U.S. Senate Committee on Environment & Public Works
U.S. Senate Committee on Environment & Public Works
Hearing Statements
Date:   09/16/2003
Statement of Lee Fuller
Vice President, Government Relations
Independent Petroleum Association of America

Clean Water Act oversight.

Mister Chairman, members of the committee, I am Lee Fuller, Vice President of Government Relations for the Independent Petroleum Association of America (IPAA). This testimony is submitted on behalf of the IPAA, the Association of Energy Service Companies, the International Association of Drilling Contractors (IADC), the National Stripper Well Association (NSWA), the Petroleum Equipment Suppliers Association (PESA), the US Oil & Gas Association (USOGA), and 33 cooperating state and regional oil and gas associations. These organizations represent petroleum and natural gas producers, the segment of the industry that is affected the most by regulations that are not cost effective and do not address real environmental risks.

This hearing addresses issues associated with regulations under the Clean Water Act. This testimony will focus on two specific issues that have significant potential implications for domestic oil and natural gas producers – regulations associated with the management of stormwater during the construction of oil and natural gas exploration, production, processing, or treatment operations or transmission facilities (E&P facilities) and expanded regulations for Spill Prevention, Control, and Countermeasure (SPCC) Plans.

Before presenting information on these provisions, it is important to understand the nature of domestic oil and natural gas exploration and production and the role of independent producers. Independent producers are companies that explore for and develop oil and natural gas. Typically, they only operate in these aspects of the petroleum and natural gas industries. There are approximately 7000 independent producers who are predominately small businesses employing an average of 12 employees each. However, they drill approximately 85 percent of the nation’s oil and gas wells.

Domestic petroleum and natural gas production has changed over the years, particularly since the mid-1980s. Maturing production areas in the Lower-48 states and the need to respond to shareholder expectations have resulted in major integrated petroleum companies shifting their exploration and production focus toward the offshore in the United States and into foreign countries. More and more, these large companies must rely on large producing fields that are found only in frontier areas. Consequently, the role of independents is increasing in both the Lower-48 states and in the near offshore areas. For example, the independents’ share of Lower-48 states petroleum production has increased from 45 percent in the mid-1980s to over 60 percent by 1995 – and these states, despite their mature fields, still account for 60 percent of domestic oil production. Similarly, independent producers account for 75 percent of overall domestic natural gas production. These trends will continue. The nation will need a strong independent exploration and production industry to meet it future needs.

Another significant aspect of domestic production – particularly in the context of the effects of regulations – involves the critical role of “marginal” wells. Marginal oil wells are wells producing no more than 15 barrels per day or producing heavy oil; marginal natural gas wells are wells producing no more than 90 mcf per day. The average marginal oil well produces only about 2.2 barrels per day. But, they comprise 84 percent of domestic oil wells (over 400,000) and produce over 20 percent of our domestic oil – an amount roughly equal to imports from Saudi Arabia. Natural gas marginal wells account for about 10 percent of domestic production – or more than a third of current natural gas imports. Taken together, these marginal oil and natural gas wells are about 650,000 of the nation’s 876,000 wells. However, they are the most susceptible to being shutdown when prices fall or costs increase. And, once shutdown, they are lost forever. During the low oil prices of 1998-99 domestic oil production dropped from about 6.5 million barrels per day to less than 6.0 million barrels per day. Most of this loss is attributable to the plugging of marginal oil wells. Average domestic crude oil production has never exceeded 6.0 million barrels per day since; in 2002 production averaged 5.817 million barrels per day.

This perspective is significant because the Clean Water Act regulatory issues that will be addressed in this testimony directly affect the development of new domestic production and the continuation of existing domestic production. Stormwater Construction Permitting Issues

The 1987 Clean Water Act (CWA) included two stormwater provisions that have become, through informal interpretation by EPA, intertwined regarding their application to oil and natural gas E&P facilities. Section 402(p) directs the Environmental Protection Agency (EPA), in general, to require permits for stormwater discharges from municipal and industrial activities under the National Pollutant Discharge Elimination System (NPDES) permitting program. At the same time, Section 402(l)(2) specifically excludes certain stormwater discharges from this requirement, including discharges of stormwater runoff from oil and natural gas E&P facilities, unless the discharge is contaminated by contact with, for example, products, byproducts, or wastes. As discussed in more detail below, EPA says that section 402(l)(2) does not to apply to clearing, grading, and excavating activities at E&P facilities, which EPA considers to be “construction activities” required to obtain a stormwater discharge permit, not E&P activities excluded by 402(l)(2).

IPAA believes that EPA has erred in its interpretation of the Clean Water Act with regard to the relationship between these sections as they apply to oil and natural gas E&P facilities. Congress spoke directly to the exclusion of stormwater related to E&P facilities in section 402(l)(2), and this specific statutory exclusion should control with respect to all activities normally associated with such facilities. Section 402(p) makes no mention of its applicability to construction activities in general, much less of an intent to undercut the specific exemption for E&P facilities in section 402(l)(2). However, despite this structure, EPA has – through a series of disconnected actions – pulled E&P facilities into the stormwater construction permitting program. Following is a summary of these events.

In 1990, EPA promulgated stormwater permitting regulations under Section 402(p). These regulations defined “industrial activities” to include construction activities that disturb five or more acres of land area or are part of a “common plan of development or sale” that ultimately will do so. At the same time, EPA promulgated regulations exempting stormwater discharges from E&P sites from the stormwater permit requirement, unless such discharges are “contaminated” in that they cause a reportable release of oil or hazardous substance or contribute to a water quality standard violation. In 1999,EPA issued Phase II stormwater regulations covering construction activities that disturb from 1 to 5 acres or are part of a common plan that will ultimately do so. Throughout this period, EPA’s regulations exempting uncontaminated stormwater discharges from E&P facilities remained unchanged. Also during this period, however, EPA issued an internal, non-binding guidance memorandum interpreting the scope of section 402(l)(2). The memorandum was issued in December 1992 in response to a question from an enforcement coordinator in one Region. In it, EPA stated that clearing, grading, and other land-disturbing activities at E&P facilities were “construction activities,” not E&P activities and, therefore the oil and gas exclusion in section 402(l)(2) did not apply. IPAA believes that this guidance is inconsistent with the law. However, industry’s challenge to EPA’s 1992 memorandum was dismissed in 1994because of finality constraints on the courts’ authority to review informal agency guidance.

As a matter of law and policy, EPA should evaluate the environmental risks and regulatory burdens created by its actions. In the case of oil and natural gas E&P facilities, IPAA does not believe that EPA made a reasonable assessment of either the risk or the burden. Nowhere in the information that IPAA has reviewed is there an indication of significant environmental risks associated with oil and natural gas E&P facility construction. Nor is there any indication that EPA understood the burdens its program would impose. For example, in an October 1999 report on the costs of the new Phase II requirements there is a revealing footnote, buried in several hundred pages of background and economic analysis, stating:

Based on public comments received on the propose rule, EPA considered including oil and gas exploration sites but, upon further review, determined that few, if any, such sites actually disturb more than one acre of land.

In reality, most oil and natural gas exploration and production sites fall within the one to five acre range. In 2000, a total of 31,732 exploratory and production wells were drilled – over 10,000 in Texas and Oklahoma. To meet future natural gas demand, the National Petroleum Council estimates that the number of natural gas wells alone needs to increase to approximately 48,000 wells annually. However, in the EPA cost analysis of the Phase II program, it estimated that the number of construction starts would be approximately 130,000 units. But, none of these units were oil and gas facilities. Oil and gas facilities alone would increase the number of units by 25 percent with a third of that total coming from the two states of Texas and Oklahoma where EPA Region 6 must handle the administrative burdens. Overall, the ultimate economic consequences of the permit requirement could be staggering, by one estimate as much as $8 billion annually.

Three things are clear. First, if the current level of drilling activity presented stormwater runoff problems during construction, it would be well known. Second, the magnitude of permitting that EPA estimated during the regulatory development process is significantly understated. Third, because the Agency believed that oil and gas facilities were not affected, the final regulation is structured to address construction of building facilities – houses and commercial buildings.

This approach is inappropriate for oil and gas facilities. For example, subdivisions are properties that are purchased by the developer, go through an extensive design process, and have a construction period that may be months or years. There is more opportunity to build time for permitting into the schedule for a commercial or residential construction project, and more opportunity to respond to permit delays. In contrast, oil and gas production operations involve the leasing of sub-surface rights, often on private lands under oil and gas leases with short primary terms. Construction must occur within a matter of weeks, and timing is critical because failure to commence drilling and/or production and/or to maintain production will cause leases, and therefore oil and gas reserves, to be lost. Exploration and production of oil and gas reserves, moreover, involves obtaining a drilling rig, which must be quickly and carefully scheduled to coincide with drilling windows and lease obligations, and is paid for based on the number of days it is in use. Disruption in this process can place oil and gas leases, entire projects, and the ability to develop domestic onshore oil and gas reserves--not to mention substantial capital--at risk. These consequences are at issue in EPA’s interpretation of the scope of the oil and gas exemption under section 402(l)(2), particularly with the impending decrease in the acreage threshold to one acre under the Phase II stormwater regulations.

The permitting process is further complicated by EPA’s interpretation of its “common plan of development” concept. This concept requires projects to be permitted if, taken together, the components will ultimately exceed the permitting acreage threshold. For E&P facilities, this concept makes no sense. E&P facilities are dependent on the success of one well before locating and drilling the next. For the producer, there is no common plan.

In addition, EPA’s existing “common plan” guidance is very confusing and difficult to apply to actual E&P activities. The definition is overly inclusive, in that activities otherwise consistent with the ordinary course of exploration and development of an oil and gas prospect would likely be grouped together by EPA as a “common plan,” causing the (currently applicable) five-acre threshold to be exceeded by many common activities. Under the current guidance, even with the two-year deferral of the one-acre threshold, there is great cause for concern that EPA could conclude that the second or third or fourth well in a field could constitute a common plan and then enforce against a producer for failing to file for a construction permit.

Because of these concerns, IPAA believes that EPA should reconsider its approach to stormwater construction permitting and E&P facilities. Recently, EPA deferred until March 2005 the Phase II deadline for E&P facilities that disturb less than five acres of land area to obtain a stormwater permit. In the meantime, EPA will have an opportunity to consider whether there are alternative approaches that might be consistent with EPA’s statutory authority and that would be consistent with the environmental impacts of construction of these facilities and minimizing the regulatory burden. IPAA believes this action is essential. However, the issue of common plan of development remains unclear in the recently issued Construction General Permit; failure to clarify it could lead to unintended regulation of these small facilities during the deferral period. Moreover, IPAA believes that EPA should revisit its current interpretation of the CWA to address whether it should be requiring E&P facilities of any size to be to obtain construction permits under subsection 402(p),given the clear exclusion in subsection 402(l). Spill Prevention, Control, and Countermeasure Plans

The 1972 CWA required the EPA to develop regulations to address oil spill prevention and response. These SPCC Plans were required to be developed and implemented in 1973.

Following a major oil spill from an Ashland oil terminal, EPA proposed revisions to the SPCC rule on three occasions, in 1991, 1993, and 1997. A new SPCC rule was finalized and became effective August 16, 2002. This new rule raises serious issues for E&P facilities.

An initial issue that causes concern and confusion is what triggers the need to create an SPCC Plan. This decision must be based on whether an operation is a “facility” under the regulation and whether it could result in a release that would reach “navigable waters”. Both elements must be met and both pose significant questions to the producer interpreting them.

Some sources indicate that EPA estimates that there are approximately 144,000 oil and natural gas E&P operations that would require SPCC Plans. However, there are approximately 876,000 producing oil and natural gas wells in the United States. Most producers believe that the SPCC regulation definition of a facility would capture most of these operations. Moreover, about 650,000 of these producing wells are marginal wells that are highly vulnerable to the impact of excessive regulatory costs. Many of these wells could be shutdown if meeting the new SPCC Plan requirements is too costly.

A similar fundamental issue relates to the interpretation of navigable waters. Making a judgment regarding whether an operation – particularly one a remote area – poses a threat to navigable waters has been consistently confounding. Over the past two decades different interpretations of the scope of the term have been complicated by different assessments by various EPA Regional offices. Further confusing the issue is the Supreme Court decision limiting the definition of the term in the Solid Waste Agency of Northern Cook County v United States Army Corps of Engineers (“SWANCC”) case. New guidance has been released regarding the implications of this decision on all federal regulations and an Advanced Notice of Proposed Rulemaking has been published on the issue.

However, this guidance has not yet been systematically applied and the additional regulatory action is designed to produce specific regulations on the definition of wetlands. The outcome of these actions significantly affects the ability of producers to determine whether an SPCC Plan is required for their operation. Additionally, it is essential that all EPA Regional offices consistently apply these ultimate standards. Without some common understanding of the law, producers will be compelled to make judgments regarding the need for SPCC Plans that may be incorrect. They would either risk enforcement actions or incur unnecessary costs. Neither choice is appropriate.

Moving beyond these pivotal issues, a number of other significant issues with the new regulations must be either clarified or addressed.

§ Past interpretations of the SPCC Plan requirements clearly allowed the operator to consider costs in the planning process. In the new regulation, EPA states, “Thus, we do not believe it is appropriate to allow an owner or operator to consider costs or economic impacts in any determination as to whether he can satisfy the secondary containment requirement.” The consequence of this approach could be enormous for marginal wells. The costs of SPCC Plans are estimated to range from around $5,000 to $20,000 with most of this cost associated with secondary containment requirements. Clearly, these costs put the economic viability of marginal wells in jeopardy.

§ One of the principal issues affecting these costs is a requirement in the new regulations for secondary containment at loading operations. A similar issue exists regarding secondary containment related to flow lines.

§ EPA has concluded that produced water operations are not exempted as wastewater treatment. This decision would subject hundreds of thousands of produced water tanks and vessels to secondary containment requirements when they contain only incidental amounts of oil.

§ There is a significant issue regarding the availability of licensed professional engineers to certify new SPCC Plans.

EPA has extended the compliance deadlines in the regulations 18 months. IPAA supports this extension as an opportunity to revisit the key issues raised by the new regulation. It is important to emphasize that the environment is not at increased risk during this extension period. First, the SPCC Plan requirements in existence prior to the new regulations remain in place. Second, the responsibility to report and respond to spills is unaffected.

IPAA believes that there are three broad challenges that must be met. First, there is a compelling need to continue the process of developing an approach that is clearly understood by all domestic oil and natural gas producers – particularly marginal well producers. Second, the process must yield a Plan that can be certified by licensed professional engineers. Third, the Plan must be affordable so that both the environmental objective of SPCC regulation can be met and domestic production is not inappropriately impaired.

IPAA believes that EPA should develop an approach to formulating SPCC Plans to meet the environmental risks of domestic oil and natural gas E&P. Such an approach should be focused on addressing those circumstances that have presented past problems. Such an approach would assure that the limited funds available – particularly for marginal well producers – are spent on areas where past experience has demonstrated a compelling call for action. Conclusion

The CWA generates many regulations to improve water quality in the United States. But, it is essential that the CWA target issues where regulation is truly needed and that those regulations are cost effective. The applications of the stormwater construction permitting requirements and the new SPCC Plan regulations to domestic oil and natural gas E&P facilities do not meet this test. Moreover, they pose a significant risk to the development of new domestic oil and natural gas resources and the continued operation of existing production. In each case, EPA needs to reconsider its actions.

IPAA appreciates the opportunity to submit this testimony.