USEPA

U.S. EPA and U.S. ACE Propose New Definition of “Waters of the United States”

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The United States Environmental Protection Agency (U.S. EPA) and United States Army Corps of Engineers (U.S. ACE) proposed a new definition of “Waters of the United States” (WOTUS) on December 11, 2018. The significance of this proposal is that WOTUS are the waters that these agencies regulate under Section 404 of the Clean Water Act (CWA).

The proposal defines WOTUS as including Traditional Navigable Waters (TNW, which are primarily waters upon which interstate commerce could be conducted), intermittent and perennial streams, ditches, channels that are relocated tributaries, impounded streams, wetlands adjacent to streams, and wetlands that have a direct connection to TNW.

The proposal further defines tributaries as excluding ephemeral streams, which are those that only flow during heavy rainfall events. This is likely the most significant part of the rule that will be challenged and is a rollback of the current 2015 federal definition of WOTUS (2015 Rule; see below) and the pre-2015 Significant Nexus standards.

The proposal also seeks to replace the Significant Nexus test with clear, defined categories, making WOTUS easier to determine and not subject to continual legal interpretations. Significant Nexus, a relatively defined and traceable pathway to TNW, had been defined by a United States Supreme Court ruling in 2006 called the Rapanos Ruling. That ruling eliminated federal jurisdiction to regulate isolated wetlands and channels under the CWA. Several clarifications of the Rapanos Rule were later issued, further complicating the definition and interpretation of a Significant Nexus.

The proposal is currently in a 60-day public comment period in which any member of the public can submit a comment and the agencies will consider them. According to the U.S. EPA, the proposal, if finalized, “would apply nationwide, replacing the patchwork framework for Clean Water Act jurisdiction that has resulted from litigation challenging the 2015 Rule. The proposal would also re-balance the relationship between the federal government, states, and tribes in managing land and water resources.”

The current federal definition of WOTUS, enacted August 28, 2015 by the Obama Administration (2015 Rule), essentially includes all channels, wetlands, and ponds that are within 100 feet of a “tributary” to a TNW, or within 1,500 feet of TNW water itself. “Tributaries” are broadly defined and often include discontinuous channels, drainage swales, and any wetland or water body located in a 100-year flood plain. This definition often extends jurisdiction over excavated ditches and other areas that were considered uplands prior to the 2015 Rule. WOTUS could include areas that were determined to contribute to downstream flow, retention, and even nutrient recycling, among other inclusive criteria. Prior to the 2015 Rule, these areas were not regulated unless it could be demonstrated that there was a Significant Nexus.

The 2015 Rule has been heavily litigated, with varying rulings issued in several states and on different legal grounds. On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the 2015 Rule. Several other court cases moved forward in the meantime, making the rule effective in some states and not in others at varying times. Several rulings were issued and overturned in several courts and states. As of September 18, 2018, the latest ruling was that the 2015 Rule only applied in 22 states throughout the U.S., while the prior definitions applied in the remaining 28 states. This unpredictability has added to the already difficult regulatory hurdles faced by landowners, businesses, and the regulated public. Acquisition due diligence has become increasingly difficult, as it is almost impossible to determine what would be regulated; what the permitting path, if any, may be available; and how long the issue would take to resolve.

These hurdles, combined with other laws such as the Endangered Species Act,1 create significant economic hardships for landowners, farmers, real estate developers, and other businesses and industries. Some of these hardships are halting projects or rendering previously developable or farmable land unusable. As a result, the development and agricultural communities argued that the 2015 Rule was an overreach by the U.S. EPA and U.S. ACE. In light of this regulatory landscape, most industries involved in real estate development agree that a formal definition of WOTUS is needed to create predictability in due diligence. Furthermore, such a definition could help owners or consultants identify WOTUS without government verification and alleviate fear of differing WOTUS opinions by the U.S. ACE after a project has commenced, leading to enforcement actions.

Prior to the 2015 Rule, WOTUS were generally defined in the U.S. ACE regulations adopted under the CWA (33 Code of Federal Regulations Part 328.3). Several guidance documents such as the 1987 U.S. ACE Wetland Delineation Manual, Natural Resources Conservation Service Technical Notes, state-issued rainwater and storm water manuals, and Federal Regulatory Guidance Letters were used to further identify and determine the limits of WOTUS. While these resources shed light on how to identify WOTUS, they did not technically define what WOTUS was or what was regulated and what was not. As a result, most developers sought U.S. ACE verifications of WOTUS opinions, typically with the help of consultants. These verifications are expensive and often take months to obtain. In many parts of the U.S., these verifications can only be conducted during the growing season—the time when plants are not dormant. Combined with clearing restrictions, survey windows, and local permitting, this made legally timing construction activities a difficult proposition, delaying or halting projects and increasing carrying costs.

After the 60-day comment period ends, the most optimistic predictions forecast that the agencies will adopt the new proposal in September of 2019. If history is any indicator, however, the rule will be mired in legal challenges and politics. In the meantime, the 2015 Rule applies in 22 states and the prior standard applies in the 28 remaining states. Landowners and developers should exercise caution when acquiring property and add extra time for due diligence to avoid potentially catastrophic economic risk.

If you have questions about WOTUS or relevant regulatory updates, please contact Bill Acton (bacton@cecinc.com) or at 614-310-1041.


1 The Endangered Species Act can delay land development projects by requiring season-specific surveys for protected species and preparation and agency approval of habitat conservation plans, and by imposing seasonal restrictions on land clearing activities.

Modifications to the Phase I ESA Process – Part 2

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A December 30, 2013, EPA final rule (78 FR 31112) amended 40 CFR Part 312 (All Appropriate Inquiries [AAI]) to reference ASTM International’s E1527-13 Standard Practice for Environmental Site Assessments:  Phase I Environmental Site Assessment (ESA) Process.  The AAI amendment was effective December 30, 2013.

Per the final rule, EPA recognizes the newly issued ASTM E1527-13 as compliant with AAI.  Therefore, “persons conducting all appropriate inquiries may use the procedures included in the standard to comply with the All Appropriate Inquiries Rule.”

ASTM published the revised E1527 standard on November 1, 2013. ASTM E1527-13 reflects the consensus of its technical committee, and as such is the industry-accepted standard of care for conducting Phase I ESAs.

EPA stated that “the ASTM E1527-13 standard is similar to the ASTM E1527-05 standard in format, process, and areas of coverage.” In general, the revisions included:

  •  New and revised terminology related to Recognized Environmental Conditions (RECs)
  • Clarification related to the applicability of the vapor pathway to ASTM E1527
  • Language regarding file reviews including agency file reviews and judicial records

EPA’s amendment offers the option of using ASTM E1527-13 to conduct all appropriate inquiries; however, the December 30, 2013 rule does not require use of ASTM E1527-13. Although not required, EPA’s final rule included the following:

  •  “ASTM E1527-13 provides an improved process for parties who wish to undertake AAI.”
  • The “changes enhance the usefulness of the standard” in identifying potential and threatened releases
  • “ASTM E1527-13 improves upon the previous standard and reflects the evolving best practices and level of rigor that will afford prospective property owners necessary and essential information when making property transaction decisions”
  • “EPA views these enhancements and clarifications to the ASTM standard as valuable improvements and strongly encourages prospective purchasers of real property to use the updated ASTM E1527-13 standard”
  • “EPA recommends that environmental professionals and prospective purchasers use the ASTM E1527-13 standard.”

Additionally, EPA also announced its intent to publish a proposed rule, in the near future, that will propose removing the previous reference to the 2005 standard from AAI; thus supplanting the 2005 standard with the 2013 standard.

If you have any questions about ASTM E1527-13 and how it may impact an upcoming project or Phase I ESAs in general, please contact Jennifer A. Ewing, P.G., (jewing@cecinc.com) at 800-365-2324.

2011 EPCRA Tier II Report

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The Emergency Planning and Community Right-to-Know Act (EPCRA) established the requirements for Federal, state and local governments, Indian Tribes, and industry regarding reporting on hazardous and toxic chemicals.    EPCRA was passed in response to concerns regarding environmental and safety hazards posed by the storage and handling of toxic chemicals.  These concerns were triggered by the disaster in Bhopal, India caused by the accidental release of methyl isocyanate.  Requirements for the preparation and submittal of Tier II Reports were established more than 20 years ago in response to these types of chemical release accidents.  Despite the time since the passage of these regulations, we have seen that some facilities are not submitting the Tier II reports in accordance with the deadline, and in some cases are simply failing to submit the reports.

Facilities covered by EPCRA requirements must submit an Emergency and Hazardous Chemical Inventory Form to the Local Emergency Planning Committee (LEPC), the State Emergency Response Commission (SERC), and the local fire department annually. Facilities provide either a Tier I or Tier II Form although most states require the Tier II Form.  Some states and counties have requirements in addition to the Federal Tier II requirements.

The EPCRA Tier II Form submittal is due on March 1, 2012.  The Tier II Form is required for chemicals that are stored at your facility above specific weight thresholds that are not exempted under the EPCRA regulations.  The weight threshold varies for extremely hazardous substances (EHS) and is set at 10,000 pounds for other chemicals stored at your facility.

 Tier II Forms must report the required information for each hazardous chemical present at your facility in quantities equal to or greater than established threshold amounts (discussed below), unless the chemicals are excluded.  Hazardous chemicals are any substance for which your facility must maintain a Material Safety Data Sheet (MSDS) under OSHA’s Hazard Communication Standard (described at 29 CFR 1910.1200).

 Section 311(e) of EPCRA excludes a number of substances.  The OSHA regulations at Section 1910.1200(b) also stipulates various exemptions from the requirement for maintaining an MSDS for certain chemicals or materials. Minimum thresholds have been established for Tier II reporting under EPCRA Section 312.  These thresholds are as follows:

  • For Extremely Hazardous Substances (EHSs) – the reporting threshold is 500 pounds or the Threshold Planning Quantity (TPQ), whichever is lower.  The current list of EHS chemicals and their TPQs is maintained at 40 CFR Part 355.
  • For gasoline (all grades combined) at a retail gas station, the threshold level is 75,000 gallons, if the tank(s) was stored entirely underground and was in compliance at all times during the preceding calendar year with all applicable Underground Storage Tank (UST) requirements.
  • For diesel fuel (all grades combined) at a retail gas station, the threshold level is 100,000 gallons, if the tank(s) was stored entirely underground and the tank(s) was in compliance at all times during the preceding calendar year with all applicable UST requirements.
  • For all other hazardous chemicals for which facilities are required to have or prepare an MSDS, the minimum reporting threshold is 10,000 pounds.

Your facility needs to report hazardous chemicals that were present at your facility at any time during the previous calendar year at levels that equal or exceed these thresholds.  The report covers the 2011 calendar year, beginning January 1 and ending December 31. For each chemical that your facility has listed, identify all the physical and health hazard boxes that apply.  These hazard categories are defined in 40 CFR 370.2.  The two health hazard categories and three physical hazard categories are a consolidation of the hazard categories defined in the OSHA Hazard Communication Standard, 29 CFR 1910.1200.

 For each chemical that is reported, the Tier II form asks for specific information such as the maximum amount stored onsite, average daily amount stored onsite, number of days present onsite, and storage codes and storage location information (for non-confidential chemicals).  You may elect to withhold location information on a specific chemical from disclosure to the public.  The Tier II instructions provide details for submittal of confidential information. The owner or operator or the officially designated representative of the owner or operator must certify that all information included in the Tier II submission is true, accurate, and complete.  An original signature is required on the submission.

 To obtain Tier II reporting procedures and requirements for your state, please click on the state where your facility is located on EPA’s Tier II Chemical Inventory Reports page.

 The completed Tier II form(s) must be submitted to each of the following organizations:  SERC, LEPC, and the fire department with jurisdiction over your facility.  If you have any questions about EPCRA Tier II reporting requirements and whether your facility may be subject to these regulations, please contact Paul Tomiczek III, REM, P.E. at ptomiczek3@cecinc.com or 800-365-2324. More information on EPCRA Tier II Reporting obligations and instructions for completing the Tier II report are provided at http://www.epa.gov/oem/docs/chem/t2-instr.pdf.

Petroleum and Natural Gas Systems Greenhouse Gas Reporting Requirements

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U.S. EPA continues to roll out new subparts and revisions to the Greenhouse Gas (GHG) Reporting Rule (40 CFR 98).  This time we take a look at Subpart W – Petroleum and Natural Gas Systems which was published in the November 30, 2010 Federal Register.  GHG emissions from this industry are generated by combustion (e.g., heaters, engines, furnaces, etc.), fugitive equipment leaks, and process vents.

As with the other 40 CFR 98 subparts, facilities that emit 25,000 metric tons (mt) or more of carbon dioxide equivalents (CO2e) per year must report.  However, the definition of a facility is slightly more complicated here than for other subparts.

First, there are eight segments of the petroleum and natural gas industry that need to be considered.  Each industry segment is defined in the rule (see §98.230) and more detailed descriptions can be found in the 144-page Background Technical Support Document.  The eight industry segments are:

  1. Offshore petroleum and natural gas production;
  2. Onshore petroleum and natural gas production;
  3. Natural gas processing plants;
  4. Natural gas transmission compression;
  5. Underground natural gas storage;
  6. Liquefied natural gas (LNG) storage;
  7. LNG import and export equipment; and
  8. Natural gas distribution.

The next step in defining a facility under Subpart W is to consider the 21 categories of emission sources that have been identified within the eight industry segments.  For example, the onshore petroleum and natural gas production facility (Segment 2) includes 19 different types of emission sources that need to be inventoried to determine if the annual 25,000 mt CO2e applicability threshold is exceeded (e.g., dehydrator vents, flare stacks, and well testing vents).

For six of the industry segments, the facility definition stops there.  One simply accounts for all of the sources located on contiguous property or under common ownership/control and for which calculation approaches have been provided in the rule.  Two of the industry segments require one more step to define the facility.

For the Onshore Petroleum and Natural Gas Production industry segment, the rule defines a facility as all of the equipment on or associated with a well pad that is under common control or ownership and that is located within a single hydrocarbon basin, as defined by the American Association of Petroleum Geologists Geologic Provinces Code Map.  (This 1991 publication is not provided by EPA but can be obtained from AAPG here.   As one might imagine, geologic provinces cover large areas (e.g., most of Pennsylvania as well as parts of New York, West Virginia, and five other southern states is covered by Code 160A – Appalachian Basin Eastern Overthrust Area).   This means that operations at multiple well pad locations will have to be aggregated for applicability determinations and reporting purposes.

The facility definition for the Natural Gas Distribution industry segment is not based on geography.  Instead, EPA has simply included “all distribution pipelines, metering stations, and regulating stations” that physically deliver natural gas to end users as operated by a single local distribution company (LDC).  The caveat relative to an LDC is that it is regulated as a separate operating company by a public utility commission or it is operated as an independent municipally-owned distribution system.

The eight industry segments and the associated 21 categories of emission sources for which GHG calculation procedures have been developed are summarized in the following table.

Summary of Source Types by Industry Segment

Source Type Industry Segments
(see list above)
1 2 3 4 5 6 7 8
Natural gas pneumatic device venting X X X
Natural gas driven pneumatic pump venting X
Acid gas removal vent X X
Dehydrator vent X X
Well venting for liquids unloading X
Gas well venting during well completions and workovers with hydraulic fracturing X
Gas well venting during well completions and workovers without hydraulic fracturing X
Blowdown vent stacks X X X X
Onshore production storage tanks X
Transmission storage tanks X
Well testing venting and flaring X
Associated gas venting and flaring X
Flare stacks X X
Centrifugal compressor venting X X X X X X
Reciprocating compressor and packing venting X X X X X X
Other emissions from equipment leaks X X X X X X X
Population count and emissions factor X X X X X
Vented equipment leaks and flare emissions identified in BOEMRE GOADS study X
Enhanced oil recovery hydrocarbon liquids dissolved CO2 X
Enhanced oil recovery injection pump blowdown X
Onshore petroleum and natural gas production and natural gas distribution combustion emissions X

X

EPA has developed extensive checklists that describe in detail what needs to be monitored at the seven onshore industry segments.  For example, Natural Gas Distribution facilities (Segment 8 ) need to account for the total number of leaking control valves and the operating time of leaking orifice meters, among many other things.  Emission calculation methods specified in the rule include engineering estimates, direct measurement, leak detection emission factors, and equipment counts with population emission factors.

The rule requires affected facilities to develop Monitoring Plans in accordance with the General Provisions by April 1, 2011.  Best available monitoring methods (BAMM) will be allowed for certain data gathering requirements for periods up through December 31, 2011.  Requests to use BAMM for extended periods must be submitted to EPA in accordance with the timing requirements specified in the rule (either April 30 or September 30, 2011).

CEC recommends that facilities carefully review the regulation, the EPA guidance, the applicability tools, and the emission estimation tools available at EPA’s site on their Greenhouse Gas Reporting Program page.  If you are unclear about how this rule affects your facility, please contact one of CEC’s GHG experts: Kris Macoskey, 800-365-2324, kmacoskey@cecinc.com.  You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.