Today's hearing continues the Environment and Public Works Committee's examination of environmental laws and their interaction with the nation's energy supply and demand. My testimony today will focus primarily on several environmental issues and how they impact the petroleum and natural gas exploration and production (E&P;) industry.
Let me begin by describing the unique nature of the industry and the specific challenges we face in the context of federal environmental law. The petroleum and natural gas E&P; industry is distinguished by its breadth and diversity. Oil and gas are natural resources that are found in 33 states, 12 of which are represented on this committee. There are over 850,000 producing oil and natural gas wells in the country in areas ranging from arid plains to forests to wetlands.
The operation of these wells has been regulated since the 1920s with an increasing emphasis on environmental controls since the 1960s. This regulation has been and continues to be done effectively by the states - a reality that has been recognized by the Congress and by the EPA. Because of the diverse conditions associated with oil and natural gas production, the regulatory process must be flexible and reflect the unique conditions in a state or areas within a state. It requires the technical expertise that has been developed in each state and which does not exist within the EPA. For this reason federal law has generally deferred regulation of this industry to the states. Additionally, because so much of federal law is written based on regulating small numbers of point sources, some laws have created particular problems for the oil and gas E&P; industry. In some instances this has resulted in specifically crafted provisions to address the oil and gas E&P; industry.
Complying with environmental regulations remains a significant cost for the E&P; industry, with estimates of annual costs ranging from about $1.6 billion to more than $2.6 billion. These costs are particularly significant during times of low commodity prices, such as occurred during the 1998-99 oil price crisis. Equally important is understanding that independent producers, who range from large publicly traded companies to small business operations, drill 85 percent of the wells within the United States. The common factor for these independents is that their revenues and hence their ability to meet these environmental costs comes solely from the exploration, production and sale of crude oil and natural gas from the wellhead. Unlike the large major producers - the integrated oil and gas industry - the independents have no means of passing on production and regulatory costs through other operations, such as refining and marketing. Ohio's producers are "price-takers" rather than "price-makers".
Consequently, the industry places great emphasis on cost effective regulation, limiting paperwork burdens, and avoiding duplicative regulatory requirements. In general, the unique problems associated with the diverse nature of the E&P; industry have been addressed, making the burden of regulation manageable. However, there have been exceptions and there are issues that need attention.
Safe Drinking Water Act, LEAF v. EPA and Hydraulic Fracturing
For example, the most compelling environmental issue currently confronting the oil and natural gas E&P; industry is a movement to have U.S. EPA regulate hydraulic fracturing under the Safe Drinking Water Act (SDWA).
Hydraulic fracturing is a common and necessary procedure used by producers to complete crude oil and natural gas wells by stimulating the well's ability to flow increased volumes of oil and gas from the well's reservoir rock into the wellbore. It is necessary in order to obtain production from wells that, for lack of proper stimulation, would not naturally yield economic volumes of crude oil and natural gas. Massive numbers of hydraulic fracturing have been performed in Ohio and throughout the United States, dramatically increasing the nation's oil and gas resource base.1
At the time the SDWA was enacted, the states had already developed extensive Underground Injection Control (UIC) programs to manage liquid wastes resulting from oil and gas operations and the reinjection of produced waters. By 1980 Congress - recognizing the need for further state flexibility - modified the SDWA to give states "primacy" based on comparable state oil and gas UIC programs. These changes were made because Congress recognized that the approach it had envisioned was inconsistent with the realities of UIC regulation. It recognized that the state UIC programs were well structured and that EPA could not fashion a federal program with the flexibility needed to deal with the different circumstances existing in the various states.
At no time during these debates - in 1974 or in 1980 - was there any suggestion of including hydraulic fracturing in the UIC waste management requirements. Nor was it an issue in the 1986 or 1996 reauthorizations of the SDWA. The reason is clear. Hydraulic fracturing - while it temporarily injects fluids into underground formations - is not the underground injection that the SDWA was designed to regulate. There have been over a million hydraulic injection operations during the past 50 years. States have regulated its use in their well permitting processes. It does not create environmental problems.
Nonetheless, in the mid-1990's the Legal Environmental Assistance Foundation (LEAF), after years of failing to make an environmental case against coalbed methane development, petitioned the U.S. EPA to regulate hydraulic fracturing under the UIC program. EPA rejected LEAF, arguing that Congress never intended UIC to cover hydraulic fracturing. LEAF appealed to the 11th Circuit Court of Appeals.
In 1997, the 11th Circuit Court decided the LEAF v EPA case. The Court never addressed the environmental risks of hydraulic fracturing; it merely decided that the plain language of the statute could include hydraulic fracturing as underground injection. This decision compels a revision to the SDWA because its basis is so fundamental that adverse regulatory action is inevitable.
Initially, EPA responded to the LEAF decision by requesting the Ground Water Protection Council (GWPC) to study coalbed methane wells. After evaluating 10,000 wells, it found one complaint - the LEAF case Alabama well that EPA had already concluded was not a fracturing problem. However, LEAF went back to the Court to force EPA action. EPA then compelled Alabama to develop a UIC regulation that requires the use of federally certified drinking water for fracturing jobs, water that must be purchased from willing cities and trucked to the well development operations.
LEAF filed a second case - likely to be decided this year - arguing that EPA erred in the Alabama regulation. LEAF argues in part that EPA should have first written a nationally applicable rule. If EPA loses this case, all hydraulic fracturing jobs could be federally regulated. The National Petroleum Council estimates that 60 to 80 percent of all the wells drilled in the next decade to meet natural gas demand will require fracturing.
Even if EPA wins the LEAF II case, the likely result would be a rash of cases raising the hydraulic fracturing issue in Federal Circuit Courts across the country. Given the "plain language" nature of the original case, most attorneys believe that such cases would produce similar results - a forced federal regulation in each state.
Not considered an issue at the time the SDWA was passed, Congress did not specifically exclude hydraulic fracturing. Two decades later, a court ignored the facts of the issue and changed the scope of the law on a technicality. Now, a legislative resolution is essential to clarify the original intent of Congress and the definition of underground injection. Industry believes that Congress should address this issue quickly through a bipartisan effort. A clear opportunity exists to bring the states and EPA together on this matter and produce an environmentally sound resolution that would prevent the loss of key energy supplies.
Clean Water Act, Endangered Species and Clean Air Act
While hydraulic fracturing represents the most compelling issue that needs legislation, there are others that require attention as well. For example, because many oil and natural gas producers are small businesses, paperwork burdens are always an issue. Here, some issues that affect producers are:
* Under the Clean Water Act, producers are required to submit Spill Prevention, Control, and Countermeasure (SPCC) Plan updates every three years (EPA has proposed to extend this period to five years). These SPCC plans provide details about the facility's operations and spill control measures. Producers must also submit Emergency and Hazardous Chemical Inventory Forms under the Emergency Planning and Community Right-To-Know Act (EPCRA), but must do so annually. Most of these EPCRA forms do not change and the same objective could be achieved by filing every three years with annual reports that would identify any significant changes. It would reduce the paperwork burden with no environmental detriment.
* Additionally, the requirements that trigger the need for a stormwater construction permit under the Clean Water Act are changing. The construction area subjected to these permits is being reduced from five acres to one acre. As a result, oil and gas production facilities - which have typically not been required to get these permits - will now be subjected to this regulatory requirement. While EPA has indicated that it will craft the permit requirements to minimize burdens to the producer; this process needs to be carefully monitored as it is implemented to avoid undue delay in developing production sites.
Not all issues are related to procedures or paperwork. Others relate to interpretations of laws that can adversely affect natural gas and oil exploration and development. Historically, these problems have related more to obtaining permits for operations than to meeting emissions limitations. For example:
* Under the Clean Water Act, some projects require Section 404 dredge and fill permits. While this process is managed by the Corps of Engineers, it involves interactions with agencies that have jurisdiction with regard to wetlands. Moreover, the definition of a wetland has been confusing and in dispute for decades. The result of these factors has been permitting uncertainty. Part of the concern results from different objectives of the agencies involved in the permitting process. While their responsibilities will not change, it is essential that they all recognize the need to develop domestic energy supplies and work toward achieving this national objective in a cost effective, environmentally sound process.
* The Endangered Species Act raises similar issues. When Federal Land Managers - principally the Bureau of Land Management - develop resource management plans (RMPs) one of their important considerations is habitat management for endangered species. Oil and natural gas exploration and production is a temporal process. It involves drilling activities for a limited period of time followed by production activities that can include well maintenance efforts while the well produces. When the well is depleted, it is closed and plugged and the area returns to its prior condition. Over the years these activities have become less intrusive to the environment. The Department of Energy's 1999 report, Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology, demonstrates the types of actions that are taken. The key point here is that oil and gas E&P; coexists with nature. This reality needs to be recognized as RMPs and other permit actions are developed, including habitat management plans that protect endangered species and encourage energy supply. Addressing this important balance does not require sacrificing the principles of the Endangered Species Act, it merely requires greater efforts to define alternatives that can accommodate both national objectives whenever possible.
* Recently, there has been discussions of aggregating individual oil and gas wells in a particular geographic area for purposes of defining a "major source" under Title V of the Clean Air Act. If that is done, it would impose a whole host of additional regulatory burdens on the producing industry with little benefit to the environment. The question of how to determine when federal clean air regulation should apply to E&P; facilities has already been raised in the context of the operation of Section 112 as amended in 1990. Congress concluded that individual oil and gas wells should not be aggregated for the purpose of determining whether they represented a major stationary source. This decision reflected the reality of oil and gas E&P; operations. While there may be several wells in an area, there is no certainty that they are operated by the same entity; in general, they are not. Unfortunately, the issue has arisen with regard to whether the definition of major source under Title V with regard to whether facilities permitted by the federal government should be interpreted consistent with Section 112. While the definitional limitations are not replicated in Title V, we believe that EPA should use the same approach. In particular, since aggregation would not result in appreciably different control requirements, it makes no environmental sense to capture oil and gas E&P; operations under the permitting burdens of Title V.
While issues such as endangered species have greater impact on oil and gas development in the Western United States, similar issues have also impacted development in the Appalachian Basin. For example, in the Wayne National Forest of Ohio, Carlton Oil Corporation, a small oil and gas producer, for an extended period has been seeking to obtain a permit from the Bureau of Land Management (BLM) to drill a development well on a federal lease tract. Since applying for the permit in February 2000, the producer has been waiting while the Forest Service has performed an environmental assessment taking into account new information, if any, regarding endangered species and the relationship of that information to the Forest Plan. It is ironic that the producer already operates two other wells on the same property. Even more ironic is that continuous oil and gas operations have existed in this area since 1860. While this producer has been waiting for the federal process to resolve itself, his requisite permits issued by the State of Ohio have been issued and expired. Needless to say, he is frustrated with a process that stymies the drilling of a simple and common development natural gas well in what is the most mature oil and gas producing province within the United States. Meanwhile, Ohioans have joined the national chorus demanding answers to why natural gas supplies are tight.
These types of issues reflect an ongoing dilemma that needs to be addressed. Without altering the underlying requirements of environmental law, the energy supply implications of new regulations, guidance, resource management plans, interagency memorandums of understanding, and other planning and review processes need to be identified early and become a part of the decision making process. This step would assure that where possible these actions could be tailored to address both environmental and energy needs. Such an approach has been included in Section 101 of S. 388 and S. 389, the National Energy Security Act of 2001.
Pipeline Issues
There are pipeline issues as well. Congress, in its 1996 amendment to the Pipeline Safety Act of 1992, directed the U.S. Department of Transportation ("USDOT") to define the term "gathering line" for purposes of jurisdiction in its gas pipeline safety regulations. This is important because gathering lines are generally exempt from regulation unless they are located within urbanized settings. USDOT failure in the past to address this issue has created a regulatory vacuum that has resulted in uncertain and vague application of regulatory standards within the states.
In 1999, U.S. DOT issued a Request for Comments on the issue of whether and how to modify the definition and regulatory status of gas gathering lines for the purposes of pipeline safety regulation. In response to USDOT's request, an industry coalition comprised of representatives from across the country and from small independent producers to the large integrated companies, proposed a unified definition for the pipeline safety program for gas gathering. That definition was filed with the agency on April 24, 2000. The American Petroleum Institute published a recommended practice document based on this definition.
Establishing regulatory stability in the arena of pipeline construction and operation is an important goal for the regulated community, particularly for the Appalachian oil and gas industry. The Appalachian Basin is the country's oldest natural gas producing field. It has been producing and gathering natural gas without safety mishaps for over a hundred years. It is located in very close proximity to major population areas of the country, especially the northeast. At a time when consumption of natural gas is expected to increase, it is imperative that a nationally driven gathering pipeline regulatory program be established that acknowledges the safety record of the Appalachian region and that enhances the region's ability to collect its naturally high quality gas and deliver it to transmission and distribution systems.
On March 8, 2001 representatives of the Gas Gathering Industry Coalition, to include the Appalachian industry, met with USDOT representatives to discuss the agency's plans with regard to its open rulemaking on the definition of gas gathering for the Pipeline Safety program. DOT conceded that it has yet to act on the need to establish a promulgated rule. The agency has offered to reconsider its reluctance to review the Industry Coalition proposal and committed to providing a response to industry's request that a public meeting be held to further discuss the development of a rulemaking. It is essential that the DOT be given the appropriate support and guidance for bringing to resolution this long outstanding issue. It is also essential that any such resolution enhances the movement of gas rather than create unnecessary regulatory burdens.
Pipeline issues also extend to the downstream industry that seeks to deliver finished petroleum products to the consumer. In Ohio, Marathon Ashland Petroleum LLC is proposing to build a 14" diameter petroleum products line to connect supply from its Catlettsburg, KY refinery to one of the fastest growing areas - Central Ohio. The Midwest faces unique challenges in the petroleum industry as it lacks the refining capacity to manufacture enough gasoline, diesel fuel, jet fuel, etc. to satisfy consumer demand. As a result, states like Ohio rely on Gulf Coast refineries for 25 percent of their petroleum products - most of which travels through capacity-constrained pipelines. There is an obvious need for more petroleum products into the Midwest. Marathon Ashland Petroleum's proposed project (Ohio River Pipe Line) will bring up to 80,000 barrels/day of refined product into Central Ohio. Nonetheless, the project has suffered many permit and legal delays and three years later not a single mile of pipeline has been laid.
Marathon Ashland has endured three years of environmental reviews and evaluations of streams, wetlands, rivers, cultural resources, and state and federally-listed threatened or endangered species. Even though the company has met, and many times significantly surpassed, the requirements of the requested permit, the approval process is not yet complete nor is it streamlined to the point where approvals can occur in an acceptable timeframe. Additionally, there is broad subjectivity in interpreting the regulations and oftentimes there are conflicting requirements between the multitude of state and federal agencies involved. Primary agencies involved in the process include the US Army Corps of Engineers, the USEPA, the US Fish and Wildlife Service, the Ohio EPA, the Ohio Department of Natural Resources, the USDOT's Office of Pipeline Safety (OPS) and the State Historical preservation offices. The lengthy process and uncertainty associated with this project is symbolic of the significant challenges for companies wanting to invest in infrastructure.
Inadvertent Targets, TMDL
The industry also faces issues where it becomes the inadvertent target of a federal regulatory initiative. For example:
* EPA has initiated a new program to address Total Maximum Daily Loadings (TMDLs) on streambodies throughout the United States. The effort is one of a long line of efforts to try to grapple with non-point source pollution of water bodies. While the Clean Water Act has enjoyed great success with its point source control program, non-point source control has been elusive because of its diverse nature. Moreover, because it largely must address drainage from agricultural and forest lands, it has always had to yield to the realities - both technical and political - that control of these sources requires something other than a federal mandate. The E&P; industry finds itself, therefore, in a vulnerable position. In looking at a typical streambody under the TMDL effort, the point sources will be controlled and therefore not likely to be further controlled and the agricultural and forest non-point sources will be deferred until a control strategy can be developed. This leaves small non-point sources as the only remaining targets for EPA to address. While they will not resolve the TMDL problems, they can provide a public relations victory. E&P; operations meet this characterization. They are small but do construction work that can produce runoff even when managed properly.
* The Clean Air Act has elements that can create similar vulnerability. Its history is clear. State and local regulators do not want to impose tough regulations on their citizens if they can shift the control elsewhere. It is much easier to push for auto emissions controls or fuel standards that are the responsibility of distant industries than to require local inspection and maintenance control programs. Visibility regulations are an example where the premise is based on emissions from facilities hundreds of miles away. It creates opportunities for regulators in one state to demand action by other states. In these circumstances there are many western states where there are few sources and those are regulated for local reasons or under new source requirements. The E&P; sources become potential targets not because they are significant but because they are there.
These types of events do not improve the nation's environmental management, but they can threaten its energy supply without any judgment that such regulations would be appropriate or necessary. Balanced decisions are necessary - decisions based on cost effective regulation and sound environmental management needs.
Thomas E. Stewart
Executive Vice President
Ohio Oil & Gas Association
P.O. Box 535
Granville, Ohio 43023
740.587.0444
740.587.0446 - fax
tstewart
ooga.org
www.ooga.org
Mr. Stewart serves as the Executive Vice President of the Ohio Oil and Gas Association, having been elected to that position in September, 199l. At OOGA, Mr. Stewart is director of staff, editor of the Association's publications and an advocate for the industry as a registered legislative agent.
Mr. Stewart serves as an Ohio representative to the Interstate Oil and Natural Gas Compact Commission (IOGCC). Ohio Governor George Voinovich appointed Mr. Stewart to the position in 1997. At IOGCC, Stewart chairs the Public Outreach Committee. Stewart also serves on numerous other committees of national organizations that address issues impacting independent oil and gas producers. He is the Northeast Regional Vice President of the National Stripper Well Association and a charter member of the Cooperating Association Council of the Independent Petroleum Association of America (IPAA).
Prior to joining OOGA, Mr. Stewart has fifteen years' experience in the oil and gas industry as an oil and gas producer and provider of contract drilling services. He is the third generation of his family making their livelihood in the domestic oil and gas industry.
OOGA is a statewide trade association with over 1,300 members who are actively involved in the exploration, development and production of crude oil and natural gas within the State of Ohio. The Association's mission is to protect, promote, foster and advance the common interests of those engaged in all aspects of the Ohio crude oil and natural gas producing industry.
1 An oil and gas producer performs a fracturing procedure to increase the flow of oil and gas from rock, known to contain oil and gas, but where the rock's natural permeability does not allow oil and gas to reach the wellbore in sufficient volumes. These reservoirs are called "tight" and wells drilled to them must either be plugged and abandoned or stimulated to enhance well flow. During a fracture procedure fluid is pumped into the reservoir rock using necessary force to split the rock. In other words, to frac a well is to create drainage ditches that penetrate deep into the reservoir rock.
Hydraulic fracturing is currently the most widely used process for stimulating oil and gas wells. Most often it is a one-time process performed on a well. According to the 1989 SPE Monograph on Recent Advances in Hydraulic Fracturing, the procedure is a standard operating practice that by 1988 had been performed over 1 million times. At that time, 35-40% of all wells were fractured, and about 25-30% of the total U.S. oil reserves have been made economically feasible by the process. By 1988, SPE experts stated that fracturing was responsible for increasing North America's oil reserves by 8 billion barrels.
Since 1951, over 73,000 wells have been drilled to the Clinton, Berea and Ohio Shale zones of Ohio. Between 1970 and 1992, a combination of commodity market conditions and government tax policy caused a boom in tight-formation drilling. During that period, 58,874 wells were drilled in Ohio of which 54,198 wells were productive - a 91.4% success rate. Of these wells, 55,046 were drilled to the Clinton, Berea and Ohio Shale. The Clinton comprised 78.4% percent of that population. With very limited exceptions, hydraulic fracturing was used to complete all of these wells. Exploitation of the tight Clinton sands would not have been possible without fracturing. The hydraulic fracture process made the modern Ohio oil and gas industry.
According to a recent statement issued by the Ohio Department of Natural Resources, Mineral Resources Management Agency, the regulatory agency has not identified a single incident of groundwater contamination associated with a hydraulic fracturing operation.
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OOGA, April 5, 2001, Page 16