I am indebted to Mary K. Sahs (Carls, McDonald & Dalrymple, LLP), an Austin attorney who specializes in water law and who has written an excellent paper, Frac Water - Regulation of Quantity and Quality, and Reporting by Texas Groundater Conservation Districts, for the State Bar conference "The Changing Face of Water Rights" held on February 23 of this year in San Antonio, for a thorough explanation of this subject. I have borrowed liberally from her work.

Groundwater conservation districts are governed by the Texas Water Code, Chapter 36, and by any special provision in the law that authorized creation of each district. Section 36.117 (b) (2) of the Water Code provides that the following are exempt from regulation:  "drilling a water well used solely to supply water for a rig that is actively engaged in drilling or exploration operations for an oil or gas well ... located on the same lease or field associated with the drilling rig." This has been referred to as the exemption for "rig supply wells." Rig supply wells are still subject to any water well spacing rules imposed by the water district, and the district may require the well to be registered and may require it to be properly equipped and completed.

The Texas Railroad Commission interprets the rig supply well exemption in the Water Code to apply to hydraulic fracturing operations. ("The RRC interprets the phrase "a rig that is actively engaged in drilling or exploration operations for an oil or gas well permitted by the commission" to mean a drilling rig or a workover rig and interprets "exploration operations" to include well completion and workover, including hydraulic fracturing operations.") But Mary Sahs quotes Ben Sebree, representing the Texas Oil and Gas Association, testifying at a House Natural Resources Committee hearing last year, as saying, with regard to water wells used in hydraulic fracturing: " ... our water wells are not exempt from the rules of the districts. We don't have to get a permit for them, and I know that sounds kind of odd, but they do have to comply with all the rules of the district, whether it's spacing, production, whatever, our ... water wells have to comply with those rules." Clearly, there is some ambiguity in the statutory language.

So how do groundwater districts regulate rig supply wells in practice? Mary Sahs went to considerable effort to review the rules of, and interview, several groundwater districts in areas where shale drilling is taking place. Their rules and practices vary considerably. Some districts impose spacing requirements. Some districts require registration and reporting of production. Only one district considered such wells to be fully subject to its regulations.

Districts also have jurisdiction to prevent "waste" of groundwater. Waste can occur where groundwater, stored in earthen pits, leaks into the soil or evaporates; or when the groundwater is transported through aluminum pipes with joints that leak. According to Mary, few districts are addressing this issue.

From Mary's survey:

The Evergreen Underground Water Conservation District (Frio, Wilson, Atascosa and Karnes Counties, in the heart of the Eagle Ford) believes it does not have authority to regulate spacing. Wells must be registered, but no drilling permit is required. If the well is turned over to the surface owner, the well must then comply with spacing rules to get a permit.

The Gonzales County Underground Water Conservation District (parts of Gonzales and Caldwell Counties) only has authority to regulate water wells producing from the Wilcox, Carrizo, Queen City and Sparta aquifers. Rig supply wells are generally not completed in those aquifers because of their depth. The District has asked operators to report production from their wells. The District encourages operators to use water that is too saline for human consumption, to avoid competition with human uses.

The Upper Trinity Groundwater Conservation District (Montague, Wise, Parker and Hood Counties, in the Barnett Shale) has special legislation allowing it to assess and collect production fees on all groundwater used for oil and gas drilling. Rig supply wells must be registered and production metered and reported, both the volume produced and the volume used at the well head. This allows the district to assess how much water is being lost between the water well and the point of use.

Panola Counter Groundwater Conservation District (Panola County) considers rig supply wells exempt, but asks that they be registered and their production reported. If a landowner sells water for fracing, his well becomes a non-exempt commerical well and must comply with all the district's rules. Mary reports, from her interview with the General Manager of the district, that "frac water wells create an approximate 1700 foot cone of influence as long as they are filling the frac ponds. Once that use ceases, the water levels recover within 2 months."

Pineywoods Groundwater Conservation District (Angelina and Nacogdoches Counties) asserts the right to regulate all aspects of rig supply wells. They must be registered and report production monthly, and are considered non-exempt industrial or commerical production wells that must obtain drilling and operating permits and pay a production fee.

Landowners should make themselves familiar with rules of their GCD's. They should call the district and ask what rules apply to rig supply wells. If the landowner wants to take over a rig supply well it should know what requirements the district will impose, and it should if possible require in its lease that the operator comply with all district rules so that the landowner will be able to use the well. If a landowner wants to use its own well to supply water for hydraulic fracturing it should know the district rules and should, if required, register the well and comply with all reporting requirements.

Groundwater Districts are so far taking a cautious approach to regulation of rig supply wells. In general, they are busy enough trying to establish their desired future conditions and their permitting and production requirements for non-exempt wells. But as they mature, and as drilling in shale plays continues and begins to affect the water levels in aquifers, districts may assert their authority to regulate how the oil and gas industry uses groundwater in their jurisdiction.

In his remarks on the Senate floor, Senator Inhofe highlighted a talk given by Armendariz that was captured on video and recently posted to YouTube, in which he says that, because of the limited number of staff in his office, his approach is to act like the Romans: "They'd go into a little Turkish town somewhere, they'd find the first five guys they saw and they would crucify them. And then you know that town was really easy to manage for the next few years.". Inhofe also wrote a letter (Inhofe letter 04-26-12.pdf) to EPA Administrator Lisa Jackson, highly critical of Armendariz's actions. 

Armendariz was also responsible for the "emergency order" issued by his office against Range Resources for allegedly contaminating groundwater in Parker County -- an allegation since disproven. Recently, EPA voluntarily dismissed its suit seeking to enforce the emergency order, after the Texas Railroad Commission found that Range was not responsible for the methane in the contaminated water well.

In 2010 Exxon purchased XTO Energy for $35 billion in stock, Exxon's largest acquisition since its merger with Mobil in 1999. Exxon's acquisition was an effort to get in on the shale gas revolution by buying XTO, one of the biggest holders of shale gas reserves. Exxon has (wisely in my view) kept XTO as a separate entity, in what Rex Tillerson, Exxon's CEO, calls "reverse integration." Since Exxon acquired XTO, XTO's gas reserves have increased 81% to 82 Tcf. Fifty percent of Exxon's total reserves are now in natural gas. XTO is Exxon's big bet on the long-term success of domestic natural gas as the preferred energy source for the US.

US natural gas production has increased 28% since 2005, and about one-third of that production is from shale gas. By 2035 it is estimated that shale gas will make up about 60% of US production. Rex Tillerson believes that natural gas will be the fuel of choice for electricity generation. Exxon estimates that world demand for electricity will grow 80% by 2040 and that natural gas will pass coal as the world's second-largest fuel source (behind crude oil) by 2025. Daniel Yergin: "I believe natural gas in the years ahead is going to be the default fuel for new electrical generation. Power demand is going to go up 15% to 20% in the US over this decade because of the increasing electrification of our society -- everything from iPads to electric Nissan Leafs. Utilities will need a predicable source of fuel in volume to meet that demand, and natural gas best fits that description."

Increased gas production has rippled through the US economy. According to Fortune, the US is now a net exporter of refined petoleum products, for the first time since 1949; plans to build facilities for the import of liquified natural gas are being revised to use those facilities to export LNG -- Cheniere Energy plans to begin construction of a new LNG processing unit at Sabine Pass on the Louisiana coast, to begin exporting LNG by 2015; cheap gas has revived the US steel industry -- Nucor Steel has broken ground for a $3.4 billion steel plant near Baton Rouge, La., and US Steel is building a new facility in Lorain, Ohio. In Texas, increased tax revenues are expected to save the state from another disastrous bienneum of deficits. Texas unemployment is well below the national average because of the oil industry.

"We call it the great revival of the North American oil industry," says Daniel Yergin. "This is a turnaround not just for North America's oil supply, but one with global impact. It's certainly the biggest development in the world oil market of this century."

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 Environmental Protection Agency has thrown in the towel. It dismissed its suit against Range Resources that sought to enforce its emergency order claiming that Range was responsible for contamination of water wells in Parker County. See Bloomberg's article here.

I have previously written about this controversy. See my previous posts here and here and here and here and here. The EPA alleged that the water well belonging to the Lipskys had been contaminated with methane by Range's fracing of wells in the area. Range called a hearing at the Railroad Commission and invited the EPA and the Lipskys to attend, but they declined. The RRC found that Range's well was not the cause of the water well contamination; it concluded that the methane was naturally occurring and was caused when the water well was drilled too deep, into a shallow gas formation. Range fought the EPA's allegations vigorously. So far, the EPA has been unable to link any groundwater contamination to hydraulic fracturing.

The Lipskys also filed a civil suit against Range seeking damages -- a big mistake. Range got the Lipsky's case dismissed, on the ground that the RRC had already determined that Range was not at fault. Range filed a counterclaim against the Lipskys for defamation and to recover the costs of its litigation, and also filed a cross claim against the Lipskys' expert Alisha Rich, claiming that she conspired with the Lipskys to produce false evidence in the case. Those claims remain pending.

Horizontal Wells Now Have As Many As 20 Frac Stages

In 2003, the average number of frac stages for a horizontal well was four. (A "frac stage" is the process of using hydraulic fracturing in an isolated segment of a horizontal well, thus concentrating the pressure and energy in a limited portion of the formation.) Last year, the average number of frac stages was twenty. Lateral lengths have also increased dramatically. In 2003, the average lateral length in Tarrant County (the Barnett Shale) was 2,433 feet. In 2010, it was 3,599 feet. The standard length in the Eagle Ford is now a mile (5,280 feet), and some wells are being drilled to 8,000 feet or more.

GAO Says That Regulators Don't Have Sufficient Information to Ensure Safety of Gathering Lines

The US General Accounting Office has issued a report on the safety of gathering lines. Gathering lines are generally the pipelines that go from the well head to the transmission line. While transmission lines are heavily regulated by US and state regulators, gathering lines are for the most part unregulated. The GAO report says that:

Try it for yourself. It's fun, and you may learn something in the process.

Goodell's article covers ground that is not new in the debate over the safety, ecology and economics of hydraulic fracturing. He touches on the study by Anthony Engraffea at Cornell University on whether natural gas has less global-warming effect than coal. He discusses the Duke University study of methane in water wells in Pennsylvania. He quotes Arthur Berman (Berman says miss-quoted), a long-time critic of the industry's estimates of shale gas reserves.

McClendon says he agreed to talk to Goodell after he was told that the magazine would publish an article on Chesapeake whether it cooperated or not. Chesapeake has issued a rebuttal to the article ("Although our expectations for honesty and fairness were quite low, the writer failed to reach even that low bar."), and Goodell has responded to Chesapeake's rebuttal ("The company entirely dodges the article's central point: that Chesapeake is a highly-leveraged firm operated by a corporate gambler who engaged in complex scheme to profit off the illusion that America has a virtually unlimited supply of cheap natural gas."). (Isn't the internet amazing?) 

Last Thursday I went to a showing of spOILed, a documentary about the oil and gas industry by journalist turned media analyst Mark Mathis. I recommend the movie as a good effort by a non-expert journalist to understand and analyze the place, importance and future of hydrocarbons in the world today. Unlike Goodell, Mathis comes down on the side of industry. He concludes that, like it or not, the world is dependent on hydrocarbons, which have made our 21st century economy and lifestyle possible; and that the world will not soon develop alternate sources of energy that could wean us from dependence on hydrocarbons, and so must continue to develop available reserves to prevent a catastrophic rise in energy prices if demand exceeds supply.

Whether you agree with Mathis or Goodell, the debate over energy and its future is one that should continue, and good journalists making real efforts to understand and explain the issues in ways that the general public can understand should be encouraged. Remarkably, there is very little debate over these issues in the political sphere, despite the recent environmental disasters -- the Gulf oil spill and the near-meltdown of nuclear reactors following the tsunami in Japan. I would encourage Mathis to read Goodell, and I would recommend Mathis' movie to Goodell. Each could learn something to learn from the other.

I wrote about this case a couple of weeks ago. See my prior discussion here. Pipeline companies had deluged the Court with briefs after its initial opinion, claiming that the Court's decision will halt pipeline construction across the state.

While denying Denbury's motion for rehearing, the Court did issue a revised opinion that made some changes to its language. The Court's opinion adds language responding to some of the arguments of the friend-of-the-court briefs filed by other pipeline companies; and the revised opinion changes the holding as follows:

We accordingly hold that for a person intending to build a CO₂ pipeline to qualify as a common carrier under Section 111.002(6), 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 their gas or sell it to parties other than the carrier.

The Court also added a footnote to its holding: "Our decision today is limited to persons seeking common-carrier pipeline status under Section 111.002(6) [of the Natural Resources Code]. We express no opinion on pipelines where common-carrier status is at issue under other provisions of the Natural Resources Code or elsewhere." (Section 111.002(6) relates only to pipelines that transport carbon dioxide. Other provisions of the Code cover pipelines that carry natural gas and hydrocarbons.)

James Mann, an Austin attorney and lobbyist for the pipeline industry, was quoted in the Houston Chronicle as commenting that "It's unclear to us just how bad this opinion is. If it only affects CO2 pipelines, it can be survived. If the same holdings are applied to all other types of pipelines, it is disaster for the oil and gas industry." Kent Sullivan, a lawyer with Sutherland Asbill & Brennan in Houston, said that the opinion represents "a substantial shift in power or potential leverage" for landowners. Sullivan predicted that the issue is likely to be a topic in the 2013 legislative session.

The opinion is certainly not surprising. It would have been a surprise to most people to learn that they do not have ownership rights in groundwater under their property. But I question whether it is such a victory for property owners and whether it will materially change the current regulatory scheme for groundwater in Texas.

Justice Hecht's opinion, 49 pages, includes a good summary of the history of groundwater regulation and litigation in Texas over the last 100 years. Remarkably, in all that time the Court had never ruled on the question of whether landowners have a property right in groundwater. The court held that the same rules should apply to groundwater as apply to oil and gas - in both, the landowner has an ownership right in the substance under his/her land, subject to being divested of that ownership by drainage from wells on adjacent lands, and subject to reasonable regulation by the state.

In EAA v. Day, two farmers owned 350 acres south of San Antonio. They applied to the Edwards Aquifer Authority for a permit for their existing water well on the property. Under the rules of the EAA, their right to use water from the well depended on what use they made of the water during the historic period from June 1, 1972 to Mary 31, 1993. The farmers applied for a permit to pump up to 700 acre-feet per year, for irrigation. The EAA granted a permit for only 14 acres, finding that their proof of historic use was not adequate. The farmers then sued, alleging that denial of their permit for 700 acre-feet constituted a taking of their property without compensation. After holding that the farmers did have a "property right" in their groundwater of which they could not be deprived without compensation, the Court remanded the case to the trial court for additional evidence on whether the EAA's regulations did in fact constitute a taking of property for which compensation is due.

This is where the case gets interesting. The court discusses how the trial court, when it gets the case back, should decide whether the farmers are entitled to compensation. Relying on a US Supreme Court case, Penn Central Transp. Co. v. New York City, the court adopted a test of "reasonableness": the trial court must consider "the economic impact of the regulation on the claimant and, particularly, the extent to which the regulation has interfered with distinct investment-backed expectations"; and the "'character of the government action' -- ... whether it amounts to a physical invasion or instead merely affects property interests through 'some public program adjusting the benefits and burdens of economic life to promote the common good.'" Considering these factors, the court must decide whether the economic impact of the regulation on the farmers, considering the promotion of the common good resulting from the regulation of groundwater imposed by the EAA, rises to the level of a "taking" of private property for public use. This in my opinion does not give the trial court much to go on. It is a pretty subjective test and will depend on particular facts. The Supreme Court remanded the case to the trial court to further develop those facts.

So what does this mean for Texas landowners and groundwater districts? Perhaps more litigation. Landowners unhappy with decisions made by their local water district may sue claiming that the district has "taken" their water rights. But, as can be seen by the Day case, such a battle is not to be taken on lightly -- in fact, Mr. Day died before the decision was issued -- and will be expensive. And there is the possibility that an unsuccessful claimant would have to reimburse the water district's legal fees. Most water districts have very limited budgets and so will be reluctant to fight landowners' inverse condemnation suits. As a result, they may be more cautious in how they draft and enforce their regulations.

All in all, the case is an important, but not surprising, milestone in the continuing development of groundwater rights law in Texas.

In the Denbury case, the Supreme Court held that a pipeline does not acquire condemnation authority merely by obtaining a permit from the Railroad Commission and subjecting itself to that agency's jurisdiction as a common carrier. The Commission makes no determination whether the intended use of the pipeline is in fact "public." The court then held that in order for a pipeline to serve a public purpose and thus have condemnation power, "a reasonable probability must exist, at or before the time common-carrier status is challenged, that the pipeline will serve the public by transporting gas for customers who will either retain ownership of their gas or sell it to parties other than the carrier." Once a landowner challenges its status as a common carrier, "the burden falls upon the pipeline company to establish its common-carrier bona fides if it wishes to exercise the power of eminent domain."  The court also held that one affiliated company transporting gas solely for the benefit of another affiliate is not a public use of the pipeline. The court said that the question of whether the pipeline is dedicated to a "public use" is ultimately a judicial question.

The court's opinion has caused a firestorm in the pipeline industry, which claims that the case will halt construction of pipelines across the state. Denbury has asked the court to re-hear the case, and at least sixteen amicus briefs have been filed. One of the most interesting is from ETC NGL Transport LLC, which is in the process of condemning a 125-mile pipeline route to transport natural gas liquids from the Eagle Ford shale to facilites in Mont Belvieu, Texas. ETC claims that a county court at law in Harris County has enjoined ETC from "taking possession of the easement [that ETC has condemned] based on an implied finding that ETC is not a common carrier." ETC claims that, "due to this Court's Denbury opinion, landowners were able to convince a county court at law that ETC, which is clearly a common carrier, is not a common carrier."

Denbury is also being cited in an attempt to halt condemnation proceedings for the Keystone XL pipeline in East Texas. Notwithstanding President Obama's refusal to approve the project, Keystone is apparently continuing with its acquisition of right-of-way in East Texas. "We don't need a presidential permit in order for us to obtain the easements that we need for the right of way for this project," said TransCanada spokesman Terry Cunha.

One landowner group has found at least 89 condemnation suits filed by Keystone in Texas. A landowner in Lamar County, Julia Trigg Crawford, got a restraining order halting any further proceedings on her property until Keystone proved its right to condemn her property. "I'm just an angry steward of the land," Crawford said. "A foreign-owned, for-profit, nonpermitted pipeline has taken a Texan's land. Doesn't sound right, does it?" Watch Ms. Crawford discussing her case here. It is unclear whether the Texas Supreme Court would agree that Keystone's activities in transporting Canadian Crude to the Texas Gulf Coast would qualify it as a "common carrier."

With water so much on everyone's minds, I thought it would be a good idea to review some basic facts about water. The following information is from a presentation made by Tom Mason, former General Manager of the Lower Colorado River Authority, who is now a shareholder at my firm, Graves Dougherty Hearon & Moody.

Water on earth:

-- 97% is in the oceans

-- 3% is fresh water

-- 69% of fresh water is ice - glaciers and icecaps

-- 30% of fresh water is groundwater

-- .3% (three tenths of one percent) of the world's fresh water is contained in rivers and lakes

Last month, Texas' water planning agency, the Texas Water Development Board, published Texas' 2012 Water Plan. This plan was developed through a complex planning process involving 16 regional planning groups. The plan lists 562 recommended water supply projects and strategies to meet the State's expected water demands for the next 50 years. Estimated costs of those projects: $53 billion.

Most significant aspects of the Texas Water Plan:

Conservation. Twenty-five percent of the "new water" proposed by the plan is by conserving existing supplies. About 2/3 of that conservation is from agriculture, most of the rest municipal. Conservation is possible: San Antonio has reduced per capita water consumption by more than 40% over the last 26 years  -- in part because a federal court ordered the city to limit withdrawals from the Edwards Aquifer due to environmental concerns. San Antonio engaged in educaton compaigns, new water pricing (the more you use the higher your rate), low flow toilets, repairs of leaky pipes, outdoor water restrictions. Farmers conserve by laser leveling of fields, changes in crops, more efficient irrigation equipment.

New Reservoirs. Texas' water plan proposes that 17% of "new water" supplies will come from new reservoirs. But there are not many good reservoir sites left in Texas. New dams are very expensive, hard to permit, and few federal dollars are available for such projects. Landowners resist use of eminent domain for reservoirs. Most of the new reservoirs proposed are "off-channel" reservoirs, which will capture heavy flood flows in very large ponds and release them when needed.

Groundwater. 9% of new water supplies are projected to come from development of groundwater resources. About 60% of all water use in Texas now comes from groundwater. Regulation of groundwater development in Texas is handled by groundwater districts. There are now some 96 such districts, and each has its local governing board and sets its own rules. Many districts are underfunded and understaffed. There is now great uncertainty over the powers and limits of groundwater regulation that these districts can impose. With such decentralized management and legal uncertainty, it is difficult to predict how groundwater will meet Texas' future water supply needs.

Water Reuse. The water plan derives 10% of its "new water" for Texas' future from reusing treated sewage effluent. Again, the increased use of treated effluent has caused legal uncertainty: who owns water once it has been treated for reuse?

Desalination. 3.5% of "new water" in the Texas Water Plan is from desalination. The cost of water from desalination is now 2 to 7 times more than river water or groundwater.

Water is a big energy user. The State of California uses almost 20% of its total energy production to treat and move water. The City of Austin's water utility is the single largest customer of the City's electric utility. Energy production is also one of the largest water users, although much of the water used for electric generation is returned to rivers and streams after use.

Water and energy remain two of the biggest challenges for Texas, our nation and the world.

TWU 2012 Energy Symposium.pdf

There is a lot on the program about the Marcellus Shale. To see the program, go here: 

http://www.texaswesleyanlawreview.org/index.php?option=com_content&view=article&id=15&Itemid=202

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.

http://www.giss.nasa.gov/research/news/20120119/

Highlights:

Domestic crude oil production is expected to grow by more than 20 percent over the coming decade: Domestic crude oil production increased from 5.1 million barrels per day in 2007 to 5.5 million barrels per day in 2010. Over the next 10 years, continued development of tight oil combined with the development of offshore Gulf of Mexico resources are projected to push domestic crude oil production to 6.7 million barrels per day in 2020, a level not seen since 1994.

With modest economic growth, increased efficiency, growing domestic production, and continued adoption of nonpetroleum liquids, net petroleum imports make up a smaller share of total liquids consumption: U.S. dependence on imported petroleum liquids declines in the AEO2012 Reference case, primarily as a result of growth in domestic oil production of over 1 million barrels per day by 2020, an increase in biofuel use of over 1 million barrels per day crude oil equivalent by 2024, and modest growth in transportation sector demand through 2035. Net petroleum imports as a share of total U.S. liquid fuels consumed drop from 49 percent in 2010 to 38 percent in 2020 and 36 percent in 2035 in AEO2012.

U.S. production of natural gas is expected to exceed consumption early in the next decade: The United States is projected to become a net exporter of liquefied natural gas (LNG) in 2016, a net pipeline exporter in 2025, and an overall net exporter of natural gas in 2021. The outlook reflects increased use of LNG in markets outside of North America, strong domestic natural gas production, reduced pipeline imports and increased pipeline exports, and relatively low natural gas prices in the United States compared to other global markets.

Use of renewable fuels and natural gas for electric power generation rises: The natural gas share of electric power generation increases from 24 percent in 2010 to 27 percent in 2035, and the renewables share grows from 10 percent to 16 percent over the same period. In recent years, the U.S. electric power sector's historical reliance on coal-fired power plants has begun to decline. Over the next 25 years, the projected coal share of overall electricity generation falls to 39 percent, well below the 49-percent share seen as recently as 2007, because of slow growth in electricity demand, continued competition from natural gas and renewable plants, and the need to comply with new environmental regulations.

Total U.S. energy-related carbon dioxide (CO₂) emissions remain below their 2005 level through 2035: Energy-related CO₂ emissions grow by 3 percent from 2010 to 2035, reaching 5,806 million metric tons in 2035. They are more than 7 percent below their 2005 level in 2020 and do not return to the 2005 level of 5,996 million metric tons by the end of the projection period. Emissions per capita fall by an average of 1 percent per year from 2005 to 2035, as growth in demand for transportation fuels is moderated by higher energy prices and Federal fuel economy standards. Proposed fuel economy standards covering model years 2017 through 2025 that are not included in the Reference case would further reduce projected energy use and emissions. Electricity-related emissions are tempered by appliance and lighting efficiency standards, State renewable portfolio standard requirements, competitive natural gas prices that dampen coal use by electric generators, and implementation of the Cross-State Air Pollution Rule.

http://www.eia.gov/forecasts/aeo/er/