the proposed guidance, the following waters are protected by the CWA: traditional navigable waters (including water bodies that have been found to be navigable-in-fact by a federal court, and waters which are currently used, historically have been used, or are susceptible to being used for commercial navigation); interstate waters (even if such waters are not traditional navigable waters); and wetlands adjacent to either traditional navigable waters or non-wetland interstate waters.

Moreover, the proposed guidance determines which waters are covered by the CWA pursuant to the standard set out in the Rapanos plurality opinion. In this vein, non-navigable tributaries are subject to CWA jurisdiction, if the tributary is connected to a downstream traditional navigable water, and flow in the tributary is at least seasonal. Guidance at 13. Wetlands that directly abut relatively permanent waters are also covered by the CWA. Id. at 15.

Additionally, the following types of waters are covered by the CWA if a fact-specific analysis determines they have a “significant nexus” to traditional navigable waters or interstate waters:
• tributaries to traditional navigable waters or to interstate waters;
• wetlands adjacent to jurisdictional tributaries to traditional navigable waters or interstate waters; and
• waters that fall under the “other waters” category of the regulations, including intrastate lakes, rivers, and mudflats. The proposed guidance divides these waters into two categories (those that are physically proximate to other jurisdictional waters and those that are not) and discusses how each category should be evaluated.
According to the proposed guidance, waters have the requisite “significant nexus” “if they, either alone or in combination with similarly situated waters in the region, significantly affect the chemical, physical, or biological integrity of traditional navigable waters or interstate waters.” Guidance at 7.

Under the proposed guidance, waters that are not covered by the CWA include artificially irrigated areas which would revert to upland if the irrigation ceased; artificial lakes or ponds which are used for stock watering, irrigation, settling basins, or rice growing; artificial reflecting pools or swimming pools excavated in uplands; water-filled depressions created in dry land incidental to construction activity and pits excavated in dry land for the purpose of obtaining fill; groundwater drained through subsurface drainage systems; and erosional features, swales and ditches that are not tributaries or wetlands. Guidance at 21.

The proposed guidance will apply to all CWA programs, including section 303 water quality standards, section 311 oil spill prevention and response, section 401 water quality certification, section 402 National Pollutant Discharge Elimination System permits, and section 404 permits for discharges of dredged or fill material.

After the agencies receive comment on the proposed guidance, they plan to finalize the guidance and then propose revisions to the existing regulations to further clarify which waters are covered by the CWA.

For more information on the proposed guidance, see water.epa.gov/lawsregs/guidance/wetlands/CWAwaters.cfm

Latest Chapter in the "EPA v. Texas" GHG Permitting Saga: EPA Publishes Final Rule Partially Disapproving Texas SIP and Promulgates FIP for GHG Emissions

Kelly Becker — Thu, 05 May 2011 12:18:30 -0500

by: Carlos J. Moreno

On May 3, 2011, the U.S. Environmental Protection Agency (EPA) promulgated a final rule partially disapproving the Texas State Implementation Plan (SIP) and issuing a Federal Implementation Plan (FIP) for Texas. The action prolongs EPA's authority to issue Prevention of Significant Deterioration (PSD) permits for Greenhouse Gas Emissions (GHG) emissions in Texas. Under the Clean Air Act (CAA), states have authority to implement the federal National Ambient Air Quality Standards (NAAQS) if the state submits, and EPA approves, a State Implementation plan (SIP). The SIP must include implementation of preconstruction PSD permitting requirements for NAAQS pollutants and, according to EPA, non-NAAQS pollutants. The CAA authorizes EPA to call for revisions to a SIP ("SIP Call") if the agency later finds that a SIP is inadequate. Following a series of EPA regulatory actions, GHG emissions became subject to PSD requirements as a non-NAAQS pollutant beginning on January 2, 2011. Since then, the EPA Tailoring Rule has required sources that trigger PSD for pollutants other than GHGs to also permit GHG emissions if they are 75,000 tpy or more.

On December 1, 2010, EPA issued a SIP Call for 13 states, including Texas, whose SIPs needed revisions in order to regulate GHG emissions under their PSD permitting program. Contrary to the other states, Texas refused to set a timeline for a SIP revision, effectively telling EPA that it would not revise its SIP to cover GHG emissions. To ensure that sources could obtain GHG permits, EPA issued an interim final rule and a "mirror" rule proposal in December 2010 that partially disapproved the Texas SIP and promulgated a FIP authorizing EPA to issue GHG permits under PSD. EPA stated that it erred in approving the Texas SIP 18 years earlier because the SIP does not contain assurances of adequate legal authority for the application of PSD to newly regulated non-NAAQS pollutants. The interim final rule was set to expire on April 30, 2011. Texas has filed several judicial challenges to EPA's GHG regulations in the DC Circuit, as well as a challenge in the 5th Circuit to EPA's SIP Call finding the Texas SIP inadequate. After issuance of the final interim rule, Texas requested a stay of the rule in the DC Circuit. The DC circuit granted a 30-day stay that was subsequently lifted on January 12, 2011. Since then, EPA has effectively been the permitting authority for GHG emissions in Texas. On May 3, 2011, EPA finalized the December 2010 rule proposal partially disapproving the Texas State Implementation Plan (SIP) and issuing a Federal Implementation Plan (FIP) for Texas. The action was made effective on May 1st to ensure no gap in permitting coverage.

One of the arguments that Texas has pursued is that EPA issued the December 2010 error correction FIP without proper notice and comment. By essentially reissuing the FIP under this final rule after notice and comment, EPA has addressed this argument. Under the FIP, EPA continues to be the PSD permitting authority for GHG emissions in Texas, while Texas continues to be the permitting authority for non-GHG emissions. Therefore, a project that is currently subject to PSD may require two PSD permits: a Texas Commission on Environmental Quality (TCEQ) PSD permit for pollutants other than GHG, and a EPA PSD permit for GHG emissions if the project has 75,000 tpy or more of GHG emissions. Currently, GHG PSD permits are only required if New Source Review is triggered by a non-GHG pollutant. But, starting on July 1, 2011, EPA's GHG Tailoring Rule will also require PSD permits for sources that trigger PSD solely because of their GHG emissions (100,000 tpy or more of GHG's for new projects; 75,000 tpy or more of GHG's for modifications). For these projects, EPA will be the PSD permitting authority for all pollutants. The final error correction FIP will remain in place until Texas submits, and EPA approves, a SIP revision including GHG permitting. Under EPA's standing SIP Call, Texas still has until December 1, 2011 to submit a SIP revision that includes application of PSD program requirements to GHG emissions. EPA has already stated that if Texas does not submit a revision by this date, EPA is prepared to promulgate a new FIP associated with the SIP Call, which would replace the May 3rd FIP, but be "fully consistent" with it. In the meantime, litigation regarding EPA's authority to regulate GHGs, error correction FIP for Texas, and the GHG SIP Call is continuing in the DC Circuit and 5th Circuit.

Supreme Court of Texas Reverses Appeals Court in Oil and Gas Waste Injection Well Permitting Case

Robert Theriot — Wed, 27 Apr 2011 15:45:21 -0500

By: Carlos J. Moreno

In Railroad Commission of Texas v. Texas Citizens for a Safe Future and Clean Water, No. 08-0497, 2011 WL 836827 (Tex. Mar. 11, 2011), the Supreme Court of Texas reversed the Austin Court of Appeal’s finding that the Railroad Commission (the “Commission”) has to consider broad public safety concerns in the permitting of proposed oil and gas waste injection wells.

The case involved a proposed oil and gas waste injection well in the Barnett Shale Area. Before the Commission can grant an injection well permit, the Texas Injection Well Act requires it to find that the use or installation of the injection well is in the public interest. At the administrative hearing, a group of residents living near the well (“Texas Citizens”) expressed concern about the large trucks hauling fracing waste water and whether the trucks would damage nearby roads. The Commission concluded that it had no jurisdiction to regulate traffic, and granted the injection well permit after finding that doing so would be in the public interest. Subsequently, Texas Citizens challenged the Commission’s findings in state court, arguing in part that the Commission should have considered traffic safety concerns in its public interest inquiry. The trial court found in favor of the Commission, but the appeals court reversed. The court of appeals found that the Commission had abused its discretion in interpreting the public interest inquiry too narrowly. The Commission and the proposed injection well operator appealed to the Supreme Court of Texas.

The supreme court framed the issue as a statutory construction inquiry. The court evaluated whether the commission’s interpretation of the public interest inquiry, as including only matters related to oil and gas production, should be given judicial deference. Looking at Texas case law, the court found that the Commission’s interpretation of the “public interest” language should be given “serious consideration” if the construction is reasonable and does not contradict the plain language of the statute.

The court pointed to several factors in concluding that the Commission’s interpretation should be upheld. First, the court noted that the statute specifically instructed the Texas Commission on Environmental Quality (TCEQ) to consider roadway concerns when permitting other types of injection wells, but did not include similar language for oil and gas waste injection wells regulated by the Commission. Second, the court noted that while the “public interest” term is ambiguous and can support more than one interpretation, the interpretation offered by Texas Citizens would mean that the Commission “would have to consider and weigh a limitless number of factors beyond the Commission’s institutional competence” in oil and gas operations. Finally, the court pointed to how long the Commission’s interpretation had been in place, noting that an agency’s long-standing interpretation of a statute is particularly worthy of deference because if the legislature disagreed with the interpretation, it could have amended the statute appropriately.

Three justices concurred in the judgment, but would have found that the statute itself unambiguously precludes consideration of traffic safety concerns.

The court’s holding means that as part of the public interest inquiry required for issuance of an injection well permit, the Commission can continue to only consider matters related to the production of oil and gas.

The full text of the opinion is available at the following link: http://www.supreme.courts.state.tx.us/historical/2011/mar/080497.pdf

Extra! Extra! Read All About It!

Amy Harang — Thu, 03 Feb 2011 17:58:51 -0500

Thanks to you, our readership, Liskow’s Energy Law Blog has been nominated for the LexisNexis Top 50 Environmental Law & Climate Change Blogs! If you like what you see on our blog, please let the ELCCC (LexisNexis Environmental Law & Climate Change Community) know by commenting “here” (go ahead and do it now, nomination support ends February 14). We appreciate your online interest in our industry blog and hope that you continue to follow it and invite a few colleagues to do the same!

EPA Denied Extension to Promulgate Boiler MACT Rule

Kelly Becker — Thu, 03 Feb 2011 16:26:32 -0500

By: Megan J. Spencer

EPA first issued its Boiler MACT Rule on September 13, 2004. However, these standards were vacated by the United States Court of Appeals for the District of Columbia Circuit after the Court found EPA’s definition of “commercial or industrial waste” conflicted with the language of the Clean Air Act in NRDC v. EPA, 489 F. 3d 1250 (D.C. Cir. 2007). The deadline for EPA to issue its Boiler MACT Rule was judicially imposed on EPA in Sierra Club v. Johnson, 444 F. Supp. 2d 46 (D.D.C. 2006), requiring EPA to fulfill its statutory duties of promulgating emissions standards by June 15, 2009. However, the United States District Court for the District of Columbia granted several unopposed motions to extend this deadline for the Boiler MACT Rule, resulting in an eventual deadline of January 21, 2011. EPA requested another extension of this deadline through April 13, 2012, but this request was opposed by the plaintiff, the Sierra Club.

EPA argued that it needed a fifteen-month, or alternatively a five-month, further extension of the January 21, 2011, deadline because: (1) in light of the comments received after the proposed rules, EPA must re-propose the rules to ensure that the final rules are a logical outgrowth of the proposed rules; and (2) in the alternative, EPA needs a five-month extension to fulfill its statutory duty of responding to all significant comments. However, the court agreed with the plaintiff that EPA had failed to satisfy the impossibility standard for the setting of emissions standards within the previous deadline set by the court. Thus, the court denied EPA’s request for an extension until April 13, 2012 so that EPA could re-propose the rules before issuing the final rules. The Court also denied the five-month extension requested by EPA to respond to all comments and instead gave EPA one-month to promulgate its Boiler MACT Rule finding that EPA had not provided sufficient evidence on why it needed five months to respond to comments it had already began reviewing.

Although EPA argued to the District Court that it wanted an extension to re-propose the rules including another round of public comment, EPA submitted the final rules to the White House Office of Management and Budget for review on January 21, 2011, the same day the court denied the request for an extension. www.nytimes.com/gwire/2011/01/21/21greenwire-with-extension-denied-epa-sends-boiler-rules-t-75622.html

It is likely that EPA will use section 307(d)(7)(B) of the CAA for administrative reconsideration of the rules without postponing the effectiveness of the rules. 42 U.S.C. § 7607(d)(7)(B). Additionally, because of the far reaching nature of the Boiler MACT Rule, it is also possible that the rules could face judicial challenges.

Congress has also indicated that it may get involved in EPA’s deadline to promulgate its Boiler MACT Rule. At a January 26 hearing of the House Energy & Commerce Committee, Rep. Fred Upton (R-MI) offered to advance legislation that would provide EPA with more time to issue its final Boiler MACT Rule.

See full opinion at: Sierra Club v. Jackson, No. 01-1537, 2011 U.S. Dist. LEXIS 5316 (D.D.C. Jan. 20, 2011).

Fifth Circuit Reverses District Court Ruling Protecting Mineral Owner's Rights of Ingress and Egress Over National Park Service Land

Kelly Becker — Tue, 18 Jan 2011 16:28:12 -0500

by: Megan J. Spencer

In its decision, filed January 7, 2011, the United States Court of Appeals for the Fifth Circuit reversed, vacated and remanded the opinion of a Texas district court that had found that the National Park Service’s Oil and Gas Management Plan was invalid under the Administrative Procedure Act (“APA”) because it denied Plaintiffs rights of ingress and egress established in the state and federal law creating the park. Dunn-McCampbell Royalty Interest Inc. v. Nat’l Park Serv., 09-40187 (5th Cir. 2011). The case involved land in the Padre Island National Park, created in 1963. The conflict arose between the National Park Service (“Service”), owner of surface estates, and Plaintiffs who were owners of mineral estates. The Service appealed the decision of the district court.

The Service made two arguments on appeal. First, it advanced a plain language argument based on the text of the Texas law creating that park. The Texas law made an exception for the use of the surface of the land for the reasonable development of oil, gas, and other minerals – including the right of ingress and egress. However, this right was only granted to the “grantors or successors in title” of surface land to the United States. Plaintiffs argued that this language in the statute was ambiguous, and thus even though they were not grantors or successors in title, the right of ingress and egress applied to them. The Service argued that the language of the statute was clear, and the right of ingress and egress was only granted to the mineral owners who conveyed surface land to the Service. The Court agreed with the Service’s plain language interpretation, finding that the right of ingress and egress did not apply to the Plaintiffs here.

Second, the Service argued that a second exception in the law creating the park did not apply to the Plaintiffs because the Plaintiffs’ mineral estates were within the Seashore’s boundaries. The act creating the park excluded from ingress and egress restrictions those minerals that were removed from outside the boundaries of the seashore. Thus, Plaintiffs argued that because they privately owned the mineral estates, these mineral estates were technically not within the park boundaries. The Fifth Circuit found that despite the private ownership of the mineral estates below the surface of the land, Plaintiffs’ mineral estates were within the park’s boundaries.

Although the case deals with laws specific to the Padre Island National Park and Seashore, it has broader implications for mineral estate owners who have mineral estates located partially or fully within national park boundaries. The Fifth Circuit joined the position of three other circuit courts finding that “land that is not owned by the Service can still exist within the boundaries of a national park.”

The full text of the opinion is available at the following link: www.ca5.uscourts.gov/opinions/pub/09/09-40187-CV0.wpd.pdf

Fifth Circuit Reverses Summary Judgment in Oil Pollution Act Case

Kelly Becker — Mon, 10 Jan 2011 17:50:17 -0500

In Gabarick v. Laurin Maritime (America), Inc., 2010 WL 5421015 (5th Cir. Dec. 30, 2010), the Fifth Circuit reversed the district court’s finding of summary judgment on liability under the Oil Pollution Act of 1990 (“OPA”). In doing so, the Court determined that at the summary judgment stage of a complex OPA case involving a number of different parties, it was improper for the court to rely solely on allegations made in the pleadings in order to find that one particular party was not liable under OPA.

The facts of the case are as follows: In July 2008, an ocean-going tanker traveling on the Mississippi River collided with a barge which contained oil. As a result, a large amount of oil spilled from the barge into the river near New Orleans. Immediately after the spill, the owner of the barge denied liability; however, as the owner of the discharging vessel, it agreed to coordinate the removal and cleanup efforts with the Coast Guard. A number of lawsuits followed involving the owner of the barge (“Barge Owner”), the owners of the tanker (“Tanker Owner”), DRD Towing, LLC (“DRD”), which was the company that supplied the crew for the tug that was towing the barge, as well as other parties. These lawsuits were then consolidated into the first-filed action. The Tanker Owner moved for summary judgment arguing that it was not liable under OPA.

OPA provides generally that each “responsible party” for a vessel or facility from which oil is discharged is liable for the damages caused by such an incident. Further, the responsible party for a vessel is any person owning or operating the vessel. OPA, however, also provides a responsible party with a complete defense to liability in the following circumstance:

A responsible party is not liable…if the responsible party establishes, by preponderance of the evidence, that the discharge or substantial threat of discharge of oil and the resulting damage or removal costs were caused solely by an act or omission of a third party, other than…a third party whose act or omission occurs in connection with any contractual relationship with the responsible party….

33 U.S.C. § 2703(a)(3). The Tanker Owner argued that because the Barge Owner’s pleadings admitted that the Barge Owner was in a contractual relationship with DRD, and because the pleadings also admitted that DRD had some fault in causing the collision, as a matter of law, the Barge Owner could not shift liability to the Tanker Owner under OPA. Accordingly, summary judgment was proper in favor of the Tanker Owner. The district court granted the Tanker Owner’s motion finding that at least some fault was attributable to the Barge Owner and/or DRD.

On appeal, the Fifth Circuit found that summary judgment was premature and, therefore, reversed the lower court’s ruling. First, the Court found that the Barge Owner had taken inconsistent positions in its pleadings in the various district court actions. Specifically, although the Barge Owner admitted in its pleadings that it had a contractual relationship with DRD, the Barge Owner had also filed a separate declaratory judgment action to have any contracts with DRD declared void ab initio. Citing Fifth Circuit precedent, the Court reasoned that one of two inconsistent pleas cannot be used as evidence in the trial of another. Accordingly, the district court erred in treating the allegations in any one of the Barge Owner’s pleadings as an admission sufficient to settle an issue of fact.

Given the complex nature of the case and the unresolved relationships between the parties, the Court also found that it was premature to treat any party’s mere allegations as sufficient evidence to conclude that a contractual partner of the Barge Owner had some fault in the collision such that summary judgment in favor of the Tanker Owner was warranted. Further, there had not been sufficient factual development to conclusively assign fault to any of the parties. Thus, the Court reversed the granting of summary judgment.

The Gabarick opinion suggests that in certain OPA cases involving complex factual scenarios and numerous different parties, it may be improper for a court to rely solely on allegations made in the pleadings in order to grant summary judgment absolving a party of OPA liability.

EPA Releases Guidance On Greenhouse Gas Permitting Leaving Many Questions Unanswered

Kelly Becker — Thu, 02 Dec 2010 13:48:55 -0500

by Megan Spencer

    On November 10, 2010, EPA released guidance for states and permitting authorities to begin including greenhouse gas (“GHG”) emissions in PSD and Title V permitting processes entitled PSD and Title V Permitting Guidance For Greenhouse Gases. (“Guidance”). This Guidance is scheduled to take effect January 2, 2011. EPA gave the public a short window to submit comments on the Guidance, with the comment period ending December 1, 2010. However, this Guidance left much to be interpreted by permitting authorities, leaving industries subject to the new Guidance wondering how it will be applied to them.
    The Guidance applies EPA’s “top down” analysis of best available control technology (“BACT”) to GHG emissions. BACT in Clean Air Act permitting actions for new and modified sources. This BACT analysis involves the following steps: 1) identify all available control technologies; 2) eliminate technically infeasible options; 3) rank remaining options by emissions control effectiveness; 4) evaluate economic, energy, and other environmental impacts; and, 5) select best option as BACT for the source. The Guidance provides a list of available control technologies under step 1 including inherently lower-emitting processes/practices/designs, add-on controls, and combinations of the two. Under step 2, a technology is “technically feasible” if it has been demonstrated in practice or is available and applicable to the source type under review. When ranking options under step 3, ranking should be based on total CO2e. Those available options are then evaluated under step 4. Under step 5, the goal of the BACT selection is to have the highest level of control that the applicant could not adequately justify its elimination based on the factors in step 4.
     The Guidance emphasizes energy efficiency as a means to achieve lower GHG emissions. (Guidance, p. 30). However, the Guidance does not provide definitive answers for how energy efficiency is to be determined. This uncertainty leaves those industries subject to the new guidance wondering whether energy efficiency will be applied to the entire facility, on an individual equipment basis, or across a production unit. With the discretion of how this energy efficiency goal will be interpreted left to the permitting authority, uniformity among states and permitting programs will be lacking. This uncertainty will likely lead to increased costs and delays in permit approvals.
One of the more controversial issues raised by the guidance is whether GHG BACT could force an applicant to redesign its source. Well-settled BACT procedures state that “EPA has recognized that a Step 1 list of options need not necessarily include inherently lower polluting processes that would fundamentally redefine the nature of the source proposed by the permit applicant. BACT should generally not be applied to regulate the applicant’s purpose or objective for the proposed facility.” However, the Guidance then continues with a statement that “permitting agencies must take a ‘hard look’ at the applicant’s proposed design in order to discern which design elements are inherent for the applicant’s purpose and which design elements may be changed to achieve pollutant emissions reductions without disrupting the applicant’s basic business purpose.” At best, this language is likely to lead to widely varying results between different permitting authorities.
     Another unanswered question involves the inclusion of carbon capture and sequestration in the Guidance. The Guidance suggests that carbon capture and sequestration is an available control technology that should be considered under step one of the BACT analysis. Notably, the Guidance recognizes in a footnote that carbon capture and sequestration is not yet ready for large-scale implementation. (Guidance, p. 33, fn. 82). This acknowledgment suggests that facilities should not be required to carry the use of carbon capture and sequestration past steps 1 or 2 when it is not “available” or “feasible” for large-scale implementation.

The full text of the Guidance is available at the following link:www.regulations.gov/search/Regs/home.html#documentDetail

EPA Encourages Consideration of Ocean Acidification in Clean Water Act Impairment Listings

Robert Theriot — Tue, 23 Nov 2010 17:35:31 -0500

By Carlos J. Moreno:

On November 15, 2010, the U.S. Environmental Protection Agency (EPA) issued a memorandum providing States with guidance on how to address ocean acidification in their Clean Water Act 303(d) impairment listings.

Section 303(d) of the Clean Water Act requires States to list water bodies that will not meet Water Quality Standards, even after technology-based permit requirements are implemented. States must then identify every contributing source, including contributions from air emissions, and make plans to bring the impaired water body into compliance. This process results in the calculation of a Total Maximum Daily Load (TMDL). There is precedent for TMDLs addressing air emission sources, specifically in relation to atmospheric deposition of mercury.

The EPA Memo is part of an EPA settlement with the Center for Biological Diversity (CBD), which sued EPA over 303(d) listing of coastal waters for ocean acidification. The CBD had argued that ocean acidification (the decrease in ocean pH caused by increasing CO₂ concentration in the atmosphere) required EPA to modify its Recommended Marine pH Criteria and consider ocean acidification in 303(d) list approvals. The Memo encourages States to list coastal waters for ocean acidification, based on existing Marine pH Water Quality Standards, where there is enough data to support it. For example, Puerto Rico’s 2010 303(d) list already includes five coastal water segments impaired by marine pH. At the same time, the agency recognizes that many States do not yet have enough monitoring data to make such a listing. EPA pledges to issue TMDL-specific guidance related to ocean acidification once there is more information on air deposition of carbon in coastal waters.

The EPA memo only addresses ocean acidification from a 303(d) list perspective and does not modify EPA’s Recommended Marine pH Criteria. It is unclear how these developments may affect, if at all, future EPA Ocean Discharge Criteria evaluations under Section 403 of the Clean Water Act.

For more information on the Memorandum, see:

http://water.epa.gov/lawsregs/lawsguidance/cwa/tmdl/oa_memo_nov2010.cfm

EPA Releases Final Rule Requiring Oil and Gas Sources to Report Emissions of Greenhouse Gases

Kelly Becker — Thu, 18 Nov 2010 13:05:42 -0500

By Carlos J. Moreno

On November 8, 2010, the U.S. Environmental Protection Agency (EPA) released its final Subpart W rule to cover petroleum and natural gas facilities under the agency’s Greenhouse Gas (GHG) Reporting Program. The original Subpart W rule for petroleum and natural gas facilities was proposed in March 2010. The industry segments covered by the rule are: offshore petroleum and natural gas production; onshore petroleum and natural gas production; onshore natural gas processing; onshore natural gas transmission compression; underground natural gas storage; liquefied natural gas (LNG) storage, import, and export; and natural gas distribution. The rule requires facilities emitting 25,000 metric tons or more of CO2 equivalents per year to report GHG emissions to EPA annually. Under the final rule, facilities are required to begin collecting emissions data on January 1, 2011, and the first annual report is due by March 31, 2012. Data submitted to EPA must be self-certified by facility reporters and is subject to EPA verification.

The final rule excludes gathering lines and boosting stations from the onshore petroleum and natural gas production source category. The rule also gives onshore petroleum and natural gas production facilities the option to use Best Available Monitoring Methods (BAMM) for specific sources during part of the 2011 calendar year. EPA may consider individual petitions to extend the use of BAMM if there are extreme or unusual circumstances.

One of the more controversial requirements in the proposed rule, the “basin-level” definition of an onshore production facility, remains largely unchanged in the final rule. For onshore production sources, the rule defines “facility” as “all petroleum or natural gas equipment on a well pad or associated with a well pad and CO2 E[nhanced] O[il] R[ecovery] operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin.” By defining the term “facility” this way, individual production wells that are under the reporting threshold may be pulled in if the owner or operator has additional wells in the same basin. In that case, the emissions from the individual wells would be aggregated and treated as one “facility” for reporting purposes. Although this definition departs from how “facility” is defined in other regulatory programs, EPA asserts that the basin-level definition is necessary to ensure appropriate emissions coverage and meet the intent of the GHG Reporting Program. EPA did include language that explicitly limits the basin-level definition to the GHG Reporting Rule.

Offshore petroleum and natural gas production facilities must include emissions from equipment leaks, venting, and flaring. Emissions from portable equipment and drilling operations (unless drilling is conducted from a production platform) are excluded for this industry segment. Reporting for offshore facilities is still based on the BOEM Gulfwide Emissions Inventory process.

For more information on the final rule, see: www.epa.gov/climatechange/emissions/subpart/w.html