Overview

On May 21, 2026, the Federal Energy Regulatory Commission unanimously approved a Notice of Proposed Rulemaking that would substantially expand the Part 157, Subpart F blanket certificate program for interstate natural gas pipelines. The proposal widens both the types and sizes of projects eligible for streamlined authorization and recalibrates cost limits that have been frozen in real terms since 2006. Comments are due 60 days after Federal Register publication.

The NOPR is worth reading not for what it proposes in isolation, but for what it reveals about the Commission’s current regulatory philosophy. The blanket certificate program has always been a barometer of FERC’s appetite for categorical deregulation of routine gas infrastructure. The 2006 revision was incremental; this one is not. And the questions FERC left open, particularly on mainline automatic authorization, suggest the final rule may go further still.

What the Blanket Certificate Program Does (and Why It Matters)

The blanket certificate program, created in 1982, allows interstate pipelines holding an NGA Section 7(c) certificate to undertake certain routine construction and abandonment activities under a one-time blanket authorization rather than filing individual certificate applications. The program sorts eligible activities into two tiers:

• “Automatic authorization” projects may proceed without any filing, subject to environmental conditions and cost limits.
• “Prior notice” projects require a filing with FERC and a 60-day notice period during which Commission staff and affected parties may protest.

The practical effect is significant. A project that qualifies for blanket treatment avoids the full Section 7 certificate process, which can take a year or more for even modest facilities. The NOPR would widen the aperture of both tiers considerably.

Key Proposals

Substantially Higher Cost Limits

FERC proposes to increase the per-project cost limits as follows:

• Automatic authorization projects: from approximately $14.5 million to $30 million.
• Prior notice projects: from approximately $41.1 million (or $61.65 million under the existing temporary waiver) to $86 million.
• Storage testing projects: from approximately $7.9 million to $17 million.

The Commission based these figures on INGAA’s analysis of Exhibit K data from Section 7 certificate applications, which showed a median 257% increase in cost per inch-mile and a 173% increase in cost per horsepower between 2006 and 2024. FERC staff verified the methodology and found no analytical flaws. The Commission declined, however, to add a further cushion for projected future cost trends, reasoning that prospective adjustments would be speculative.

The practical significance is less about the dollar figures themselves than about the category of work they bring inside the program’s perimeter. At the current limits, a straightforward compressor addition or pipeline loop serving incremental load can exceed the cap on materials and labor alone, requiring the project to go through a full Section 7 proceeding that adds months of review for what is, functionally, routine construction. The proposed limits would bring the program back into alignment with the scale of work it was designed to authorize.

New Inflation Adjustment Methodology

FERC proposes to replace the GDP implicit price deflator with the Handy-Whitman Index of Public Utility Construction Costs for annual adjustments to the blanket certificate cost limits. The GDP deflator has failed to keep pace with actual pipeline construction cost inflation, which is precisely why the Commission found itself needing to reset the limits in this rulemaking. The Handy-Whitman Index tracks gas utility construction costs more narrowly and should reduce the need for future one-time corrections.

This change matters more than it may appear. The shift from the GDP deflator to the Handy-Whitman Index is an implicit admission that the Commission’s own annual adjustment formula was structurally inadequate. Had the Handy-Whitman Index been in use since 2006, the cost limits would have tracked actual construction cost inflation, and this rulemaking may not have been necessary.

No Cost Limit for Compressor Station Expansions Within the Fence Line

The NOPR would remove cost limits entirely for expansions of existing compressor stations where the project remains within the station’s existing fence line, and the pipeline owns or leases all project land. These projects would proceed under prior notice procedures (not automatic authorization), preserving the opportunity for staff and affected parties to protest. Applicants would be required to file the full suite of environmental information required by Section 380.12(k), and the existing noise condition (55 dBA Ldn at any preexisting noise-sensitive area) would continue to apply.

Within-the-fence-line compression work involves no new right-of-way acquisition, no new landowner impacts, and a narrower environmental footprint than greenfield construction. By removing the cost cap and relying instead on the prior notice protest mechanism and the existing noise and air quality conditions, FERC is effectively treating the fence line as the proxy for the regulatory screening that cost limits were designed to approximate. That is a meaningful conceptual shift, and one worth watching as a potential template for future categorical expansions of the program.

Incremental Rates Now Available for Blanket Certificate Projects

Under current policy, FERC does not allow incremental rates for blanket certificate projects, meaning all capacity built under the program is priced at the pipeline’s existing system rate. The NOPR would change this for prior notice projects. A pipeline proposing incremental rates would file a rate exhibit with its application, and Commission staff and affected parties would have the 60-day notice period to evaluate and, if warranted, protest.

This change addresses a longstanding tension in the program. A pipeline with a creditworthy anchor shipper willing to pay an incremental rate for new capacity had no way to use that commercial arrangement under the blanket certificate, even if the project was otherwise routine. The only path was a full Section 7 proceeding. By opening the door to incremental rates under prior notice, FERC is acknowledging that rate treatment and project complexity are distinct questions that should not be conflated.

Receipt Points Treated Like Delivery Points

Currently, construction of receipt points (taps and metering facilities to receive gas onto a pipeline system) is subject to cost limits, while delivery points (the analogous facilities for delivering gas) are not. FERC proposes to eliminate the cost limitation on receipt points and allow them to proceed under automatic authorization, matching the treatment of delivery points. The facilities involved are functionally identical, and the Commission found no basis to differentiate treatment.

Abandonment Eligibility Based on Actual Cost

Under the current rules, FERC determines whether an abandonment project qualifies for blanket treatment based on the hypothetical cost to construct a modern replacement of the facility being abandoned, rather than the actual cost of the abandonment itself. The NOPR would reverse this approach. Because abandonment activities typically involve less construction and fewer environmental impacts than new construction, measuring eligibility by the actual cost of removal or decommissioning aligns more logically with the program’s framework.

Automatic Authorization for Storage Well Abandonments

Storage well abandonments currently require prior notice procedures regardless of cost. The NOPR would allow automatic authorization of storage well abandonments that do not alter the physical parameters of the storage field. The Commission found these abandonments to be routine and often driven by safety compliance requirements.

Two-Year In-Service Deadline

FERC proposes to extend the deadline for placing blanket certificate projects in service from one year to two years, consistent with its current practice in Section 7 proceedings and reflecting the reality that permitting delays, workforce constraints, and supply chain issues routinely push timelines beyond 12 months.

Mainline Automatic Authorization: An Open Question

The Commission stopped short of proposing this change but went further than simply asking whether it should. FERC directed staff to evaluate the proposal in its NEPA review, which means the environmental analysis that accompanies the final rule will include a scenario in which mainline projects qualify for automatic authorization. That is not the posture of a Commission that considers the question closed. FERC’s decision to include this scenario in the NEPA analysis suggests it is seriously weighing the option, and parties with a stake in this outcome, whether they favor expedition or want to preserve the prior notice process for mainline work, should treat the comment period as their primary opportunity to shape the result.

Additional Housekeeping and Clarifications

The NOPR includes several additional proposals worth noting. FERC would eliminate the separate prior notice requirement for facilities transporting synthetic gas or revaporized LNG, allowing these facilities to proceed under either tier subject to cost limits. FERC would clarify that the half-mile construction exclusion zone around nuclear facilities applies to “nuclear power reactor facilities” rather than “nuclear power plants,” a distinction that excludes nuclear storage facilities from the restriction. Landowner notification for prior notice projects would be required both at the start of easement negotiations and within three business days of docket assignment. Notification would be required by certified or first-class mail, replacing the current “good faith effort” standard.

What FERC Declined to Propose

Several significant requests were left on the table. FERC declined to expand the blanket program to projects receiving a “no adverse effect” finding from a State Historic Preservation Officer, concluding that doing so would require a nationwide programmatic agreement under the NHPA and would delay this rulemaking. FERC also declined to modify the temporary workspace rules under Section 2.55 to allow pipelines to use newly negotiated workspace for replacement projects, finding that the environmental protections of the existing rule warranted preservation. And FERC rejected proposals for a rolling three-year cumulative spending cap, finding that the existing prohibition on project segmentation adequately addresses the concern.

Practical Implications

If this rule is finalized as proposed, a substantial category of gas infrastructure work that currently requires a year or more of regulatory review would be eligible for authorization in 60 days or less, and some of it would require no filing at all. Development timelines would compress, capital deployment would accelerate, and the risk of regulatory delay on routine projects would drop materially. The removal of cost limits for within-the-fence-line compression work alone could facilitate maintenance and capacity additions that have faced extended timelines in Section 7 proceedings.

The availability of incremental rates under the blanket program is also a significant commercial development. Projects backed by creditworthy anchor shippers can now be structured with dedicated rate support and still move on an expedited timeline, which should improve returns on incremental capacity investment and make project-level financing more straightforward.

On the shipper side, the higher cost limits and broader scope of blanket-eligible projects warrant attention to cost allocation. The Commission’s proposal to require disclosure of project beneficiaries is a step toward transparency, but it remains to be seen whether that disclosure will provide enough information to evaluate rolled-in rate treatment at the next rate case. The evidentiary standard for demonstrating that a mainline expansion “benefits existing customers” is undefined, and how the Commission fills that gap in the final rule will determine how much protection existing shippers actually have.

The data center buildout adds a less obvious dimension. Much of the gas-fired generation being developed to serve co-located and behind-the-meter data center load depends on upstream pipeline capacity to deliver fuel. To the extent the revised blanket program accelerates lateral connections, compression additions, and receipt point construction, it may remove a supply-chain bottleneck that is not always visible in the data center permitting conversation but is very much present in practice.

The comment period is the moment to engage. The Commission left several questions open, most notably on mainline automatic authorization, the inflation methodology, and the evidentiary standard for rolled-in rate treatment, and a unanimous vote suggests the final rule will move quickly once comments close.

This alert is intended to provide a general overview of the Commission’s proposed revisions to the blanket certificate program for interstate natural gas pipelines. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project or filing.

RJ Colwell is a senior associate at Davis Graham & Stubbs LLP in the Energy & Mining Group. He advises pipeline companies, gas-fired generation developers, data center developers, and their investors and lenders on FERC regulatory matters, energy transactions, and infrastructure permitting. RJ can be reached at rj.colwell@davisgraham.com.

1. Reflecting on your time at Davis Graham, what was the most valuable lesson you learned? 
   • It’s extremely difficult to narrow it down to a single lesson.  If forced to choose one, I would say it is that building and maintaining relationships matters.  Obviously, you must continually grow as an attorney and become better, especially as a junior attorney when the learning curve is the steepest. However, if that is all that you do, then you are missing out on the people side, which matters just as much and is even more rewarding.  I couldn’t be prouder of being associated with Davis Graham, the attorneys there (past and present), and the clients.
2. How did your time at Davis Graham prepare you for your role at Black Rock?
   • Being in-house at a rapidly growing company, with a very lean legal department (single attorney, and an administrative assistant that splits her time helping out the development team), means that on a given day I’m asked to weigh in on topics ranging from securities to real estate, to corporate governance, to intellectual property, to litigation strategy, to insurance claims, and to human resources.  Some issues are really important to the company, and others are less material, but still important to the person that asked. Luckily, at Davis Graham, I was often the point person for clients and would then direct them to the firm’s internal specialist, where I learned as much as I could from them about their disciplines.  Now, my job is not so different, as internally people expect me to know all laws in all states at all times (I don’t), so I have to figure out when to get specialists involved.
3. What is the biggest difference between working at Davis Graham and running an in-house legal department?
   • Budgets.  At Davis Graham, I was fortunate to be insulated from budgets for the most part (thank you Sara Kraeski and the rest of the Executive Committee).  Because of that, I was able to focus on practicing law and trying to build a practice.  Now, while not necessarily the first questions asked, but certainly questions that ultimately always get asked are “How much will this cost? Did we budget for it? What will it do to our financial results? Do we still need it with that in mind?”.  
4. What is your favorite memory of working at Davis Graham?
   • It’s hard to pinpoint one, but I’ll tell a a story I told many junior associates.  I had been at the firm for about a month when I had the opportunity to work with John Elofson on a registration statement for PDC Energy, Inc. (two relationships that would define a large part of my time at Davis Graham).  I was adding little value to John on this Saturday afternoon, but he asked me to do two things (i) make and handful of changes to the prospectus (by hand) and (ii) scan and send those changes to the financial printer.  Only problem, I misspelled the same word 4 times in my hand markup and didn’t know how to use the scanner yet.  John, graciously, taught me that day how to spell and how to use the scanner, despite it making him stay at the office an extra hour to correct my mistakes.  I circle back to the story often because I like to believe that at some point over the years, through hard work and dedication, I earned John’s trust despite my spelling and scanning ability. 
5. Who are some of the people at Davis Graham that had the greatest influence on you and why?
   • These lists always get you in trouble because you inevitably leave off people that influenced you and deserve to be mentioned, but I’ll give it a shot. Chris Richardson was the first attorney I ever met, and once I learned he worked at Davis Graham, I knew that’s where I wanted to work because I wanted to be just like him.  Ron Levine for hiring me (despite not going through the proper channels, as I would learn is typical for Ron).  Kristin Lentz, John Elofson, Patricia Peterson and Deborah Friedman for teaching me to be a lawyer.  And, Jon Bergman and Sam Niebrugge for mentoring me and being my friend as I transitioned into the partnership.  

The Energy Innovators Network is a recurring quarterly series designed for professionals across the clean energy sector. Each session brings together business leaders, emerging innovators, and technical experts to explore a wide range of topics shaping the future of clean energy. From policy, project finance, emerging technologies, and market trends, the series provides attendees with insightful and timely programming.

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Davis Graham & Stubbs LLP was named among the 2026 Best Lawyers® “Best Law Firms” by publisher Woodward/White, Inc. in the latest edition of the guide. This edition marks the 16th consecutive year that Best Lawyers® has released its “Best Law Firms®” rankings, showcasing over 16,000 firms across 75 national practice areas and 127 practice areas in 188 metropolitan regions throughout the U.S. Firms were evaluated and ranked in three tiers, both regionally and nationally, based on extensive quantitative and qualitative feedback from peers and clients. 

Nationally, Davis Graham received Tier 1 rankings in the areas of Mining Law and Oil and Gas Law. Davis Graham was also nationally ranked in Corporate Law, Leveraged Buyouts and Private Equity Law, Litigation – Real Estate, and Natural Resources Law. The 2026 edition designated the firm with first-tier rankings in Colorado in the following practice areas: 
 

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1. Reflecting on your time at Davis Graham, what was the most valuable lesson you learned?
   • I learned many valuable lessons, and one that stands out is: how to effectively communicate with clients. The partners in the Oil & Gas Group were great models, and I continue to use the tools they gave me today.
2. What are some pro bono or community service experiences that have had a significant impact on your career? What did you learn from these opportunities, and how have they influenced your path?
   • I have been actively involved with the Rocky Mountain Chapter of the Cystic Fibrosis Foundation since I started practicing law. It’s a wonderful organization; at its core, the mission is to find a cure for CF. It’s been amazing to see the progress towards this in the last 15 years. When I started volunteering for the foundation the average life span of a person living with CF was 35, due to advances in treatments, it’s now 61. It’s taught me that if you stay focused on a mission, you will see results.
3. What is the biggest difference between working at Davis Graham and being in-house counsel?
   • For me the biggest difference has been the diversity of work. Working at a law firm, you tend to focus on one piece of the client’s business, i.e. transactions/contracts, regulatory, litigation, etc. Now that I am in-house, I touch every aspect of the business, which has been both fun and fast-paced. Every day is different, and I’m enjoying the challenges and opportunities each day brings.
4. What is your favorite memory of working at Davis Graham?
   • Aside from all of the wonderful people, I loved doing deal work. There’s always an adrenaline surge when a deal gets close to signing/closing and inevitably, there will be some roadblock that needs a workaround. When the deal is complete, you feel a real sense of accomplishment.
5. Who are some of the people at Davis Graham that had the greatest influence on you and why?
   • Everyone in the Oil & Gas Group! Gene Lang was instrumental in improving my commercial contract skills, specifically drafting and reviewing master service agreements and drilling contracts. I still call him every now and then when I have a question about a certain vendor or want to share a funny story. Greg Danielson, Craig Gleaton, Sam Niebrugge and Lamont Larsen were also great influences. Each took the time to explain why we do certain things the way we do them, and all were available whenever I had questions. I know I am a better lawyer for my time spent at Davis Graham under the guidance and leadership of the Oil & Gas team.