Securing Project Permits Takes Preparation

What's the status of the permit? Why is the permit taking so long? Why can't we get our permit?

These questions are heard all too often by executives and project managers seeking updates on construction projects in process.

Midstream build outs supporting the development of U.S. oil and gas shale plays occur in an era of heightened regulatory scrutiny. Environmental permitting is now the most time consuming—and often most complex—component of midstream project development. Upfront project planning enables operators to proactively address permitting concerns of affected parties and improve project timetables, thus de-risking projects and reducing costs.

Evolving regulatory standards demand executive awareness and attention because liabilities associated with environmental risk are expensive to remedy and can cost a company something invaluable—its reputation. Early knowledge of project impacts enables early solutions that result in timely permitting, liability transfer, de-risked projects and reduced costs.

Permits from appropriate regulatory agencies are required for unavoidable, project-related impacts to the environment from the production, development, transportation, refining and delivery of vital hydrocarbon resources. Regulatory regimes in each shale play area must be navigated by producers and operators and—although operating under standardized federal regulations—are required to address the local or regional preferences of each regulatory agency. In many cases, requirements vary by individual regulators themselves. Regulators have their own project timetables, compliance and reporting requirements that can vary widely from what contractors expect.

No. 1 risk factor

The energy industry is well aware of permit-cycle times and associated costly delays. A 2012 study of recent Securities and Exchange Commission 10-K annual report filings, done by tax advisory service BDO, noted for the past two years that the 100 largest exploration and production companies cited regulatory and legislative changes and the increased cost of compliance as the No. 1 risk factor and greatest regulatory concern to oil and gas businesses. E&P companies are certainly valid analogs for midstream firms with regard to permitting. Regulatory risk and liabilities are truly items of grave concern to midstream operators.

Consider the entire suite of environmental issues that arise in U.S. shale plays as shown in the accompanying table, "U.S. Environmental Issues." Any and all projects with development-stage assets may affect the surface of the earth. Surface impacts from midstream projects that most often require permits prior to construction include access roads, flowlines, gathering systems, laterals, pipeline trunks and brine ponds associated with subsurface gas storage. Of course, all project impacts are location-specific.

As shale play activities move from the appraisal to the development phase, it is increasingly difficult for surface operations to avoid impacts to the environment. Many shale play footprints are located in areas more visible to the general public than ever before in the history of domestic onshore production. Federal, state and local agencies are all involved in the project permitting process at various levels and for multiple activities. The ­table on page 73, highlights the spectrum of regulatory agencies that may be involved with permitting one project.

Two important questions: Does your project team know these regulators? Do they understand how these regulators will assess your project impacts?

The knowledge base

The value of a regulatory knowledge base is immeasurable. Each permitting agency addresses compliance by applying one or more laws and regulations. Each of these statutes is subject to interpretation—particularly when activities with unavoidable surface impacts are considered in an environmental context.

Regulators may not be, and are often not, attorneys; they may be administrators, practitioners, engineers, biologists or another kind of specialist. Agency attorneys are often most visible in the enforcement stage of permitting after the fact and a good subject for its own story.

As such, individual regulators' interpretations are often brought to the forefront during the permit application process. Relationships with agencies and their personnel will help to expedite permitting because the permit applicant can learn over time how to address agency and individual biases and preferences.

Knowledge of the methods applied by regulatory personnel provides insights into how a project will be evaluated. These methods are often years in the making, very well-documented and published with sound science behind them. And just like the regulations for which agencies are permitting, the methods often change over time. The table on page 74, "One Project, Many Permits," highlights some of the laws and statutes administered and enforced by regulators for a single Federal Energy Regulatory Commission (FERC)-regulated natural gas pipeline project. None of these regulations are new and many are undergoing scrutiny and amendments right now—for the first time in 40 years.

The assessment method employed by a regulator, vis-à-vis the compliant law or regulation, can change between projects or even vary within a single project. Regulators may assess impacts from several standpoints—temporal (permanent or temporary), spatial (single site, linear, combination, other), or cumulatively, among others. Each impact may be viewed from its own unique biological, chemical or physical attribute standpoint.

Each project is different and unique and will be thusly assessed. Agencies are regulators and regulators are people, and people apply rules of thumb and ratios to make their lives easier, even as assessment methodologies become more scientifically sound—and evolve over time.

A newly constructed pipeline crosses a Pennsylvania creek. Systems serving the state’s developing Marcellus and Utica plays face complex permitting requirements due to the area’s terrain. Source: U.S. Department of Agriculture

What is water?

Let's look at water from the midstream project-permitting perspective. Each project has its own compliance issues with regard to water. For example, in the Pennsylvania Marcellus shale, linear-corridor projects may require streams to be crossed every 2,000 feet, necessitating multiple state and federal permits, with some permits needed for each stream crossing and others for cumulative project impacts.

In the Louisiana Haynesville shale, every fifth well pad and its access roads and associated flowlines typically require a permit for deposit of fill material into wetlands. In the Texas Eagle Ford shale, what is now an access road may have once been a dry streambed, which potentially should have been permitted, if indeed it was not. The natural gas liquids processing facilities and natural gas storage caverns along the Gulf Coast are in, on, or under wetlands.

Wetlands, defined by the U.S. government as "Waters of the United States," are regulated under both the Clean Water Act of 1972 and the Rivers and Harbors Act of 1899. This water includes lakes, streams, rivers, their tributaries and the like—and wetlands. The surface impact activities mentioned above are considered fill to waters of the United States and therefore require a permit.

Clean Water Act permits are administered by the U.S. Army Corps of Engineers and enforced by the U.S. Environmental Protection Agency (EPA). In 2008, these agencies instituted regulatory compliance change by enacting their Final Rule for Compensatory Mitigation for Losses of Aquatic Resources (33 CFR 325 and 332, 40 CFR 230), requiring offsets for unavoidable impacts to wetlands and streams to be identified before project permitting and to occur in the watershed where the impacts will occur.

This change is material and means that projects must determine mitigation solutions before the permit application, rather than after the project as in days past. No longer can projects afford to wait for regulators to inform permit applicants late in the permitting process what mitigation is required to obtain the permit.

In 2012, many agency-driven environmentally oriented regulatory changes are in process; at least two involving water are proposed at the federal level. The first, proposed by the FERC, (FERC Docket AD12-2-000 Draft Revisions to the Upland Erosion Control, Revegetation, and Maintenance Plan and Wetland and Waterbody Construction and Mitigation Procedures and Request For Comments July 31, 2012) contains noteworthy revisions and procedural changes with regard to inspection, reporting and compliance. The second, EPA Docket EPA-HQ-OW-2011-0409, was released in 2011 and aims to redefine waters of the United States to bring more waters under the regulation of the EPA and the U.S. Army Corps of Engineers than are currently regulated. Of course, this has enormous implications.

The very definition of water will be changed. With the public comment period lapsed and tens of thousands of comments received, the process continues and, according to the EPA, it will "finalize the guidance and to continue work on a rulemaking."

Other federal agency examples include the Texas Rapid Assessment Method (TXRAM) for wetlands in the U.S. Army Corps of Engineers Fort Worth District, and Galveston Corps District's new interim Level 2 Rapid Assessment Method for Streams and long-standing interim Hydrogeomorphic Model (iHGM).

Regulatory change at the state agency level involving water includes Pennsylvania's upcoming Function Based Aquatic Resource Compensation Resource Protocol.

Be prepared

Change in assessment methods, change in regulations and change in application and interpretation of regulations—the only constant is change. The way to deal with change is to be prepared.

A presentation by this author at the 2012 Southern Gas Association's Environmental Permitting & Construction conference highlighted the impact of change on project costs. One single project was evaluated using four assessment methods as applied in each of four, separate Army Corps of Engineers districts. The ratio of required offsets for each acre of impact ranged from 0.6:1 to 3.6:1. Translated into dollar costs, the cost-per-impact-acre for a mitigation offset ranged from $12,000 to $72,000.

Why the difference? Type and quality of mitigation, technical differences in the functional assessment methods, application of ratio multipliers and supply and demand for mitigation offsets, in general, accounted for the variability in offset ratios and dollar costs.

Planning ahead to be prepared for compliance in a dynamic regulatory world means activating the environment in health-safety-environment operations as part of project planning as early as physically possible. The initial line on a map is a fine and appropriate starting point. Some to-dos:

• Team: Categorize projects to gain early knowledge and identify project-related environmental risk. Involve all members of the asset development team:
• Internal members: business development, project managers, environmental team, government and regulatory affairs, legal, investor relations and sponsoring executives.
• Trusted advisors: environmental and compliance companies, consultants and advisors, counsel, subject matter experts and solution providers.
• Scope and Magnitude: Evaluate projects to understand the scope and magnitude of potential impacts on environmental resources.
• Regulatory: Identify which regulatory agencies may require which permits for what activities. Determine the state of affairs with each and every regulatory agency and individual involved in the permitting process. Reach out and establish relationships with regulatory agencies.
• Avoid and Minimize: Document how projects will avoid and minimize project-related impacts.
• Solutions: Develop prioritized mitigation alternatives.
• Outreach: As projects get formalized, begin to build awareness and support for projects in the local community. Proactive communication and awareness overcomes public anxiety. Include the regulator community—they live there, too.