Oil Pollution Prevention; Spill Prevention, Control, and Countermeasure Rule Requirements

February 25, 2009

EPA Docket Center (EPA/DC)

1200 Pennsylvania Ave., NW.

Washington, DC 20460

Attention:  Docket ID No. EPA-HQ-OPA-2007-0584.

Subject:  Oil Pollution Prevention; Spill Prevention, Control, and Countermeasure Rule Requirements--Amendments, 72 Federal Register 198 (October 15, 2007) – Proposed Rule, (Docket ID No.  EPA-HQ-OPA-2007-0584).

We appreciate the opportunity to comment on the Environmental Protection Agency (EPA) proposal to revise its Spill Prevention, Control, and Countermeasure (SPCC) Plan regulations.  Specifically, we will comment on the need for appropriately realistic compliance dates for the final rule, on the definition of qualified oil production facilities and on the optional approaches for produced water containers.

Before addressing the specific proposals now presented, it is useful to consider the comments made during EPA’s previous proposal to extend the deadline for regulatory compliance in order to develop this package of regulatory alterations.

In our prior comments to Docket ID No. EPA-HQ-OPA-2007-0584, we submitted, in part, the following comments:

During the comment period associated with Docket ID No. EPA-HQ-OPA-2006-0949, we submitted the following comments:

EPA indicates that one area that will be addressed is oil and natural gas exploration and production.  We believe that this additional time would allow an opportunity to address fundamental issues in the current regulations that need to be considered during the extension period.  Recognizing that the current SPCC program requires plans, a key issue that has yet to be addressed is what incremental environmental benefits the 2002 regulations create compared to its costs and potential energy implications.  We have urged EPA throughout the time since the 2002 regulations were unveiled to provide this information; this extension allows time to produce such an analysis. 

The extension will also allow time to address a series of issues that have been raised repeatedly in the past and have not yet been addressed.  One of the first issues that causes concern and confusion is the question of 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 who must interpret them.

For example, some sources have indicated that the Environmental Protection Agency (EPA) estimates that there are approximately 144,000 oil and natural gas upstream operations that would require SPCC Plans.  However, there are approximately 870,000 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 producing wells.  Moreover, about 635,000 of these producing wells are stripper 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.  For example, a Department of Energy analysis, “Assessment of the Potential Costs and Energy Impacts of Spill Prevention, Control, and Countermeasure Requirements for U.S. Oil and Natural Gas Production”, concluded that – depending on the price of crude oil and natural gas – compliance with the 2002 SPCC regulations could result in the loss of between 2 and 9 percent of American crude oil production.

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 in this rule 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, 531 U.S. 159 (2001), in the Rapanos v. United States case, 376 F.3d 629 (2004) and in other cases that have been subsequently argued.  This issue remains a continuing problem in interpreting the requirement to develop an SPCC Plan and needs a consistent resolution.  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.  Following are brief reviews of these issues.

Cost Consideration – Past interpretations of the SPCC Plan requirements clearly allowed the operator to consider costs in determining the practicability or impracticability of meeting particular requirements of 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 when applied to the marginal wells in this country.  To put this in perspective, a marginal oil well is defined as one producing 15 barrels per day or less (a stripper oil well produces 10 barrels per day or less).  Individually, marginal oil wells average around 2.2 barrels per day, but collectively they produce about 20 percent of domestic oil and are about 80 percent of the number of wells.  The costs of SPCC Plans are estimated to range from lows of around $5,000 to as high as $20,000 with most of this cost associated with secondary containment requirements.  Clearly, these costs put the economic viability of marginal wells in jeopardy. 

Tiering of Requirements – Building on the Small Business Administration (SBA) suggestion that SPCC planning requirement differ based on the size of an operation, industry has identified approaches that would specifically limit the requirements for exploration and production (E&P) operations.  In particular, it would lessen the burden for marginal wells which are the most susceptible to cost increases.  Among the issues that need to be addressed in this arena is the tier where professional engineer certification is necessary.

Secondary Containment of Produced Water – Produced water storage tanks typically contain small volumes of oil that do not represent a significant source of oil storage.  Water produced should be exempt from the SPCC regulations because there is a very low risk of a significant discharge of oil to Waters of the U.S.  Additionally, by expanding the scope of the SPCC program to cover produced water, it has the effect of capturing hundreds of thousands of natural gas operations producing natural gas liquids that have previously fallen below the threshold for planning.

Secondary Containment of Process Equipment – The containment of produced fluids around oil and gas fired process vessels, such as heater treaters, can present a serious safety hazard and it is impractical for pressurized vessels.  In addition, the rule treats process/operating equipment inconsistently for the different industrial sectors.  At non‑exploration and production sites, it is excluded from the definition of bulk storage containers, whereas at E&P facilities, this type of equipment is considered bulk storage containers and subject to secondary containment requirements. The purpose of oil and gas process equipment such as heater treaters is to process oil/water mixtures.  These vessels are flow-through process vessels rather than containment vessels.

Secondary Containment of Flow and Gathering Lines – Requirements for containment around flow lines and gathering lines are excessive and impractical and will cause significant and unnecessary disturbance of the surrounding lands.  Installing secondary containment (including double-walled piping) or retrofitting all existing flow lines and gathering lines is cost prohibitive.  A more reasonable approach would be to allow operators to implement flexible and responsible, risk-based flow line inspection and maintenance programs to prevent spills.  Flow lines are not and should not be considered oil storage containers.

Definition of Facility – Although the Consent Decree agreement with the American Petroleum Institute attempted to clarify the distinction between the definition of “facility” and of “production facility” in the context of Facility Response Plans (FRPs), it leaves open the impact of these definitions on the planning process.  In particular, changes in the definition of production facility from earlier regulatory proposals deleting the term “may” from the definition raises questions about the authority of the operator or the professional engineer to create discrete, manageable plans for production operations within the larger production field.

Timing of Implementation – Because the oil exploration and production industry does not know whether its development efforts will succeed, it needs a structure that allows for SPCC Plans to be prepared within 6 months after operations begin and to be implemented within 6 months after they are prepared.

Regulations vs. Guidance – A recurring problem with the SPCC program has been inconsistent interpretation between EPA’s headquarters and its regions.  Consequently, EPA needs to establish its requirements as regulations that can be consistently interpreted and applied equally throughout the country.  Guidance documents fail to provide certainty; rather, they create the opportunity for different interpretations of the same requirements in different EPA offices.  But, Guidance documents preclude formal challenges and therefore create the opportunity for arbitrary and unsubstantiated decisions by EPA inspectors.  The SPCC programs needs reliability that can only be achieved in regulations.

Conclusion

We believe 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 or that an appropriate alternative is developed.  In previous submissions to the EPA, the oil and natural gas exploration and production industry has proposed alternative approaches based on concepts presented by the Small Business Administration.  These have not been embraced by EPA and need further attention.  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. 

Consequently, we support EPA’s proposal to extend the existing compliance dates and we urge EPA to begin the process of developing such new regulations as are necessary to address the changes that are needed to revise the SPCC Plan requirements.  In particular, we are concerned that EPA has not justified the current regulatory changes.  We have not seen indications that there are systemic problems with the current SPCC Plan requirements as they apply to oil and natural gas exploration and production.  Similarly, we have not seen an analysis of the energy implications of the 2002 regulations. 

Many of the issues raised during these January 2007 comments have been addressed in the current proposal but some have not.

In particular, we remain frustrated that the benefits compared to the costs of these regulations have yet to be thoroughly analyzed despite the issue being raised since 2002.  This analysis is important because of the context of SPCC planning requirements.  If oil is spilled at a production facility, the operator is responsible for its clean up.  SPCC plans do not protect the operator from this responsibility.  Therefore, effective SPCC plans benefit the operator by procedures to enable a timely response to a spill.  At issue is when the mandates for specific actions and equipment in the SPCC planning process become cost ineffective compared to their environmental benefits.  EPA has never conducted a thorough assessment.  Apparently, the closest it has come is a report in the Docket entitled, “Considerations for the Regulation of Onshore Oil Exploration and Production Facilities Under the Spill Prevention, Control, and Countermeasure Regulation (40 CFR Part 112)” prepared by Abt Associates Inc. (The Abt Report).

While it is not a thorough – or peer reviewed – document, The Abt Report presents issues that should be addressed.  Clearly, it is crafted as a document to justify the actions proposed in the current regulatory action.  However, it raises as many questions as it may attempt to answer.

For example, we have regularly raised the question of how many facilities the new regulations would affect.  EPA has regularly used an assumption that the universe of production facilities affected by the regulations is about 144,000.  The Abt Report states that EPA has now estimated a universe of about 166,000 oil production facilities based on an assumption of four wells per facility.  This would then translate to 664,000 wells.  However, IPAA’s United States Petroleum Statistics reports that in 2006 there were approximately 914,000 producing oil and natural gas wells in the United States, suggesting that the EPA number is about 72 percent of the United States total.  On the other hand, nothing in The Abt Report suggests whether these assumptions include an assessment of whether these facilities also pose a risk to navigable waters – important because a navigable waters link is required before SPCC Plans must be developed.  These differences can be significant in determining the potential cost of compliance with new regulations.  Against this number of facilities, The Abt Report also reviews the number of reported incidents and volume of spills.  Using data from the National Reporting Center (NRC), The Abt Report concludes that the number of incidents from 2000 through 2005 “…remained relatively constant during the six-year period, with an average of 501 incidents per year.”  Similarly, the average release was approximately 548,000 gallons per year. 

How do these incidents relate to the scope oil that the industry manages yearly?  Using EPA’s assessment of the number of onshore facilities of 166,000, 500 releases represent 0.30 percent of the operations.  From a volumetric standpoint, 548,000 gallons is about 13,050 barrels.  Based on information in “IPAA Oil & Gas Producing Industry in Your State” and the National Ocean Economics Program, onshore production of oil and natural gas liquids in 2004 totaled about 2,001,000,000 barrels.  The oil spill volumetric loss was approximately 0.00065 percent of the total volume produced.

The Abt Report further studied some specific state analyses.  One of these was the Fisher and Sublette study of Oklahoma, a report that was released several years ago.  The Fisher and Sublette raised several questions at that time that are no clearer in The Abt Report.  They are outlined below:

·        Without going into the database used for the Fisher and Sublette study, it is difficult to assess whether the underlying information is limited to E&P facilities

·        One tank release from overfilling is shown as 89,000 barrels.  That size vessel seems too large for an E&P operation.  In fact, based on conversations with the Oklahoma agency responsible for oil facility regulation, the spill was attributable to operations at Cushing oil storage facilities – facilities that are world scale oil storage operations taking crude oil from throughout the midcontinent for shipment to refineries.

·        There are a number of line leaks but it is unclear whether these are E&P lines or gathering lines or intrastate pipelines.

·        Some of the data clearly skew the results

·        The 89,000 barrel tank spill shifts the mean upward and accounts for 70 percent of the total tank spill volume.  It would clearly improve the study to correct the error associated with this spill and determine whether there were some similar large spills that shift the data and the nature of those spills.

·        There is a similar large saltwater spill that affects that data.

·        In the context of SPCC Plans, the study does not address whether Plans existed and were effective.  Spills occur whether there are SPCC Plans or not.

·        SPCC Plans are required under the Clean Water Act if there is a risk to contaminate navigable waters.

·        The analysis shows that there were releases to surface water but more releases were to other receptors – this raises questions about whether SPCC Plans would have been required for these sites.  Interestingly, the 89,000 barrel oil spill is not shown as affecting any of the receptors.

Ultimately, these state analyses show roughly the same information as the national material:  spills occur at a small number of facilities and represent a small amount of the volume of oil produced and managed at E&P operations.

Weighed against these spill assessments are the costs of new requirements.  The Department of Energy (DOE) analysis, “Assessment of the Potential Costs and Energy Impacts of Spill Prevention, Control, and Countermeasure Requirements for U.S. Oil and Natural Gas Production”, concluded that – depending on the price of crude oil and natural gas – compliance with the 2002 SPCC regulations could result in the loss of between 2 and 9 percent of American crude oil production.  Current oil prices exceed those of the DOE analysis, but it is essential to recognize that the proposed SPCC regulations do not change with commodity prices.  Consequently, while the cost of the regulations may be more absorbable under current prices, the future consequences of the costs cannot be ignored.  The failure of this regulatory process to openly and straightforwardly develop a thorough and clear determination of the environmental benefits that are created by these new requirements compared to their costs in the context of the legal responsibilities for spill damage remains a major frustration and leads in our view to unnecessary results.

The remainder of these comments will focus on specific proposals, principally those in Section V.L.

1.      Definition of Production Facility

We are concerned that several unintended consequences may result from the definition proposal that need to be clarified.  For example, the preamble suggests that the use of “one-plan” could invoke a Facility Response Plan (FRP) designation.  In order to facilitate easy use for operators because of the similarity of E&P facilities, companies use a plan template that works for all operations but includes specifics where appropriate.  This approach is extremely valuable to producers because they provide a straightforward method to improve responses if spills occur.  Denial of these types of approaches will not improve the ability to respond but would be necessary to avoid an FRP designation and the additional requirements it brings.  Similarly, the reference to “…property, parcels, leases….” in the proposed definition cause uncertainty.  For example, leases regularly extend beyond the size of the facility.

2.      SPCC Plan Preparation and Implementation

We share the view that additional time is needed to prepare and implement SPCC Plans after the production facility becomes operational.  Oil and natural gas E&P facilities differ from most operations because they cannot be completely defined until the specifics of the production capability at an operation is analyzed.  Once this information is available, it is used to develop the SPCC Plan.  Consequently, we support the delay in requiring the preparation and implementation of a Plan and believe that six months is the minimum additional time needed.

3.      Flowlines and Intra-facility Gathering Lines

We agree with the concerns expressed by other submitters that this proposal blurs the jurisdictional lines that have been long established between EPA and the Department of Transportation (DOT).  We support proposed changes that would clarify this distinction in the final rules.

We agree that sized secondary containment for flowlines is impracticable and commend EPA for providing an alternative option.  However, we are concerned that both the language in the proposed regulations and the material contained in the Guidance Document will be construed to compel monitoring and maintenance programs that are excessive.  Other submitters have recommended that the existing language of Section 112.9(3) “Have a program of flowline maintenance to prevent discharges from each flowline.” be maintained.  This would allow the plan designer, in consultation with the owner/operator, to design a flowline maintenance program utilizing good engineering judgment appropriate to the site-specific conditions of the facility.  We support this approach.

Along with others we are concerned that the use of the phrase, “Promptly remove any accumulations of oil discharges associated with flowlines….” could limit the response options.  Using a phrase like “initiate appropriate response actions to contain and stabilize accumulations of oil discharges associated with flowlines….” would imply the same sense of action without limiting the type of response.

4.      Flow-Through Process Vessels

We concur with EPA’s approach to move from sized secondary containment of flow‑through process vessels to an approach utilizing general secondary containment and an inspection and/or testing program.  We, however, are concerned about the potential for the language and Guidance Document to be construed to compel a program that is excessive.  Most of the facilities that will be impacted by these regulations will be marginal well facilities.  Regular management of these facilities is conducted by lease operators and contract pumpers.  Typically, these parties inspect the production facilities as they check them to determine that they are operating properly.  At these times, they make necessary repairs or adjustments – and address leaks or possible spills.  We believe that these current management procedures meet the proposed EPA requirements to provide for “…periodic inspection and/or testing of the flow-through process vessels and associated appurtenances on a regular schedule for leaks, corrosion, or other conditions that could lead to a discharge….”

5.      Small Oil Production Facilities

EPA has presented several proposed options regarding the regulation of small oil production facilities under these rules.  Generally, there are two issues at stake:  the definition of a small facility and the scope of the provision.

On the first of these, the fundamental choice is between a new definition of a small oil production facility created by EPA (or some modification of it) and the use of the definition of marginal wells under the federal tax code.  We support the use of the tax code definition for several reasons.  First, all producers of marginal wells know whether they qualify under the tax code definition; no new interpretation is required.  Second, the EPA proposed definition is arbitrary.  It represents a specific mix of operations that may or may not be realistic or widely applicable.  Third, the EPA definition remains linked to storage capacity at the facility.  As we have said several times in earlier comments, the storage capacity at marginal wells is not sized based on current production levels.  These facilities are designed when the wells are producing at higher rates.  As the production declines and the wells become marginal, the same equipment is used because it remains functional and it is too expensive to replace as the well generates lower income.

The second – and more compelling – element of the proposal is the scope of regulatory burden.  Here, the choice is significant.  Option One relaxes the regulatory burden by allowing self-certification and the use of an SPCC Plan template.  Option Two limits the regulatory burden to crude oil and condensate tanks.  The potential benefit of Option One may be illusory.  New information suggests that several states are adopting provisions requiring that all SPCC Plans must have professional engineer certification thereby negating much of the benefit of Option One.  Option Two presents a real opportunity for regulatory relief.  At issue then is whether such relief would pose an unacceptable environmental risk.  As we stated earlier, EPA has never conducted a comprehensive environmental analysis of the risks associated with these proposed regulations and whether they significantly change from the current regulatory program to this proposed one.  However, as we described earlier, the current experience with oil spills related to oil and natural gas E&P facilities shows that releases reported to the NRC are extremely low given the large number of facilities and the large volume of oil that is handled.  Clearly, at marginal well operations, the largest volumes of oil – and, therefore, the largest risk to the environment – are stored in the crude oil and condensate tanks.  Consequently, we believe the benefits of the regulatory reduction for these marginal wells from Option Two outweigh any consequences and the proposal does not pose a significant increase in environmental risk.

6.      Produced Water Storage Containers

As EPA is well aware, we have never agreed with the interpretation of the SPCC program – first surfaced in 2002 – that SPCC Plans should cover produced water storage.  This is a significant alteration of interpretation in part because one consequence is expansion of SPCC program to potentially hundreds of thousands of natural gas production operations that produce some liquid condensate and produced water.  The condensate volume would not trigger the threshold volume for oil but adding produced water to it brings these facilities into the requirements.

This proposal presents three options for addressing produced water under the new regulations.  One of these options would exempt produced water treatment facilities from the scope of the program.  We endorse this option.

EPA has raised questions regarding the efficiency of oil-water separation operations and the potential for oil to be entrained into the produced water storage tanks.  These issues seem to be largely identified in The Abt Report.  Many of the statements in The Abt Report are the result of anecdotal observations and hypothetical conversations with engineering company representatives.  They cannot be easily rebutted because of their imprecise nature.  In general, the following comments address the key points.  Oil-water separation does depend on the nature of the oil-water mixture.  However, the most dominant factor in the separation is residence time.  The longer the mixture is given to separate, the more oil will be released from the water.  The oil-water separation equipment is initially designed to separate a mixture that is more oil than water.  As the wells age and production declines, secondary recovery using water is frequently applied.  This increases the water content in the mixture.  By the end of a well’s life, it may be producing one barrel of oil for every ten barrel of production.  In these circumstances the mixture subject to oil-water separation would be about 10 percent oil; therefore, the produced water would be well below this percentage.  Equally significant, the purpose of these wells is the production of oil.  Oil left in the produced water is lost income.  Consequently, the economic driving force for producers is managing their operations to minimize the amount of oil in their produced water.  Finally, returning to our assessment of The Abt Report, it demonstrated that – given the magnitude of production and the number of operating wells – spill management of oil and natural gas E&P operations has been effective under the existing SPCC Plan requirements and there is no reason to believe it will not continue to be effective considering the increased value of the oil.

We include these materials because they reflect a number of issues that continue to be unsettled. 

In reviewing the December 5, 2008, Federal Register explanation of EPA’s decisions on the final rule, there is a recurring theme of assumptions that are used to justify EPA’s conclusions.  Since 2002, when EPA first published the revised SPCC rules, the oil and natural gas production industry has sought to have EPA identify the environmental risks that these new requirements are intended to address.  It has sought to participate in accurate assessments of production operations, to identify real risks and to develop regulatory solutions to address those problems.  However, over the seven year period that this regulatory development has been modified since then, no such effort has been forthcoming.  Rather, EPA has relied on the Abt Report as its assessment to justify these new requirements.  As shown above, the Abt Report is at best incomplete and clearly includes information that does not reflect oil and natural gas production operations.

Similarly, the implications of EPA’s position on produced water influences these regulations dramatically – not only with regard to the specific treatment of produced water storage.  Prior to 2002, produced water was treated by oil and natural gas production operators – and EPA – as waste water was treated by all others.  EPA drew the distinction between production waste water and other industries’ waste water in the 2002 regulation.  This distinction drags a large number of operations – particularly natural gas production facilities – that would not meet the oil thresholds subjected to the SPCC regulations because of the addition of produced water to their volume thresholds.  Similarly, in the discussion of qualified production facilities, produced water volumes change the scope of its impact.  The ultimate consequence of EPA’s decision to expand the scope of the SPCC program directly relates to the ultimate compliance costs.  The hardest burden of those costs will be on the marginal well operations in the United States.  These facilities account for approximately 20 percent of American oil production and 12 percent of American natural gas production.  It is from this perspective that we provide our specific comments on the current proposals.

Compliance Date

Compliance with the requirements of these new regulations will require both education and capital expenditures.  The regulations introduce a number of compliance paths with different requirements.  The current outcome of the definition of qualified production facilities means that these regulations will impose significant new requirements on smaller producers.  Guidance on compliance must be developed and communicated to the operators of the 933,000 oil and natural gas wells in the United States.  Consequently, all of these operations will need to create or revise their SPCC Plans.  These actions will require both physical modifications of facilities and certification by professional engineers.  The certification process will require the professional engineers to define and design additional physical equipment.  These will need to be constructed before final certification.  Taken together, these mandates will overstress the available pool of professional engineers and construction firms to meet the arbitrary compliance date.  Moreover, in a time of reduced oil and natural gas prices, these costs could result in well shutdowns and plugging for no environmental benefit.  To meet these tasks, we recommend a general compliance date 24 months following the final promulgation of the rules.  Additionally, the compliance date for the December 2008 rulemaking provided for a later compliance date of qualified production facilities – November 2013.  We believe a similar 60 month compliance date for these facilities should be included in the final rule.

EPA appears to have recognized this potential adverse outcome when it proposed a later compliance date for qualified production facilities in the 2008 Notice.  Notably, EPA argues in the Notice that:

This extension will also provide the Agency with sufficient time to initiate work with relevant trade associations, the Interstate Oil and Gas Compact Commission (IOGCC) and the Department of Energy (DOE) on outreach and compliance assistance tools to help qualified oil production facilities develop their self-certified Plans. Finally, given: (1) The large number of marginal or stripper wells in the U.S.; (2) that they contribute a significant portion of the country’s oil production; and (3) EPA’s understanding of the production process, the particular aboveground oil storage container capacities, and the nature of the fluids handled and operations conducted at certain small oil production facilities, the Agency is proposing additional time for these facilities to come into compliance.

Produced Water

We continue to believe that the soundest approach to addressing produced water remains its exclusion from the scope of the SPCC regulations.  As we described above from our earlier comments, the apprehensions presented by EPA in its characterization of the problem run counter to the interests of producers.  Oil production is the purpose of an oil well; losing oil in produced water is lost revenue.  Losing oil in a produced water spill creates a liability to the producer for clean up such that not only is revenue lost but additional costs are created.

However, rather than take such a direct approach, EPA created a three option process that will likely impose unnecessary costs on production facility.  While EPA creates an apparent option to exempt produced water containers, it is unrealistic.  The exemption occurs only if a professional engineer certifies that a complete discharge from the container would not be harmful under a test that would fail if oil sheen were present.  Oil sheen can result at low concentrations of oil in water.  Professional engineers are unlikely to certify any produced water container rendering the option nonexistent.  The second option would involve general secondary containment as long as certain operations are certified and unless there is a spill at the facility.  The third option requires full compliance with the regulation.  Both of the latter options require capital expenditures that can force wells to be shutdown – particularly for marginal properties.  We do not believe EPA has shown these expenditures are justified by tangible environmental benefits.

Qualified Production Facilities

We recommend that EPA reconsider using a definition of marginal wells to define qualified production facilities.  As we have previously stated the marginal well definition used for IRS tax purposes is well understood and can be easily linked to production operations.  EPA rejected this approach on the following basis:

However, EPA disagrees with commenters who argued that the IRS tax code definition of 15 barrels or less of oil per day should be used in defining flow rate. Specifically, the IRS definition of 15 barrels of oil or less per day equivalent is calculated by dividing the average daily production of domestic crude oil and domestic natural gas from producing wells on such property for such calendar year by the number of such wells. Thus, under this approach, a facility will contain wells with marginal production, such as 15 barrels of oil per day, but also will likely contain wells that produce much greater quantities of oil, because the IRS definition calculates the average daily production of oil over all producing wells, as opposed to the amount of oil that flows from any individual well. EPA believes that using such a definition defeats the purpose of identifying a qualified facility, which is to allow those small facilities that have relatively simple operations to self-certify their SPCC Plans.

EPA’s concerns are unjustified.  While it is possible that some wells at a facility might exceed 15 barrels of oil per day, the average marginal well produces 2.2 barrels of oil per day.  Consequently, it is unlikely that there are several 15 barrels per day wells surrounded by a vast number of small wells.  Our view of the purpose of the qualified production facility was to reduce regulatory burden and increase cost effectiveness.  EPA’s approach to create an artificial definition fails to meet this test.  EPA should revisit the definition.

More significantly, EPA’s regulatory relief is too narrow.  Creating the definition of a qualified production facility solely for the purpose of self-certification saves the cost of professional engineer certification.  But, it leaves the larger costs of construction of new containment and other plan requirements untouched.  These costs will result in the termination of the very marginal wells that the regulatory relief is intended to benefit.  EPA needs to revisit the scope of its regulatory requirements on qualified production facilities.

Conclusion

We appreciate the opportunity to provide these comments.  The provisions that we are addressing today have changed considerably and, on the whole, positively since the 2002 rulemaking.  However, these remaining issues should be addressed to assure the benefits of American oil and natural gas production for national energy security.  If there are questions regarding these comments or if additional information is required, please contact Edward Cross at the Kansas Independent Oil & Gas Association (KIOGA) 785-232-7772.