memo-ghg-cost-recovery.docx

1016-00005 · Dunmore Energy Holdings · Tariff Redesign

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CALDERWOOD & HARKNESS LLP 1601 K Street NW, Suite 900 Washington, DC 20006 Telephone: (202) 555-7100 Facsimile: (202) 555-7199

MEMORANDUM

TO:

Patricia Dunmore, Founder & Chairperson, Dunmore Energy Holdings Ltd. James K. Winfield, CEO & President, Ridgeline Midstream Services LLC Dr. Natasha Orlov, Director of Rates & Regulatory, Ridgeline Midstream Services LLC

FROM:

George Trujillo, Responsible Partner Brett Callahan, Lead Associate David Stanton, Working Associate Energy & Infrastructure Group, Calderwood & Harkness LLP

DATE: March 22, 2024

RE: Greenhouse Gas Cost Recovery Provisions — Addressing FERC Deficiency Item 13; FERC Docket Nos. RP22-847-000 and RP22-847-001; C&H Matter No. 1016-00005

CC: Dr. Raymond Braswell, Lead Consultant, Braswell Energy Consulting Group LLC (Engagement No. BEC-2023-0041)

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I. Executive Summary

This memorandum has been prepared at the request of Ridgeline Midstream Services LLC ("Ridgeline" or the "Pipeline") to address Deficiency Item 13 from the January 19, 2023 Deficiency Letter issued by the Federal Energy Regulatory Commission's ("FERC" or the "Commission") Office of Energy Market Regulation ("OEMR"). The Deficiency Letter, authored under the supervision of Dr. Miriam Okafor, Lead Economic Analyst for the proceeding, identified Ridgeline's failure to include provisions addressing greenhouse gas ("GHG") emission cost recovery in the proposed FERC Gas Tariff, Original Volume No. 1 (the "Tariff"). This memorandum sets forth our analysis of the governing legal and regulatory framework and provides recommended tariff language to cure the identified deficiency.

As background, Ridgeline Midstream Services LLC operates the Ridgeline Pipeline System (the "System"), a 187-mile, 24-inch-diameter high-pressure natural gas transmission pipeline extending from the Wetzel County Interconnect in Wetzel County, West Virginia, to the Waynesburg Compressor Station in Greene County, Pennsylvania. The System has a certificated design capacity of 1.2 billion cubic feet per day ("Bcf/d") and a current average throughput of approximately 680 million cubic feet per day ("MMcf/d"), representing approximately 56.67% utilization. Three compressor stations — the Wetzel Station, the Mannington Station, and the Waynesburg Station — provide an aggregate installed compression of 45,000 horsepower ("HP") and constitute the primary sources of GHG emissions on the System. These compressor stations combust natural gas to power centrifugal and reciprocating compressor units, producing carbon dioxide ("CO₂"), methane ("CH₄"), and nitrous oxide ("N₂O") emissions that are subject to, or are anticipated to become subject to, range federal and state regulatory requirements.

This memorandum undertakes four principal analytical tasks. First, it surveys the emerging federal and state regulatory landscape governing GHG emissions and cost recovery for midstream natural gas pipelines, including the Environmental Protection Agency's ("EPA") Greenhouse Gas Reporting Program (Subpart W), EPA's methane emissions reduction rules promulgated under the Clean Air Act ("CAA") as amended by the Inflation Reduction Act of 2022 ("IRA"), the Securities and Exchange Commission's ("SEC") recently adopted climate disclosure rules, and potential federal carbon pricing legislation. Second, it reviews the state-level regulatory environments in West Virginia and Pennsylvania, through which the System traverses, including Pennsylvania's contested participation in the Regional Greenhouse Gas Initiative ("RGGI") and West Virginia's evolving air quality permitting framework. Third, it examines FERC precedent and policy guidance concerning the recovery of environmental compliance costs in natural gas pipeline tariffs, including a survey of analogous tariff provisions adopted by comparable FERC-jurisdictional pipelines. Fourth, it proposes specific tariff language for a GHG Cost Tracker mechanism to be incorporated into Section 28 of the General Terms and Conditions of the redesigned Tariff.

Our recommendation is to incorporate a GHG Cost Tracker provision in Section 28 of the General Terms and Conditions of the redesigned FERC Gas Tariff, Original Volume No. 1. This mechanism would provide for the annual passthrough of incremental GHG compliance costs, with a prospective true-up mechanism designed to ensure that the Pipeline neither over-recovers nor under-recovers its actual GHG-related expenditures. The proposed tracker would be filed annually as a limited Section 4 filing under 18 C.F.R. § 154.403, with shipper protections including an annual rate cap of $0.005 per dekatherm ("Dth"), transparency requirements through electronic bulletin board ("EBB") posting, and Commission oversight through protest and investigation rights.

This memorandum has been prepared in close coordination with Braswell Energy Consulting Group LLC ("BECG"), whose lead consultant, Dr. Raymond Braswell (a former FERC staff economist), has been engaged since April 15, 2023 to support Ridgeline's comprehensive tariff redesign effort. The cost-of-service implications of the proposed GHG Cost Tracker have been integrated into the revised total cost of service, which is currently estimated at $103.15 million under the redesigned Tariff. The GHG tracker costs themselves are treated as a separate surcharge mechanism and are not included within that base cost-of-service figure. We estimate that the initial GHG Tracker Rate, based on a midpoint estimate of $3.5 million in annual GHG compliance costs, would be approximately $0.0107/Dth, yielding an effective total rate of approximately $0.3247/Dth when combined with the proposed redesigned recourse rate of $0.3140/Dth.

The sections that follow provide our detailed analysis and recommendations. We note that this memorandum should be read in conjunction with the companion memoranda prepared by Calderwood & Harkness LLP on the remaining unresolved deficiency items, as well as the BECG cost-of-service workpapers (Engagement No. BEC-2023-0041).

II. Background and Procedural Context

A. The FERC Proceeding

On May 12, 2022, Ridgeline Midstream Services LLC filed an application with the Federal Energy Regulatory Commission for an initial tariff rate and interconnection authorization in FERC Docket Nos. RP22-847-000 (the rate case proceeding) and RP22-847-001 (the interconnection proceeding). The filing was made pursuant to Sections 4 and 7 of the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717c and 717f, and the Commission's implementing regulations at 18 C.F.R. Parts 154 (Rate Schedules and Tariffs), 157 (Applications for Certificates of Public Convenience and Necessity), and 284 (Certain Sales and Transportation of Natural Gas Under the Natural Gas Policy Act of 1978 and Related Authorities). The filing included the proposed FERC Gas Tariff, Original Volume No. 1, Form of Service Agreements, and supporting rate schedules.

The proposed rate structure consisted of a recourse rate of $0.2265/Dth, composed of a reservation charge of $0.2223/Dth and a usage charge of $0.0042/Dth. This rate was derived from a total cost of service of $97.36 million, predicated upon a rate base of $612.40 million, a proposed return on equity ("ROE") of 14.00%, a capital structure of 55% equity and 45% debt, and a resulting weighted average cost of capital ("WACC") of 10.0625%. The billing determinants were calculated on a 100% load factor basis, yielding annual billing determinants of 438,000,000 Dth per year, based on the System's 1.2 Bcf/d design capacity. The original construction cost of the System was approximately $587.2 million, with the rate base reflecting post-in-service capital additions and adjustments through the test period.

The Commission assigned the case a Track II procedural schedule, indicating its determination that the case presented material issues warranting a full evidentiary hearing. Administrative Law Judge Clara Whitfield was appointed to preside over the hearing on November 14, 2022. In parallel, Settlement Judge Howard Margolis was appointed on September 22, 2022, pursuant to 18 C.F.R. § 385.603, to facilitate settlement negotiations among the parties.

Three entities intervened in the proceeding, each with distinct interests and concerns:

1. Appalachian Trunk Pipeline Company, LLC ("ATPC"), an existing FERC-jurisdictional interstate natural gas pipeline headquartered at 2200 Penn Center West, Suite 300, Pittsburgh, PA 15276, represented by Kellner, Royce & Dillard LLP (lead counsel William Pratt). ATPC operates a 640-mile interstate natural gas pipeline system with a design capacity of 3.8 Bcf/d. ATPC's intervention is principally focused on the terms and costs of the interconnection between the Ridgeline Pipeline System and ATPC's system at the Wetzel County Interconnect (ATPC Milepost 412.6). ATPC is a subsidiary of Tidewater Infrastructure Partners LP, which has an estimated enterprise value of approximately $6.1 billion and is controlled by the Alderman family.

2. Mountainside Gas Producers Coalition ("MGPC"), represented by Whitmore & Sable LLP (lead counsel Rebekah Montague). MGPC is a coalition of 14 independent natural gas producers operating in the Marcellus and Utica shale formations in the greater Appalachian Basin. MGPC generally supports the construction and operation of the Ridgeline Pipeline System as a new takeaway capacity option for Appalachian producers, but has intervened to oppose what it characterizes as an excessive proposed recourse rate. MGPC's retained rate expert, Dr. Eleanor Vasquez, has testified in support of a rate ceiling of approximately $0.2560/Dth. Calvin Dreyer serves as Executive Director of MGPC and has publicly advocated for rate stability for Appalachian producers.

3. Clearwater Municipal Gas Authority ("CMGA"), represented by Fordham Municipal Law Group PC (lead counsel Stephen Greer). CMGA is a municipal gas distribution authority, and its General Manager, Dennis Ott, has expressed concern regarding the potential impact of the Ridgeline interconnection on transportation rates on ATPC's system, which could ultimately affect delivered gas costs to CMGA's municipal end-users.

B. The Deficiency Letter and Item 13

On January 19, 2023, FERC's Office of Energy Market Regulation issued a Deficiency Letter identifying fourteen (14) deficiencies in Ridgeline's initial tariff filing. The letter was issued under the direction of Dr. Miriam Okafor, Lead Economic Analyst for the proceeding, and reflected OEMR's preliminary review of the Tariff as filed. The Deficiency Letter covered a broad range of issues, from fuel-use and lost-and-unaccounted-for gas ("FL&U") tracker mechanisms (Deficiency Item 2) to interruptible rate design (Deficiency Item 3), EBB posting requirements (Deficiency Item 7), IT revenue crediting (Deficiency Item 10), creditworthiness provisions (Deficiency Item 11), and Order No. 2222 implications for affiliated renewable energy assets (Deficiency Item 14).

Of particular relevance to this memorandum is Deficiency Item 13, which the OEMR described as follows:

"No provisions addressing greenhouse gas emission cost recovery — The proposed tariff contains no mechanism for tracking, allocating, or recovering costs that Ridgeline Midstream Services LLC may incur as a result of federal or state greenhouse gas emission regulations, carbon pricing programs, or emissions reporting requirements. Given the Pipeline's three compressor stations with 45,000 HP of aggregate installed compression, the Pipeline should address how it intends to treat GHG-related compliance costs, including but not limited to costs arising from the EPA Greenhouse Gas Reporting Program, potential methane emission charges under the Inflation Reduction Act, and any applicable state-level carbon pricing or cap-and-trade programs."

This language is significant because it demonstrates that FERC staff has affirmatively identified GHG cost recovery as an issue that must be addressed in the Tariff — not merely as an optional enhancement, but as a necessary component of a complete tariff filing. The specificity of the staff's reference to the IRA methane fee provisions and state-level carbon pricing programs indicates a level of analytical sophistication and forward-looking awareness that should inform our response.

On March 15, 2023, Ridgeline filed a partial response to the Deficiency Letter addressing eight (8) of the fourteen deficiency items — specifically, Items 1 through 4 and Items 7 through 10. Item 13 was among the six remaining items deferred to the comprehensive tariff redesign phase, which was the subject of Ridgeline's motion for an extension of time filed contemporaneously.

On February 6, 2023, ALJ Whitfield issued an order staying the hearing proceedings to allow the parties to attempt settlement and to permit Ridgeline to prepare its comprehensive response to the Deficiency Letter. Three subsequent extensions of time have been granted, and the current deadline for filing the redesigned Tariff and supplemental testimony is February 21, 2025. This deadline has been firmly established by ALJ Whitfield's most recent procedural order, and we do not anticipate that further extensions will be granted absent extraordinary circumstances.

In light of the tariff redesign timeline, Ridgeline engaged Braswell Energy Consulting Group LLC on April 15, 2023 to provide comprehensive rate and regulatory consulting support. Dr. Raymond Braswell, BECG's lead consultant, is a former FERC economist with extensive experience in natural gas pipeline rate design and cost-of-service analysis. Dr. Braswell's engagement encompasses all aspects of the tariff redesign, including the cost-of-service impact of the GHG Cost Tracker mechanism addressed in this memorandum.

C. Relevance to Ridgeline's Operations

The GHG cost recovery issue is of particular relevance to Ridgeline's operations because of the Pipeline's significant compression infrastructure. The three compressor stations on the System — the Wetzel Station (located near the Wetzel County Interconnect in Wetzel County, West Virginia), the Mannington Station (located near Mannington, Marion County, West Virginia), and the Waynesburg Station (located at the System's terminus in Greene County, Pennsylvania) — combust natural gas to power compression equipment, producing CO₂, CH₄, and N₂O emissions. With an aggregate installed compression capacity of 45,000 HP, the System's emissions footprint is meaningful, and the associated compliance costs are likely to increase materially over the coming years as federal and state regulatory requirements tighten.

Several operational and corporate considerations amplify the importance of addressing GHG cost recovery comprehensively:

Current throughput and future growth. The System's current throughput of approximately 680 MMcf/d represents approximately 56.67% utilization of its 1.2 Bcf/d design capacity. As throughput increases — whether through the execution of additional firm transportation service agreements, increased interruptible transportation volumes, or the development of new receipt and delivery point interconnections — emission levels will increase correspondingly. The GHG cost recovery mechanism must be designed to accommodate both current and anticipated future emission profiles.

Original construction cost and rate base. The System's original construction cost of $587.2 million and current rate base of $612.40 million reflect a substantial capital investment. The proposed GHG Cost Tracker mechanism is designed to avoid the need to adjust the rate base or base cost of service for each year's incremental GHG compliance costs, thereby preserving the stability of the underlying recourse rate while providing a transparent mechanism for recovering variable GHG-related expenditures.

Multi-state operations. The Pipeline traverses two states — West Virginia and Pennsylvania — each of which has its own existing or developing GHG regulatory framework. The tariff mechanism must be sufficiently flexible to accommodate the potentially divergent regulatory requirements of both states, including the possibility that one state may impose carbon pricing obligations while the other does not.

Corporate climate strategy. Dunmore Energy Holdings Ltd. ("DEH"), the sole member of Ridgeline and a Cayman Islands exempted limited company (Company Registration No. CR-381204), also has a 250-megawatt ("MW") wind energy portfolio under development. The intersection of DEH's renewable energy activities with Ridgeline's GHG compliance obligations raises the possibility that renewable energy credits ("RECs") or carbon offsets generated by the wind portfolio could be applied to reduce Ridgeline's GHG compliance costs. The tariff mechanism should contemplate this possibility, while maintaining appropriate separation between the regulated pipeline entity and DEH's other unregulated activities. We note that this issue also intersects with Deficiency Item 14 (Order No. 2222 implications), which is the subject of a separate Calderwood & Harkness memorandum scheduled for completion in May 2024.

Ridgeline's principal office and operational headquarters. Ridgeline maintains its principal office at 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301, situating the company within a state that has historically maintained a complex relationship with federal environmental regulation. This geographic and political context will inform both the substantive design of the GHG cost recovery mechanism and the strategic approach to presenting the mechanism to FERC and the intervenors.

III. Federal Regulatory Landscape for GHG Costs Affecting Midstream Pipelines

The federal regulatory landscape affecting GHG emissions from midstream natural gas pipeline operations has evolved substantially over the past several years and is expected to continue to evolve throughout the useful life of the Ridgeline Pipeline System. This section surveys the principal federal regulatory programs that currently impose, or are anticipated to impose, GHG-related compliance costs on the System. An understanding of this regulatory environment is essential both for designing a tariff mechanism that is sufficiently comprehensive and for providing FERC staff with the regulatory context necessary to evaluate the proposed GHG Cost Tracker.

A. EPA Greenhouse Gas Reporting Program (Subpart W)

The EPA's Greenhouse Gas Reporting Program ("GHGRP"), codified at 40 C.F.R. Part 98, requires the annual reporting of GHG emissions from specified source categories. Subpart W (40 C.F.R. Part 98, Subpart W) applies specifically to petroleum and natural gas systems, encompassing both gathering and boosting operations and natural gas transmission pipelines and compressor stations.

Under Subpart W, operators of natural gas transmission compression facilities are required to report annual GHG emissions from a range of source categories, including but not limited to: (i) reciprocating and centrifugal compressor venting; (ii) natural gas-fired combustion units (turbines, engines, heaters, and boilers); (iii) pneumatic device venting; (iv) blowdown events; and (v) equipment leaks from connectors, valves, open-ended lines, pressure relief valves, and other components. Facilities exceeding the 25,000 metric ton CO₂-equivalent ("CO₂e") annual reporting threshold must file annual reports with the EPA through the electronic Greenhouse Gas Reporting Tool ("e-GGRT") by March 31 of the year following the reporting year.

Ridgeline's three compressor stations collectively operate 45,000 HP of installed compression capacity. Based on preliminary emissions estimates prepared in coordination with Thomas Greaves, VP Engineering & Operations, and BECG, the System's aggregate annual GHG emissions are estimated to range from approximately 85,000 to 120,000 metric tons of CO₂e, depending on throughput levels, compressor utilization rates, and equipment configuration. These emissions exceed the Subpart W reporting threshold by a substantial margin, and Ridgeline is currently subject to Subpart W annual reporting obligations.

The current annual compliance cost associated with Subpart W reporting — including data collection, emissions quantification, third-party verification, quality assurance/quality control procedures, and e-GGRT submission — is estimated at approximately $175,000 to $250,000 per year for the System. These costs include the services of environmental consulting firms retained to assist with emissions inventory development and report preparation, as well as internal staff time allocated to compliance activities.

Importantly, the EPA has signaled its intent to expand the scope and stringency of Subpart W reporting requirements. Proposed revisions to Subpart W, published in the Federal Register on November 15, 2023 (88 Fed. Reg. 78,780), would, among other things: (i) require more granular component-level emissions reporting; (ii) mandate the use of direct measurement methodologies in lieu of engineering emission factors for certain source categories; and (iii) lower the reporting threshold for gathering and boosting segments. While the specific applicability of these proposed revisions to Ridgeline's transmission pipeline operations is subject to further analysis, the trend toward more rigorous and costly reporting requirements is clear. The GHG Cost Tracker mechanism should be designed to accommodate these anticipated cost increases.

B. EPA Methane Emissions Regulations

The EPA's methane emissions reduction regulatory program, promulgated under Section 111 of the Clean Air Act and substantially enhanced by the methane fee provisions of the Inflation Reduction Act of 2022 (Pub. L. 117-169, § 60113), represents the single most significant near-term source of potential GHG compliance costs for the Ridgeline Pipeline System.

Clean Air Act Methane Rules. On December 2, 2023, the EPA issued final rules establishing comprehensive New Source Performance Standards ("NSPS") and Emission Guidelines for the oil and natural gas sector under CAA Sections 111(b) and 111(d), respectively (88 Fed. Reg. 88,530). These rules, commonly referred to as "OOOOb" (new sources) and "OOOOc" (existing sources), establish emissions standards and work practice requirements for a wide range of GHG emission sources in the petroleum and natural gas production, processing, transmission, and storage segments. Key requirements applicable to Ridgeline's compressor stations include:

• Fugitive emissions monitoring. Operators of compressor stations must implement comprehensive Leak Detection and Repair ("LDAR") programs, including regular optical gas imaging ("OGI") surveys of all components at each compressor station. For new and modified compressor stations, the required survey frequency is quarterly; for existing sources, the initial required frequency is biannual, increasing to quarterly within three years. Each OGI survey at Ridgeline's three compressor stations is estimated to cost approximately $15,000 to $25,000 per station, yielding an annual LDAR cost of approximately $180,000 to $300,000 at the quarterly survey frequency.

• Pneumatic controller requirements. The rules require the replacement of high-bleed and intermittent-vent pneumatic controllers with zero-emission controllers (electric or instrument air) at compressor stations. Capital costs for pneumatic controller replacement at Ridgeline's three stations are estimated at $500,000 to $800,000, which would be capitalized and included in rate base rather than tracked through the GHG Cost Tracker.

• Compressor seal and rod packing requirements. Enhanced requirements for centrifugal compressor wet seal degassing and reciprocating compressor rod packing replacement impose additional maintenance and equipment costs.

• Super-emitter response program. The rules establish a framework for EPA-approved third-party "super-emitter" notification programs, under which any credible report of a super-emitter event (emissions exceeding 100 kg/hr of methane) at a covered facility triggers a mandatory investigation and response obligation.

IRA Methane Fee (Waste Emissions Charge). Section 60113 of the Inflation Reduction Act amended Section 136 of the Clean Air Act to impose a charge on methane emissions from petroleum and natural gas facilities that report under Subpart W and that exceed specified waste emissions thresholds. The charge is structured as follows:

• 2024 reporting year: $900 per metric ton of methane emissions exceeding the applicable threshold

• 2025 reporting year: $1,200 per metric ton

• 2026 and subsequent reporting years: $1,500 per metric ton

The applicable waste emissions threshold is calculated using facility-specific intensity benchmarks, expressed as a percentage of natural gas throughput. For transmission compression facilities, the waste emissions threshold is set at 0.05% of natural gas sent to pipeline from the facility. Emissions below this threshold are not subject to the charge; only "excess" emissions above the threshold trigger liability.

Based on preliminary analysis by BECG and Ridgeline's engineering team, the three compressor stations are currently estimated to emit methane at levels that may exceed the waste emissions threshold by a modest margin, depending on equipment condition, maintenance practices, and operational parameters. The estimated annual methane fee liability, assuming current emissions profiles and full implementation of the fee structure, ranges from approximately $800,000 to $2.5 million per year at the Wetzel Station, Mannington Station, and Waynesburg Station in the aggregate. This estimate is subject to considerable uncertainty, as actual emissions are influenced by variable factors including throughput levels, ambient temperature, equipment age, and the effectiveness of LDAR programs. Investments in emissions reduction technologies (e.g., pneumatic controller replacements, enhanced LDAR) could reduce the fee liability, but would generate capital costs recoverable through rate base rather than through the tracker mechanism.

We further note that the IRA methane fee provisions include an exemption for facilities that demonstrate compliance with the EPA's OOOOb/OOOOc rules, provided that the operator can demonstrate that its facility is in compliance with all applicable emissions standards. If Ridgeline achieves full compliance with the OOOOb/OOOOc rules for its compressor stations, the effective methane fee liability could be substantially reduced or eliminated. However, achieving and maintaining compliance will itself generate significant costs — including the LDAR program costs, pneumatic controller replacement costs, and enhanced monitoring costs described above — which must be recovered through the tariff.

The aggregate estimated annual cost impact of the EPA methane emissions regulatory program on Ridgeline's System, including LDAR compliance costs, enhanced monitoring, and the potential methane fee charge, ranges from approximately $2.0 million to $4.5 million per year. This estimate represents the most significant component of the projected GHG compliance cost range discussed in Section VIII below.

C. SEC Climate Disclosure Rules

On March 6, 2024, the Securities and Exchange Commission adopted final rules requiring registrants to provide climate-related disclosures in registration statements and annual reports (Securities Act Release No. 33-11275; Exchange Act Release No. 34-99678). The rules require, among other things, the disclosure of Scope 1 and Scope 2 GHG emissions for "large accelerated filers" and "accelerated filers," and material climate-related risks, strategies, governance, and financial impacts for all registrants.

Ridgeline Midstream Services LLC is a Delaware limited liability company and is not itself a registrant under the Securities Act of 1933 or the Securities Exchange Act of 1934. DEH, Ridgeline's sole member, is a Cayman Islands exempted limited company that is also not a SEC registrant. Accordingly, neither entity is currently subject to the SEC's climate disclosure rules.

However, the potential applicability of the SEC rules to Ridgeline and DEH warrants consideration in two scenarios:

First, if DEH or Ridgeline seeks to access the public capital markets — for example, through a registered offering of debt securities — the resulting registration statement would be subject to the SEC's climate disclosure requirements. This scenario is not presently anticipated, but it cannot be excluded as a future possibility, particularly given the capital-intensive nature of pipeline operations and the potential need for additional financing to support capacity expansions or GHG compliance capital expenditures.

Second, even absent a registration obligation, Ridgeline's existing private capital market participants may require disclosure compliance as a condition of financing. Ridgeline's $150 million 7.875% Second Lien Notes (the "Notes"), held by Harborview Capital Management LLC and Sentinel Ridge Fund LP, are governed by an indenture that includes certain reporting covenants. While the existing indenture does not expressly require SEC-compliant climate disclosures, future amendments, refinancings, or additional note issuances could include such requirements, particularly as institutional investors increasingly incorporate climate risk into their credit assessment frameworks. The compliance cost associated with preparing SEC-quality GHG emissions disclosures — including emissions quantification, third-party assurance, internal controls over climate data, and legal review — is estimated at $200,000 to $400,000 per year for an entity of Ridgeline's size and complexity.

While the probability of SEC climate disclosure obligations affecting Ridgeline in the near term is relatively low, the GHG Cost Tracker mechanism should be designed with sufficient breadth to encompass disclosure compliance costs if and when they materialize. We recommend that the definition of "GHG Compliance Costs" in the proposed tariff language include costs incurred in connection with GHG emissions disclosure requirements imposed by any federal regulatory authority, not limited to the EPA.

D. Potential Federal Carbon Pricing

Although no federal carbon pricing legislation has been enacted as of the date of this memorandum, the prospect of a future federal carbon tax or cap-and-trade program remains a material consideration in the design of a long-term GHG cost recovery mechanism. The Ridgeline Pipeline System has an anticipated useful life of at least 40 years, and the regulatory environment over that period is likely to include some form of carbon pricing mechanism.

Several legislative proposals introduced in recent Congressional sessions illustrate the potential scope and design of a federal carbon pricing program. The Energy Innovation and Carbon Dividend Act (most recently reintroduced as H.R. 2307 in the 118th Congress) would impose a fee on fossil fuel producers and importers based on the carbon content of their products, starting at $15 per metric ton of CO₂e and increasing by $10 per year, with adjustments for inflation and emissions reduction progress. While this proposal targets upstream fossil fuel production rather than midstream transportation, the economic incidence of such a fee would likely be borne, in part, by midstream pipeline operators through increased costs of pipeline fuel gas and indirect effects on the competitiveness and throughput of natural gas relative to other energy sources.

Other proposals, such as the American Opportunity Carbon Fee Act (S. 1128, 117th Congress), would apply a carbon fee directly to facilities emitting more than 25,000 metric tons of CO₂e per year — a threshold that Ridgeline's compressor stations are estimated to exceed. Under such a program, Ridgeline would be directly liable for carbon fee payments based on its actual emissions, with the fee rate potentially ranging from $25 to $50 per metric ton of CO₂e in initial years, escalating over time.

The economic impact of a hypothetical federal carbon pricing program on the Ridgeline Pipeline System would depend heavily on the specific design parameters of the enacted legislation, including the price per ton, the covered sources and activities, the availability of exemptions or offsets, and the interaction with existing EPA regulations and state-level carbon pricing programs. Preliminary illustrative modeling by BECG, using a range of carbon price assumptions from $25 to $75 per metric ton of CO₂e, suggests that the annual cost impact on Ridgeline could range from approximately $2.1 million to $9.0 million, depending on throughput levels and the specific design of the carbon pricing mechanism.

Given the uncertainty regarding the timing, design, and ultimate enactment of federal carbon pricing legislation, we do not recommend attempting to quantify or include a specific carbon price assumption in the initial GHG Cost Tracker filing. Rather, the proposed tariff language should include a broad, forward-looking definition of "Applicable GHG Regulations" that encompasses any future federal carbon pricing mechanism, and the out-of-cycle filing provision (proposed Section 28.8) should specifically authorize the Pipeline to adjust the GHG Tracker Rate in response to the enactment of a federal carbon tax or cap-and-trade program. This approach provides the necessary tariff flexibility to accommodate a wide range of potential future regulatory developments without prejudging the specific form that such developments may take.

IV. State Regulatory Landscape — West Virginia and Pennsylvania

The Ridgeline Pipeline System traverses two states — West Virginia and Pennsylvania — each of which has its own distinct regulatory framework governing air quality, GHG emissions, and environmental compliance. This section surveys the relevant state-level regulatory environments and identifies the potential GHG compliance costs associated with each state's requirements.

A. West Virginia

Ridgeline's operations in West Virginia are anchored by the System's receipt point at the Wetzel County Interconnect in Wetzel County, the Wetzel Compressor Station and the Mannington Compressor Station (both located in West Virginia), and Ridgeline's principal office at 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301. Approximately 120 miles of the System's 187-mile route traverse West Virginia, and the majority of the System's compression capacity (two of three compressor stations, comprising approximately 30,000 HP of the 45,000 HP total) is located in the state.

Air Quality Permitting. West Virginia's air quality permitting program is administered by the West Virginia Department of Environmental Protection ("WVDEP"), Division of Air Quality ("DAQ"), pursuant to the West Virginia Air Pollution Control Act (W. Va. Code §§ 22-5-1 et seq.) and the state's federally approved State Implementation Plan ("SIP"). Ridgeline's compressor stations in West Virginia operate under Title V operating permits issued by the DAQ, which incorporate federal New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants ("NESHAP") applicable to natural gas transmission and storage facilities.

Current annual air quality compliance costs for the West Virginia compressor stations, including permit fees, emission monitoring, annual emission inventory preparation, and compliance reporting, are estimated at approximately $180,000 to $250,000 per year. These costs are included in the System's current operating and maintenance expenses and are reflected in the base cost of service.

State Income Tax. West Virginia imposes a corporate net income tax at a rate of 6.5%, which, in combination with the 21% federal corporate income tax rate, yields an effective combined income tax rate of approximately 26.13%. This effective tax rate is reflected in the income tax allowance component of the redesigned cost of service. While the state income tax rate is not itself a GHG-related cost, it is relevant to the cost-of-service calculation insofar as any GHG compliance costs that are treated as deductible operating expenses will reduce taxable income and generate a tax benefit that partially offsets the gross cost to the Pipeline. The GHG Tracker Rate calculation should reflect the after-tax impact of GHG compliance costs to avoid over-recovery.

West Virginia's Position on GHG Regulation. West Virginia has historically adopted a cautious approach to GHG regulation, reflecting the state's economic dependence on fossil fuel extraction and combustion. The West Virginia Legislature has not enacted a statewide GHG emissions reduction program, carbon pricing mechanism, or cap-and-trade system. Indeed, West Virginia was a lead plaintiff in West Virginia v. EPA, 597 U.S. 697 (2022), in which the Supreme Court held that the EPA lacked authority under CAA Section 111(d) to adopt a generation-shifting approach to regulating GHG emissions from power plants. The state's political and regulatory posture suggests that West Virginia is unlikely to impose significant independent GHG regulatory burdens on natural gas pipeline operations in the near term.

However, two developments warrant monitoring. First, the WVDEP may be required to adopt state-level emission guidelines for existing oil and gas sources pursuant to the EPA's OOOOc rule, which directs states to submit plans for implementing emission guidelines for existing sources within specified deadlines. The state's compliance with this federal directive will determine the specific regulatory obligations applicable to Ridgeline's West Virginia compressor stations, and any associated compliance costs would fall within the scope of the proposed GHG Cost Tracker.

Second, West Virginia imposes various property, franchise, and severance taxes on natural gas operations, and the possibility of future GHG-related tax levies — whether characterized as environmental impact fees, emission surcharges, or similar assessments — cannot be excluded over the multi-decade useful life of the System. The test-year taxes other than income currently total $3.80 million, reflecting existing property and franchise tax obligations. Any incremental GHG-related tax levies would be appropriately captured by the GHG Cost Tracker mechanism.

B. Pennsylvania. Ridgeline's operations in Pennsylvania center on the Waynesburg Compressor Station, located in Greene County, Pennsylvania, which serves as the System's primary delivery point and houses approximately 15,000 HP of the System's aggregate compression capacity. Approximately 67 miles of the System's route traverse Pennsylvania.

Regional Greenhouse Gas Initiative (RGGI). The most significant potential source of GHG compliance costs for Ridgeline's Pennsylvania operations is the Commonwealth's contested participation in the Regional Greenhouse Gas Initiative. RGGI is a cooperative cap-and-trade program among participating states in the northeastern and mid-Atlantic United States that caps CO₂ emissions from electric generating units and requires covered sources to purchase CO₂ emission allowances at quarterly auctions.

On April 23, 2022, the Pennsylvania Environmental Quality Board published a final rulemaking (52 Pa. Bull. 2038) adopting 25 Pa. Code Chapter 145, Subchapter E, establishing Pennsylvania's CO₂ Budget Trading Program. The rule would require owners and operators of "CO₂ budget sources" — defined generally as fossil fuel-fired electric generating units with a capacity of 25 megawatts or greater — to purchase CO₂ allowances for each ton of CO₂ emitted during each control period.

The direct applicability of Pennsylvania's RGGI rule to Ridgeline's Waynesburg Compressor Station is uncertain. The RGGI program, as adopted by Pennsylvania, targets electric generating units rather than natural gas pipeline compressor stations. However, several factors create potential exposure:

• The definition of "CO₂ budget source" could potentially be expanded through future regulatory amendments to encompass natural gas compressor stations, particularly if the program is extended beyond the power sector.

• Even if Ridgeline's compressor station is not directly subject to RGGI, the Pipeline may be indirectly affected by increased electricity costs resulting from RGGI compliance by electric generators serving the System. Ridgeline purchases electricity for ancillary equipment, lighting, and controls at its compressor stations, and RGGI-driven increases in electricity costs would represent an indirect GHG compliance cost.

• If Pennsylvania expands its carbon pricing program or adopts a broader economy-wide cap-and-trade system — a possibility that has been discussed in the Pennsylvania state legislature — the Waynesburg Compressor Station could become a directly covered source.

We note, however, that Pennsylvania's participation in RGGI faces significant legal challenges. On November 1, 2023, the Commonwealth Court of Pennsylvania ruled in Bowfin KeyCon Holdings LLC v. Pennsylvania Department of Environmental Protection that the RGGI rulemaking exceeded the authority of the Environmental Quality Board and violated the Pennsylvania Air Pollution Control Act. The case is currently on appeal to the Pennsylvania Supreme Court, and the ultimate fate of Pennsylvania's RGGI participation remains uncertain. For purposes of our analysis, we estimate the potential annual cost impact of Pennsylvania RGGI-related obligations on the Waynesburg Compressor Station at $0.5 million to $1.5 million per year, with the wide range reflecting the uncertainty regarding the scope and durability of the program.

Pennsylvania Air Pollution Control Act. Independent of RGGI, Ridgeline's Waynesburg Compressor Station is subject to the Pennsylvania Air Pollution Control Act (35 P.S. §§ 4001–4015) and the implementing regulations of the Pennsylvania Department of Environmental Protection ("PaDEP"), Bureau of Air Quality. The station operates under a Title V operating permit incorporating applicable NSPS and NESHAP requirements. Current annual compliance costs for the Pennsylvania compressor station, including permit fees, emission monitoring, compliance reporting, and source testing, are estimated at approximately $80,000 to $120,000 per year.

Comparative Analysis — ATPC. A comparative analysis of ATPC's treatment of GHG costs is instructive. ATPC, headquartered at 2200 Penn Center West, Suite 300, Pittsburgh, PA 15276, operates its 640-mile interstate pipeline system predominantly in Pennsylvania, with substantial compression capacity. ATPC's FERC Gas Tariff, as most recently revised, does not contain a standalone GHG cost recovery tracker mechanism. ATPC has historically recovered its environmental compliance costs — including GHG-related costs — through its base cost of service, with adjustments made in periodic Section 4 rate filings. However, ATPC has not faced a recent FERC rate case in which GHG cost recovery was specifically at issue, and ATPC's parent, Tidewater Infrastructure Partners LP, may be developing its own approach to GHG cost recovery in light of evolving federal and state requirements.

The absence of a GHG cost tracker in ATPC's existing tariff does not preclude Ridgeline from proposing such a mechanism. To the contrary, Ridgeline's status as a new pipeline with an initial tariff filing provides an opportunity to incorporate forward-looking GHG cost recovery provisions from the outset — an approach that FERC staff has expressly identified as necessary through Deficiency Item 13.

C. Multi-State Compliance Coordination

The fact that Ridgeline's System spans the West Virginia–Pennsylvania border creates coordination challenges that the GHG Cost Tracker mechanism must address. Specifically:

Harmonized compliance approach. Ridgeline must comply with the distinct GHG regulatory frameworks of both states simultaneously. To the extent that West Virginia and Pennsylvania adopt divergent emission standards, monitoring requirements, or carbon pricing mechanisms, Ridgeline will incur state-specific compliance costs that must be appropriately tracked and allocated within the GHG Cost Tracker. The proposed tariff language defines "Applicable GHG Regulations" to include the laws and regulations of any state in which the Pipeline operates, ensuring comprehensive coverage.

Interconnection considerations. The Wetzel County Interconnect, located at ATPC Milepost 412.6, is the point at which the Ridgeline Pipeline System receives natural gas from ATPC's system. The proposed interconnection facilities, estimated at $22.3 million, include metering and measurement equipment (ultrasonic flow meters, gas chromatographs, and SCADA integration) designed to measure gas quality and quantity at the interconnection point. In light of the emerging GHG regulatory framework, Ridgeline and ATPC should consider whether GHG monitoring equipment — such as continuous emission monitoring systems ("CEMS") or methane detection sensors — should be incorporated into the interconnection metering station design. The incremental cost of integrating GHG monitoring equipment into the metering station is estimated at $250,000 to $500,000 (one-time capital cost), which could be included in the interconnection facilities cost and allocated between Ridgeline and ATPC pursuant to the interconnection agreement.

upstream/downstream GHG cost allocation. To the extent that GHG emissions at the Wetzel County Interconnect point are attributable to upstream activities on ATPC's system (e.g., methane slip or venting from ATPC's transmission operations) versus downstream activities on Ridgeline's system, questions of GHG cost allocation between the two pipelines may arise. The proposed GHG Cost Tracker mechanism is designed to recover only those GHG compliance costs that are directly attributable to Ridgeline's own operations and for which Ridgeline is legally liable. Costs attributable to ATPC's operations or emissions would not be included in Ridgeline's tracker.

V. FERC Policy on GHG Cost Recovery in Natural Gas Pipeline Tariffs

A. Current FERC Framework

The Federal Energy Regulatory Commission exercises jurisdiction over the rates, terms, and conditions of interstate natural gas pipeline transportation service pursuant to Sections 4 and 5 of the Natural Gas Act, 15 U.S.C. §§ 717c and 717d, and the Commission's implementing regulations at 18 C.F.R. Part 154. Under the NGA's regulatory framework, a pipeline's rates must be "just and reasonable" (NGA § 4(a)) and may not include any "undue preference or advantage" or "unreasonable difference in rates" (NGA § 4(b)). The Commission determines just and reasonable rates primarily through cost-of-service ratemaking, in which the pipeline's total cost of service — comprising return on rate base, depreciation, operations and maintenance expenses, administrative and general expenses, taxes, and revenue credits — is allocated among the pipeline's shippers on the basis of appropriate billing determinants.

Within this framework, GHG compliance costs represent a category of operating expense that must be addressed through the tariff rate structure. The critical analytical question is whether GHG compliance costs are properly characterized as "known and measurable" costs — i.e., costs that can be quantified with reasonable certainty and included in the pipeline's base cost of service at the time of a Section 4 rate filing — or as contingent, prospective, or variable costs that are more appropriately addressed through a tracker or surcharge mechanism.

This distinction is fundamental to the design of the GHG cost recovery mechanism. Known-and-measurable costs are "baked into" the base recourse rate at the time of the rate filing and remain fixed until the pipeline files a new Section 4 rate case or FERC initiates a Section 5 investigation. Tracker mechanisms, by contrast, allow for periodic (typically annual) adjustments to a separate rate component to reflect changes in specified cost categories, without the need for a full rate case filing.

FERC has long recognized the appropriateness of tracker mechanisms for cost categories that are: (i) subject to significant variability or uncertainty; (ii) driven by external regulatory requirements outside the pipeline's control; (iii) material in magnitude; and (iv) susceptible to reasonably accurate quantification on a periodic basis. GHG compliance costs exhibit all four of these characteristics, and the tracker approach is therefore well-suited to this cost category.

B. FERC Policy Statements and Orders on Environmental Costs

The Commission's evolving treatment of environmental compliance costs in the natural gas pipeline context provides important guidance for the design of Ridgeline's GHG Cost Tracker mechanism.

2022 Updated Policy Statement on Certification. On February 18, 2022, the Commission issued an Updated Policy Statement on Certification of New Interstate Natural Gas Facilities (178 FERC ¶ 61,107), which established a new framework for evaluating the environmental impact of proposed natural gas pipeline projects, including an assessment of GHG emissions. Although the Policy Statement was subsequently designated as a "draft" policy statement following industry and Congressional criticism, and its legal status remains somewhat unsettled, it reflects the Commission's increasing attention to GHG considerations in the natural gas pipeline context. The Policy Statement discussed, among other things, the Commission's interest in understanding the "reasonably foreseeable" GHG emissions associated with a proposed pipeline project and the extent to which those emissions would be mitigated.

While the Certification Policy Statement primarily addresses the Commission's certificate evaluation process rather than rate design, it is relevant to the GHG cost recovery analysis insofar as it signals the Commission's expectation that pipeline operators will address GHG emissions comprehensively — including the costs associated with monitoring, reporting, and mitigating those emissions. Deficiency Item 13 can be understood as the rate-side corollary of the Certificate Policy Statement's GHG assessment requirements.

Interim GHG Significance Thresholds. In connection with the 2022 Policy Statement, the Commission discussed the establishment of GHG significance thresholds that would trigger enhanced environmental review and potential mitigation requirements for proposed pipeline projects. Although no final threshold has been adopted, the Commission's discussion of significance thresholds (at both 100,000 and 300,000 metric tons of CO₂e per year) further underscores the regulatory salience of GHG emissions in the natural gas pipeline sector. Ridgeline's estimated annual emissions of 85,000 to 120,000 metric tons of CO₂e fall within the range that the Commission has identified as potentially significant.

Treatment of Environmental Compliance Costs in Rate Cases. FERC has consistently permitted pipelines to include documented, known-and-measurable environmental compliance costs in their cost of service as part of the operations and maintenance expense category. These costs may include air quality monitoring and reporting expenses, environmental remediation costs, and regulatory compliance program expenses. However, the Commission has also recognized that environmental compliance costs may be appropriately addressed through tracker mechanisms when the costs are subject to significant variability or are driven by regulatory requirements that may change during the rate period.

Precedent for Tracker Mechanisms. The Commission has approved range tracker mechanisms in natural gas pipeline tariffs, including:

• Fuel, Lost, and Unaccounted-for Gas ("FL&U") Trackers. FL&U trackers are the most common and well-established form of tracker mechanism in FERC-jurisdictional pipeline tariffs. These trackers allow pipelines to adjust a separate rate component annually (or more frequently) to reflect actual fuel consumption and gas losses, without the need for a full rate case. The FL&U tracker mechanism is directly analogous to the proposed GHG Cost Tracker in structure and purpose. We note that Deficiency Item 2 in the Ridgeline Deficiency Letter also required the inclusion of an FL&U tracker, and the GHG Cost Tracker is designed to be structurally consistent with and complementary to the FL&U tracker mechanism.

• Electric Power Cost Trackers. Several pipelines have obtained FERC approval for tracker mechanisms that adjust rates to reflect changes in the cost of electricity used to power electric-driven compression, which is a cost category subject to variability based on wholesale electricity market conditions.

• Tax Rate Change Trackers. Following the Tax Cuts and Jobs Act of 2017, which reduced the federal corporate income tax rate from 35% to 21%, FERC approved tracker mechanisms to flow through the tax rate change to shippers.

The structural features of these approved tracker mechanisms — annual filing, true-up procedures, shipper protest rights, and Commission oversight — provide the template for the proposed GHG Cost Tracker.

Rolled-In vs. Surcharge Treatment. FERC has generally expressed a preference for "rolled-in" cost-of-service treatment for routine, ongoing operating costs, and has reserved surcharge or tracker treatment for cost categories that are variable, uncertain, or driven by external factors. GHG compliance costs exhibit characteristics of both categories: some costs (e.g., annual reporting fees) are relatively stable and predictable, while others (e.g., methane fee charges, carbon pricing costs) are highly variable and subject to regulatory change. The proposed GHG Cost Tracker mechanism represents a pragmatic compromise, treating GHG compliance costs as a separate surcharge that is transparent to shippers and adjustable on an annual basis, while avoiding the need to embed volatile cost assumptions in the base recourse rate.

C. FERC Precedent — Comparable Pipeline Tariff Provisions

As part of our analysis, we conducted a survey of FERC-jurisdictional pipeline tariffs to identify existing GHG or environmental cost recovery provisions that could serve as models for the Ridgeline tariff. The results of this survey are summarized in full at Appendix A; key findings are presented here.

Of the eight comparable FERC-jurisdictional pipelines surveyed — selected on the basis of geographic location (Appalachian Basin or adjacent regions), pipeline diameter and capacity (20-inch to 36-inch diameter, 0.5 to 4.0 Bcf/d capacity), and recency of rate filing (Section 4 filings or initial tariff filings within the past five years) — we identified three that have adopted tariff provisions specifically addressing GHG or environmental compliance cost recovery:

1. Pipeline A (name withheld pending privilege review) adopted an "Environmental Compliance Cost Tracker" in its FERC Gas Tariff in connection with a 2021 Section 4 rate case settlement. The tracker covers "costs incurred by Pipeline in compliance with Environmental Laws and Regulations, including but not limited to greenhouse gas emission regulations, air quality standards, and water quality requirements." The tracker provides for annual filings with a 180-day true-up period, subject to a rate cap of $0.008/Dth per year.

2. Pipeline B included a "Carbon Cost Recovery Surcharge" provision in its initial tariff filing in 2022, specifically designed to address the anticipated costs of compliance with the IRA methane fee and potential state-level carbon pricing programs. The surcharge is calculated annually based on projected carbon-related costs, with a quarterly true-up mechanism and no rate cap. The tariff provision was approved by FERC without modification as part of an uncontested settlement.

3. Pipeline C adopted a general "Regulatory Compliance Cost Tracker" that encompasses a broader range of regulatory compliance costs, including GHG-related costs, safety compliance costs, and cybersecurity compliance costs. The tracker provides for semi-annual filings with shipper protest rights and independent audit requirements.

The remaining five pipelines surveyed do not have standalone GHG cost recovery provisions and recover environmental compliance costs through their base cost of service. However, several of these pipelines have pending Section 4 rate cases or anticipated rate filings in which GHG cost recovery provisions may be introduced.

Key observations from the survey include:

• Annual filing and true-up procedures are the most common structural feature, reflecting FERC's preference for periodic cost verification and adjustment.

• Shipper protections — including rate caps, protest rights, and independent audit or verification requirements — are consistently included and appear to be expected by FERC staff as a condition of approval.

• Broad definitions of covered cost categories are preferred over narrow enumerations, providing flexibility to accommodate evolving regulatory requirements while maintaining transparency through itemized supporting documentation.

• Separation from FL&U tracker mechanisms is important to avoid confusion or double-counting, as some GHG compliance costs (e.g., methane emissions from compressor stations) may overlap with fuel-use and lost-and-unaccounted-for gas measurement issues.

D. FERC Trial Staff Position

Based on our experience with the proceeding and our analysis of the Deficiency Letter, we anticipate that FERC Trial Staff will be generally supportive of a well-designed GHG Cost Tracker mechanism, given that Item 13 of the Deficiency Letter expressly directed Ridgeline to include GHG cost recovery provisions in the Tariff. However, staff's support is likely to be conditioned on several factors:

Lead Trial Attorney Jonathan Briggs has not taken a public position on GHG cost recovery mechanisms in natural gas pipeline tariffs, but his involvement in recent proceedings involving environmental compliance cost issues suggests a preference for transparency, documentation, and shipper protections. We anticipate that Mr. Briggs will scrutinize the proposed mechanism for any potential for over-recovery, cross-subsidization, or inclusion of costs that are properly borne by the Pipeline's equity owners rather than its shippers.

Lead Economic Analyst Dr. Miriam Okafor, who authored the Deficiency Letter language directing Ridgeline to address GHG cost recovery, is likely to evaluate the proposed mechanism against her analytical framework for cost tracker design. Based on the specificity of her Deficiency Letter language — which referenced the IRA methane fee provisions and state carbon pricing programs by name — we anticipate that Dr. Okafor will expect the tariff language to address each of these specific regulatory programs, with supporting cost estimates and allocation methodologies.

Anticipated staff concerns include:

• Cost pass-through limitations. Staff may seek to ensure that the Pipeline does not simply pass through all GHG-related costs to shippers without taking reasonable steps to minimize those costs. The proposed annual cap of $0.005/Dth addresses this concern by cre

PRIVILEGED AND CONFIDENTIAL — ATTORNEY WORK PRODUCT This memorandum is protected by the attorney-client privilege and the work product doctrine. It has been prepared by Calderwood & Harkness LLP at the request of and for the exclusive use of the addressees herein. This memorandum should not be disclosed to any third party, except as expressly authorized by counsel, without the prior written consent of Calderwood & Harkness LLP. Unauthorized disclosure may result in a waiver of applicable privileges.
CALDERWOOD & HARKNESS LLP 1601 K Street NW, Suite 900 Washington, DC 20006 Telephone: (202) 555-7100 Facsimile: (202) 555-7199
MEMORANDUM
TO:
Patricia Dunmore, Founder & Chairperson, Dunmore Energy Holdings Ltd. James K. Winfield, CEO & President, Ridgeline Midstream Services LLC Dr. Natasha Orlov, Director of Rates & Regulatory, Ridgeline Midstream Services LLC
FROM:
George Trujillo, Responsible Partner Brett Callahan, Lead Associate David Stanton, Working Associate Energy & Infrastructure Group, Calderwood & Harkness LLP
DATE: March 22, 2024
RE: Greenhouse Gas Cost Recovery Provisions — Addressing FERC Deficiency Item 13; FERC Docket Nos. RP22-847-000 and RP22-847-001; C&H Matter No. 1016-00005
CC: Dr. Raymond Braswell, Lead Consultant, Braswell Energy Consulting Group LLC (Engagement No. BEC-2023-0041)
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I. Executive Summary
This memorandum has been prepared at the request of Ridgeline Midstream Services LLC ("Ridgeline" or the "Pipeline") to address Deficiency Item 13 from the January 19, 2023 Deficiency Letter issued by the Federal Energy Regulatory Commission's ("FERC" or the "Commission") Office of Energy Market Regulation ("OEMR"). The Deficiency Letter, authored under the supervision of Dr. Miriam Okafor, Lead Economic Analyst for the proceeding, identified Ridgeline's failure to include provisions addressing greenhouse gas ("GHG") emission cost recovery in the proposed FERC Gas Tariff, Original Volume No. 1 (the "Tariff"). This memorandum sets forth our analysis of the governing legal and regulatory framework and provides recommended tariff language to cure the identified deficiency.
As background, Ridgeline Midstream Services LLC operates the Ridgeline Pipeline System (the "System"), a 187-mile, 24-inch-diameter high-pressure natural gas transmission pipeline extending from the Wetzel County Interconnect in Wetzel County, West Virginia, to the Waynesburg Compressor Station in Greene County, Pennsylvania. The System has a certificated design capacity of 1.2 billion cubic feet per day ("Bcf/d") and a current average throughput of approximately 680 million cubic feet per day ("MMcf/d"), representing approximately 56.67% utilization. Three compressor stations — the Wetzel Station, the Mannington Station, and the Waynesburg Station — provide an aggregate installed compression of 45,000 horsepower ("HP") and constitute the primary sources of GHG emissions on the System. These compressor stations combust natural gas to power centrifugal and reciprocating compressor units, producing carbon dioxide ("CO₂"), methane ("CH₄"), and nitrous oxide ("N₂O") emissions that are subject to, or are anticipated to become subject to, range federal and state regulatory requirements.
This memorandum undertakes four principal analytical tasks. First, it surveys the emerging federal and state regulatory landscape governing GHG emissions and cost recovery for midstream natural gas pipelines, including the Environmental Protection Agency's ("EPA") Greenhouse Gas Reporting Program (Subpart W), EPA's methane emissions reduction rules promulgated under the Clean Air Act ("CAA") as amended by the Inflation Reduction Act of 2022 ("IRA"), the Securities and Exchange Commission's ("SEC") recently adopted climate disclosure rules, and potential federal carbon pricing legislation. Second, it reviews the state-level regulatory environments in West Virginia and Pennsylvania, through which the System traverses, including Pennsylvania's contested participation in the Regional Greenhouse Gas Initiative ("RGGI") and West Virginia's evolving air quality permitting framework. Third, it examines FERC precedent and policy guidance concerning the recovery of environmental compliance costs in natural gas pipeline tariffs, including a survey of analogous tariff provisions adopted by comparable FERC-jurisdictional pipelines. Fourth, it proposes specific tariff language for a GHG Cost Tracker mechanism to be incorporated into Section 28 of the General Terms and Conditions of the redesigned Tariff.
Our recommendation is to incorporate a GHG Cost Tracker provision in Section 28 of the General Terms and Conditions of the redesigned FERC Gas Tariff, Original Volume No. 1. This mechanism would provide for the annual passthrough of incremental GHG compliance costs, with a prospective true-up mechanism designed to ensure that the Pipeline neither over-recovers nor under-recovers its actual GHG-related expenditures. The proposed tracker would be filed annually as a limited Section 4 filing under 18 C.F.R. § 154.403, with shipper protections including an annual rate cap of $0.005 per dekatherm ("Dth"), transparency requirements through electronic bulletin board ("EBB") posting, and Commission oversight through protest and investigation rights.
This memorandum has been prepared in close coordination with Braswell Energy Consulting Group LLC ("BECG"), whose lead consultant, Dr. Raymond Braswell (a former FERC staff economist), has been engaged since April 15, 2023 to support Ridgeline's comprehensive tariff redesign effort. The cost-of-service implications of the proposed GHG Cost Tracker have been integrated into the revised total cost of service, which is currently estimated at $103.15 million under the redesigned Tariff. The GHG tracker costs themselves are treated as a separate surcharge mechanism and are not included within that base cost-of-service figure. We estimate that the initial GHG Tracker Rate, based on a midpoint estimate of $3.5 million in annual GHG compliance costs, would be approximately $0.0107/Dth, yielding an effective total rate of approximately $0.3247/Dth when combined with the proposed redesigned recourse rate of $0.3140/Dth.
The sections that follow provide our detailed analysis and recommendations. We note that this memorandum should be read in conjunction with the companion memoranda prepared by Calderwood & Harkness LLP on the remaining unresolved deficiency items, as well as the BECG cost-of-service workpapers (Engagement No. BEC-2023-0041).
II. Background and Procedural Context
A. The FERC Proceeding
On May 12, 2022, Ridgeline Midstream Services LLC filed an application with the Federal Energy Regulatory Commission for an initial tariff rate and interconnection authorization in FERC Docket Nos. RP22-847-000 (the rate case proceeding) and RP22-847-001 (the interconnection proceeding). The filing was made pursuant to Sections 4 and 7 of the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717c and 717f, and the Commission's implementing regulations at 18 C.F.R. Parts 154 (Rate Schedules and Tariffs), 157 (Applications for Certificates of Public Convenience and Necessity), and 284 (Certain Sales and Transportation of Natural Gas Under the Natural Gas Policy Act of 1978 and Related Authorities). The filing included the proposed FERC Gas Tariff, Original Volume No. 1, Form of Service Agreements, and supporting rate schedules.
The proposed rate structure consisted of a recourse rate of $0.2265/Dth, composed of a reservation charge of $0.2223/Dth and a usage charge of $0.0042/Dth. This rate was derived from a total cost of service of $97.36 million, predicated upon a rate base of $612.40 million, a proposed return on equity ("ROE") of 14.00%, a capital structure of 55% equity and 45% debt, and a resulting weighted average cost of capital ("WACC") of 10.0625%. The billing determinants were calculated on a 100% load factor basis, yielding annual billing determinants of 438,000,000 Dth per year, based on the System's 1.2 Bcf/d design capacity. The original construction cost of the System was approximately $587.2 million, with the rate base reflecting post-in-service capital additions and adjustments through the test period.
The Commission assigned the case a Track II procedural schedule, indicating its determination that the case presented material issues warranting a full evidentiary hearing. Administrative Law Judge Clara Whitfield was appointed to preside over the hearing on November 14, 2022. In parallel, Settlement Judge Howard Margolis was appointed on September 22, 2022, pursuant to 18 C.F.R. § 385.603, to facilitate settlement negotiations among the parties.
Three entities intervened in the proceeding, each with distinct interests and concerns:
1. Appalachian Trunk Pipeline Company, LLC ("ATPC"), an existing FERC-jurisdictional interstate natural gas pipeline headquartered at 2200 Penn Center West, Suite 300, Pittsburgh, PA 15276, represented by Kellner, Royce & Dillard LLP (lead counsel William Pratt). ATPC operates a 640-mile interstate natural gas pipeline system with a design capacity of 3.8 Bcf/d. ATPC's intervention is principally focused on the terms and costs of the interconnection between the Ridgeline Pipeline System and ATPC's system at the Wetzel County Interconnect (ATPC Milepost 412.6). ATPC is a subsidiary of Tidewater Infrastructure Partners LP, which has an estimated enterprise value of approximately $6.1 billion and is controlled by the Alderman family.
2. Mountainside Gas Producers Coalition ("MGPC"), represented by Whitmore & Sable LLP (lead counsel Rebekah Montague). MGPC is a coalition of 14 independent natural gas producers operating in the Marcellus and Utica shale formations in the greater Appalachian Basin. MGPC generally supports the construction and operation of the Ridgeline Pipeline System as a new takeaway capacity option for Appalachian producers, but has intervened to oppose what it characterizes as an excessive proposed recourse rate. MGPC's retained rate expert, Dr. Eleanor Vasquez, has testified in support of a rate ceiling of approximately $0.2560/Dth. Calvin Dreyer serves as Executive Director of MGPC and has publicly advocated for rate stability for Appalachian producers.
3. Clearwater Municipal Gas Authority ("CMGA"), represented by Fordham Municipal Law Group PC (lead counsel Stephen Greer). CMGA is a municipal gas distribution authority, and its General Manager, Dennis Ott, has expressed concern regarding the potential impact of the Ridgeline interconnection on transportation rates on ATPC's system, which could ultimately affect delivered gas costs to CMGA's municipal end-users.
B. The Deficiency Letter and Item 13
On January 19, 2023, FERC's Office of Energy Market Regulation issued a Deficiency Letter identifying fourteen (14) deficiencies in Ridgeline's initial tariff filing. The letter was issued under the direction of Dr. Miriam Okafor, Lead Economic Analyst for the proceeding, and reflected OEMR's preliminary review of the Tariff as filed. The Deficiency Letter covered a broad range of issues, from fuel-use and lost-and-unaccounted-for gas ("FL&U") tracker mechanisms (Deficiency Item 2) to interruptible rate design (Deficiency Item 3), EBB posting requirements (Deficiency Item 7), IT revenue crediting (Deficiency Item 10), creditworthiness provisions (Deficiency Item 11), and Order No. 2222 implications for affiliated renewable energy assets (Deficiency Item 14).
Of particular relevance to this memorandum is Deficiency Item 13, which the OEMR described as follows:
"No provisions addressing greenhouse gas emission cost recovery — The proposed tariff contains no mechanism for tracking, allocating, or recovering costs that Ridgeline Midstream Services LLC may incur as a result of federal or state greenhouse gas emission regulations, carbon pricing programs, or emissions reporting requirements. Given the Pipeline's three compressor stations with 45,000 HP of aggregate installed compression, the Pipeline should address how it intends to treat GHG-related compliance costs, including but not limited to costs arising from the EPA Greenhouse Gas Reporting Program, potential methane emission charges under the Inflation Reduction Act, and any applicable state-level carbon pricing or cap-and-trade programs."
This language is significant because it demonstrates that FERC staff has affirmatively identified GHG cost recovery as an issue that must be addressed in the Tariff — not merely as an optional enhancement, but as a necessary component of a complete tariff filing. The specificity of the staff's reference to the IRA methane fee provisions and state-level carbon pricing programs indicates a level of analytical sophistication and forward-looking awareness that should inform our response.
On March 15, 2023, Ridgeline filed a partial response to the Deficiency Letter addressing eight (8) of the fourteen deficiency items — specifically, Items 1 through 4 and Items 7 through 10. Item 13 was among the six remaining items deferred to the comprehensive tariff redesign phase, which was the subject of Ridgeline's motion for an extension of time filed contemporaneously.
On February 6, 2023, ALJ Whitfield issued an order staying the hearing proceedings to allow the parties to attempt settlement and to permit Ridgeline to prepare its comprehensive response to the Deficiency Letter. Three subsequent extensions of time have been granted, and the current deadline for filing the redesigned Tariff and supplemental testimony is February 21, 2025. This deadline has been firmly established by ALJ Whitfield's most recent procedural order, and we do not anticipate that further extensions will be granted absent extraordinary circumstances.
In light of the tariff redesign timeline, Ridgeline engaged Braswell Energy Consulting Group LLC on April 15, 2023 to provide comprehensive rate and regulatory consulting support. Dr. Raymond Braswell, BECG's lead consultant, is a former FERC economist with extensive experience in natural gas pipeline rate design and cost-of-service analysis. Dr. Braswell's engagement encompasses all aspects of the tariff redesign, including the cost-of-service impact of the GHG Cost Tracker mechanism addressed in this memorandum.
C. Relevance to Ridgeline's Operations
The GHG cost recovery issue is of particular relevance to Ridgeline's operations because of the Pipeline's significant compression infrastructure. The three compressor stations on the System — the Wetzel Station (located near the Wetzel County Interconnect in Wetzel County, West Virginia), the Mannington Station (located near Mannington, Marion County, West Virginia), and the Waynesburg Station (located at the System's terminus in Greene County, Pennsylvania) — combust natural gas to power compression equipment, producing CO₂, CH₄, and N₂O emissions. With an aggregate installed compression capacity of 45,000 HP, the System's emissions footprint is meaningful, and the associated compliance costs are likely to increase materially over the coming years as federal and state regulatory requirements tighten.
Several operational and corporate considerations amplify the importance of addressing GHG cost recovery comprehensively:
Current throughput and future growth. The System's current throughput of approximately 680 MMcf/d represents approximately 56.67% utilization of its 1.2 Bcf/d design capacity. As throughput increases — whether through the execution of additional firm transportation service agreements, increased interruptible transportation volumes, or the development of new receipt and delivery point interconnections — emission levels will increase correspondingly. The GHG cost recovery mechanism must be designed to accommodate both current and anticipated future emission profiles.
Original construction cost and rate base. The System's original construction cost of $587.2 million and current rate base of $612.40 million reflect a substantial capital investment. The proposed GHG Cost Tracker mechanism is designed to avoid the need to adjust the rate base or base cost of service for each year's incremental GHG compliance costs, thereby preserving the stability of the underlying recourse rate while providing a transparent mechanism for recovering variable GHG-related expenditures.
Multi-state operations. The Pipeline traverses two states — West Virginia and Pennsylvania — each of which has its own existing or developing GHG regulatory framework. The tariff mechanism must be sufficiently flexible to accommodate the potentially divergent regulatory requirements of both states, including the possibility that one state may impose carbon pricing obligations while the other does not.
Corporate climate strategy. Dunmore Energy Holdings Ltd. ("DEH"), the sole member of Ridgeline and a Cayman Islands exempted limited company (Company Registration No. CR-381204), also has a 250-megawatt ("MW") wind energy portfolio under development. The intersection of DEH's renewable energy activities with Ridgeline's GHG compliance obligations raises the possibility that renewable energy credits ("RECs") or carbon offsets generated by the wind portfolio could be applied to reduce Ridgeline's GHG compliance costs. The tariff mechanism should contemplate this possibility, while maintaining appropriate separation between the regulated pipeline entity and DEH's other unregulated activities. We note that this issue also intersects with Deficiency Item 14 (Order No. 2222 implications), which is the subject of a separate Calderwood & Harkness memorandum scheduled for completion in May 2024.
Ridgeline's principal office and operational headquarters. Ridgeline maintains its principal office at 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301, situating the company within a state that has historically maintained a complex relationship with federal environmental regulation. This geographic and political context will inform both the substantive design of the GHG cost recovery mechanism and the strategic approach to presenting the mechanism to FERC and the intervenors.
III. Federal Regulatory Landscape for GHG Costs Affecting Midstream Pipelines
The federal regulatory landscape affecting GHG emissions from midstream natural gas pipeline operations has evolved substantially over the past several years and is expected to continue to evolve throughout the useful life of the Ridgeline Pipeline System. This section surveys the principal federal regulatory programs that currently impose, or are anticipated to impose, GHG-related compliance costs on the System. An understanding of this regulatory environment is essential both for designing a tariff mechanism that is sufficiently comprehensive and for providing FERC staff with the regulatory context necessary to evaluate the proposed GHG Cost Tracker.
A. EPA Greenhouse Gas Reporting Program (Subpart W)
The EPA's Greenhouse Gas Reporting Program ("GHGRP"), codified at 40 C.F.R. Part 98, requires the annual reporting of GHG emissions from specified source categories. Subpart W (40 C.F.R. Part 98, Subpart W) applies specifically to petroleum and natural gas systems, encompassing both gathering and boosting operations and natural gas transmission pipelines and compressor stations.
Under Subpart W, operators of natural gas transmission compression facilities are required to report annual GHG emissions from a range of source categories, including but not limited to: (i) reciprocating and centrifugal compressor venting; (ii) natural gas-fired combustion units (turbines, engines, heaters, and boilers); (iii) pneumatic device venting; (iv) blowdown events; and (v) equipment leaks from connectors, valves, open-ended lines, pressure relief valves, and other components. Facilities exceeding the 25,000 metric ton CO₂-equivalent ("CO₂e") annual reporting threshold must file annual reports with the EPA through the electronic Greenhouse Gas Reporting Tool ("e-GGRT") by March 31 of the year following the reporting year.
Ridgeline's three compressor stations collectively operate 45,000 HP of installed compression capacity. Based on preliminary emissions estimates prepared in coordination with Thomas Greaves, VP Engineering & Operations, and BECG, the System's aggregate annual GHG emissions are estimated to range from approximately 85,000 to 120,000 metric tons of CO₂e, depending on throughput levels, compressor utilization rates, and equipment configuration. These emissions exceed the Subpart W reporting threshold by a substantial margin, and Ridgeline is currently subject to Subpart W annual reporting obligations.
The current annual compliance cost associated with Subpart W reporting — including data collection, emissions quantification, third-party verification, quality assurance/quality control procedures, and e-GGRT submission — is estimated at approximately $175,000 to $250,000 per year for the System. These costs include the services of environmental consulting firms retained to assist with emissions inventory development and report preparation, as well as internal staff time allocated to compliance activities.
Importantly, the EPA has signaled its intent to expand the scope and stringency of Subpart W reporting requirements. Proposed revisions to Subpart W, published in the Federal Register on November 15, 2023 (88 Fed. Reg. 78,780), would, among other things: (i) require more granular component-level emissions reporting; (ii) mandate the use of direct measurement methodologies in lieu of engineering emission factors for certain source categories; and (iii) lower the reporting threshold for gathering and boosting segments. While the specific applicability of these proposed revisions to Ridgeline's transmission pipeline operations is subject to further analysis, the trend toward more rigorous and costly reporting requirements is clear. The GHG Cost Tracker mechanism should be designed to accommodate these anticipated cost increases.
B. EPA Methane Emissions Regulations
The EPA's methane emissions reduction regulatory program, promulgated under Section 111 of the Clean Air Act and substantially enhanced by the methane fee provisions of the Inflation Reduction Act of 2022 (Pub. L. 117-169, § 60113), represents the single most significant near-term source of potential GHG compliance costs for the Ridgeline Pipeline System.
Clean Air Act Methane Rules. On December 2, 2023, the EPA issued final rules establishing comprehensive New Source Performance Standards ("NSPS") and Emission Guidelines for the oil and natural gas sector under CAA Sections 111(b) and 111(d), respectively (88 Fed. Reg. 88,530). These rules, commonly referred to as "OOOOb" (new sources) and "OOOOc" (existing sources), establish emissions standards and work practice requirements for a wide range of GHG emission sources in the petroleum and natural gas production, processing, transmission, and storage segments. Key requirements applicable to Ridgeline's compressor stations include:
• Fugitive emissions monitoring. Operators of compressor stations must implement comprehensive Leak Detection and Repair ("LDAR") programs, including regular optical gas imaging ("OGI") surveys of all components at each compressor station. For new and modified compressor stations, the required survey frequency is quarterly; for existing sources, the initial required frequency is biannual, increasing to quarterly within three years. Each OGI survey at Ridgeline's three compressor stations is estimated to cost approximately $15,000 to $25,000 per station, yielding an annual LDAR cost of approximately $180,000 to $300,000 at the quarterly survey frequency.
• Pneumatic controller requirements. The rules require the replacement of high-bleed and intermittent-vent pneumatic controllers with zero-emission controllers (electric or instrument air) at compressor stations. Capital costs for pneumatic controller replacement at Ridgeline's three stations are estimated at $500,000 to $800,000, which would be capitalized and included in rate base rather than tracked through the GHG Cost Tracker.
• Compressor seal and rod packing requirements. Enhanced requirements for centrifugal compressor wet seal degassing and reciprocating compressor rod packing replacement impose additional maintenance and equipment costs.
• Super-emitter response program. The rules establish a framework for EPA-approved third-party "super-emitter" notification programs, under which any credible report of a super-emitter event (emissions exceeding 100 kg/hr of methane) at a covered facility triggers a mandatory investigation and response obligation.
IRA Methane Fee (Waste Emissions Charge). Section 60113 of the Inflation Reduction Act amended Section 136 of the Clean Air Act to impose a charge on methane emissions from petroleum and natural gas facilities that report under Subpart W and that exceed specified waste emissions thresholds. The charge is structured as follows:
• 2024 reporting year: $900 per metric ton of methane emissions exceeding the applicable threshold
• 2025 reporting year: $1,200 per metric ton
• 2026 and subsequent reporting years: $1,500 per metric ton
The applicable waste emissions threshold is calculated using facility-specific intensity benchmarks, expressed as a percentage of natural gas throughput. For transmission compression facilities, the waste emissions threshold is set at 0.05% of natural gas sent to pipeline from the facility. Emissions below this threshold are not subject to the charge; only "excess" emissions above the threshold trigger liability.
Based on preliminary analysis by BECG and Ridgeline's engineering team, the three compressor stations are currently estimated to emit methane at levels that may exceed the waste emissions threshold by a modest margin, depending on equipment condition, maintenance practices, and operational parameters. The estimated annual methane fee liability, assuming current emissions profiles and full implementation of the fee structure, ranges from approximately $800,000 to $2.5 million per year at the Wetzel Station, Mannington Station, and Waynesburg Station in the aggregate. This estimate is subject to considerable uncertainty, as actual emissions are influenced by variable factors including throughput levels, ambient temperature, equipment age, and the effectiveness of LDAR programs. Investments in emissions reduction technologies (e.g., pneumatic controller replacements, enhanced LDAR) could reduce the fee liability, but would generate capital costs recoverable through rate base rather than through the tracker mechanism.
We further note that the IRA methane fee provisions include an exemption for facilities that demonstrate compliance with the EPA's OOOOb/OOOOc rules, provided that the operator can demonstrate that its facility is in compliance with all applicable emissions standards. If Ridgeline achieves full compliance with the OOOOb/OOOOc rules for its compressor stations, the effective methane fee liability could be substantially reduced or eliminated. However, achieving and maintaining compliance will itself generate significant costs — including the LDAR program costs, pneumatic controller replacement costs, and enhanced monitoring costs described above — which must be recovered through the tariff.
The aggregate estimated annual cost impact of the EPA methane emissions regulatory program on Ridgeline's System, including LDAR compliance costs, enhanced monitoring, and the potential methane fee charge, ranges from approximately $2.0 million to $4.5 million per year. This estimate represents the most significant component of the projected GHG compliance cost range discussed in Section VIII below.
C. SEC Climate Disclosure Rules
On March 6, 2024, the Securities and Exchange Commission adopted final rules requiring registrants to provide climate-related disclosures in registration statements and annual reports (Securities Act Release No. 33-11275; Exchange Act Release No. 34-99678). The rules require, among other things, the disclosure of Scope 1 and Scope 2 GHG emissions for "large accelerated filers" and "accelerated filers," and material climate-related risks, strategies, governance, and financial impacts for all registrants.
Ridgeline Midstream Services LLC is a Delaware limited liability company and is not itself a registrant under the Securities Act of 1933 or the Securities Exchange Act of 1934. DEH, Ridgeline's sole member, is a Cayman Islands exempted limited company that is also not a SEC registrant. Accordingly, neither entity is currently subject to the SEC's climate disclosure rules.
However, the potential applicability of the SEC rules to Ridgeline and DEH warrants consideration in two scenarios:
First, if DEH or Ridgeline seeks to access the public capital markets — for example, through a registered offering of debt securities — the resulting registration statement would be subject to the SEC's climate disclosure requirements. This scenario is not presently anticipated, but it cannot be excluded as a future possibility, particularly given the capital-intensive nature of pipeline operations and the potential need for additional financing to support capacity expansions or GHG compliance capital expenditures.
Second, even absent a registration obligation, Ridgeline's existing private capital market participants may require disclosure compliance as a condition of financing. Ridgeline's $150 million 7.875% Second Lien Notes (the "Notes"), held by Harborview Capital Management LLC and Sentinel Ridge Fund LP, are governed by an indenture that includes certain reporting covenants. While the existing indenture does not expressly require SEC-compliant climate disclosures, future amendments, refinancings, or additional note issuances could include such requirements, particularly as institutional investors increasingly incorporate climate risk into their credit assessment frameworks. The compliance cost associated with preparing SEC-quality GHG emissions disclosures — including emissions quantification, third-party assurance, internal controls over climate data, and legal review — is estimated at $200,000 to $400,000 per year for an entity of Ridgeline's size and complexity.
While the probability of SEC climate disclosure obligations affecting Ridgeline in the near term is relatively low, the GHG Cost Tracker mechanism should be designed with sufficient breadth to encompass disclosure compliance costs if and when they materialize. We recommend that the definition of "GHG Compliance Costs" in the proposed tariff language include costs incurred in connection with GHG emissions disclosure requirements imposed by any federal regulatory authority, not limited to the EPA.
D. Potential Federal Carbon Pricing
Although no federal carbon pricing legislation has been enacted as of the date of this memorandum, the prospect of a future federal carbon tax or cap-and-trade program remains a material consideration in the design of a long-term GHG cost recovery mechanism. The Ridgeline Pipeline System has an anticipated useful life of at least 40 years, and the regulatory environment over that period is likely to include some form of carbon pricing mechanism.
Several legislative proposals introduced in recent Congressional sessions illustrate the potential scope and design of a federal carbon pricing program. The Energy Innovation and Carbon Dividend Act (most recently reintroduced as H.R. 2307 in the 118th Congress) would impose a fee on fossil fuel producers and importers based on the carbon content of their products, starting at $15 per metric ton of CO₂e and increasing by $10 per year, with adjustments for inflation and emissions reduction progress. While this proposal targets upstream fossil fuel production rather than midstream transportation, the economic incidence of such a fee would likely be borne, in part, by midstream pipeline operators through increased costs of pipeline fuel gas and indirect effects on the competitiveness and throughput of natural gas relative to other energy sources.
Other proposals, such as the American Opportunity Carbon Fee Act (S. 1128, 117th Congress), would apply a carbon fee directly to facilities emitting more than 25,000 metric tons of CO₂e per year — a threshold that Ridgeline's compressor stations are estimated to exceed. Under such a program, Ridgeline would be directly liable for carbon fee payments based on its actual emissions, with the fee rate potentially ranging from $25 to $50 per metric ton of CO₂e in initial years, escalating over time.
The economic impact of a hypothetical federal carbon pricing program on the Ridgeline Pipeline System would depend heavily on the specific design parameters of the enacted legislation, including the price per ton, the covered sources and activities, the availability of exemptions or offsets, and the interaction with existing EPA regulations and state-level carbon pricing programs. Preliminary illustrative modeling by BECG, using a range of carbon price assumptions from $25 to $75 per metric ton of CO₂e, suggests that the annual cost impact on Ridgeline could range from approximately $2.1 million to $9.0 million, depending on throughput levels and the specific design of the carbon pricing mechanism.
Given the uncertainty regarding the timing, design, and ultimate enactment of federal carbon pricing legislation, we do not recommend attempting to quantify or include a specific carbon price assumption in the initial GHG Cost Tracker filing. Rather, the proposed tariff language should include a broad, forward-looking definition of "Applicable GHG Regulations" that encompasses any future federal carbon pricing mechanism, and the out-of-cycle filing provision (proposed Section 28.8) should specifically authorize the Pipeline to adjust the GHG Tracker Rate in response to the enactment of a federal carbon tax or cap-and-trade program. This approach provides the necessary tariff flexibility to accommodate a wide range of potential future regulatory developments without prejudging the specific form that such developments may take.
IV. State Regulatory Landscape — West Virginia and Pennsylvania
The Ridgeline Pipeline System traverses two states — West Virginia and Pennsylvania — each of which has its own distinct regulatory framework governing air quality, GHG emissions, and environmental compliance. This section surveys the relevant state-level regulatory environments and identifies the potential GHG compliance costs associated with each state's requirements.
A. West Virginia
Ridgeline's operations in West Virginia are anchored by the System's receipt point at the Wetzel County Interconnect in Wetzel County, the Wetzel Compressor Station and the Mannington Compressor Station (both located in West Virginia), and Ridgeline's principal office at 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301. Approximately 120 miles of the System's 187-mile route traverse West Virginia, and the majority of the System's compression capacity (two of three compressor stations, comprising approximately 30,000 HP of the 45,000 HP total) is located in the state.
Air Quality Permitting. West Virginia's air quality permitting program is administered by the West Virginia Department of Environmental Protection ("WVDEP"), Division of Air Quality ("DAQ"), pursuant to the West Virginia Air Pollution Control Act (W. Va. Code §§ 22-5-1 et seq.) and the state's federally approved State Implementation Plan ("SIP"). Ridgeline's compressor stations in West Virginia operate under Title V operating permits issued by the DAQ, which incorporate federal New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants ("NESHAP") applicable to natural gas transmission and storage facilities.
Current annual air quality compliance costs for the West Virginia compressor stations, including permit fees, emission monitoring, annual emission inventory preparation, and compliance reporting, are estimated at approximately $180,000 to $250,000 per year. These costs are included in the System's current operating and maintenance expenses and are reflected in the base cost of service.
State Income Tax. West Virginia imposes a corporate net income tax at a rate of 6.5%, which, in combination with the 21% federal corporate income tax rate, yields an effective combined income tax rate of approximately 26.13%. This effective tax rate is reflected in the income tax allowance component of the redesigned cost of service. While the state income tax rate is not itself a GHG-related cost, it is relevant to the cost-of-service calculation insofar as any GHG compliance costs that are treated as deductible operating expenses will reduce taxable income and generate a tax benefit that partially offsets the gross cost to the Pipeline. The GHG Tracker Rate calculation should reflect the after-tax impact of GHG compliance costs to avoid over-recovery.
West Virginia's Position on GHG Regulation. West Virginia has historically adopted a cautious approach to GHG regulation, reflecting the state's economic dependence on fossil fuel extraction and combustion. The West Virginia Legislature has not enacted a statewide GHG emissions reduction program, carbon pricing mechanism, or cap-and-trade system. Indeed, West Virginia was a lead plaintiff in West Virginia v. EPA, 597 U.S. 697 (2022), in which the Supreme Court held that the EPA lacked authority under CAA Section 111(d) to adopt a generation-shifting approach to regulating GHG emissions from power plants. The state's political and regulatory posture suggests that West Virginia is unlikely to impose significant independent GHG regulatory burdens on natural gas pipeline operations in the near term.
However, two developments warrant monitoring. First, the WVDEP may be required to adopt state-level emission guidelines for existing oil and gas sources pursuant to the EPA's OOOOc rule, which directs states to submit plans for implementing emission guidelines for existing sources within specified deadlines. The state's compliance with this federal directive will determine the specific regulatory obligations applicable to Ridgeline's West Virginia compressor stations, and any associated compliance costs would fall within the scope of the proposed GHG Cost Tracker.
Second, West Virginia imposes various property, franchise, and severance taxes on natural gas operations, and the possibility of future GHG-related tax levies — whether characterized as environmental impact fees, emission surcharges, or similar assessments — cannot be excluded over the multi-decade useful life of the System. The test-year taxes other than income currently total $3.80 million, reflecting existing property and franchise tax obligations. Any incremental GHG-related tax levies would be appropriately captured by the GHG Cost Tracker mechanism.
B. Pennsylvania. Ridgeline's operations in Pennsylvania center on the Waynesburg Compressor Station, located in Greene County, Pennsylvania, which serves as the System's primary delivery point and houses approximately 15,000 HP of the System's aggregate compression capacity. Approximately 67 miles of the System's route traverse Pennsylvania.
Regional Greenhouse Gas Initiative (RGGI). The most significant potential source of GHG compliance costs for Ridgeline's Pennsylvania operations is the Commonwealth's contested participation in the Regional Greenhouse Gas Initiative. RGGI is a cooperative cap-and-trade program among participating states in the northeastern and mid-Atlantic United States that caps CO₂ emissions from electric generating units and requires covered sources to purchase CO₂ emission allowances at quarterly auctions.
On April 23, 2022, the Pennsylvania Environmental Quality Board published a final rulemaking (52 Pa. Bull. 2038) adopting 25 Pa. Code Chapter 145, Subchapter E, establishing Pennsylvania's CO₂ Budget Trading Program. The rule would require owners and operators of "CO₂ budget sources" — defined generally as fossil fuel-fired electric generating units with a capacity of 25 megawatts or greater — to purchase CO₂ allowances for each ton of CO₂ emitted during each control period.
The direct applicability of Pennsylvania's RGGI rule to Ridgeline's Waynesburg Compressor Station is uncertain. The RGGI program, as adopted by Pennsylvania, targets electric generating units rather than natural gas pipeline compressor stations. However, several factors create potential exposure:
• The definition of "CO₂ budget source" could potentially be expanded through future regulatory amendments to encompass natural gas compressor stations, particularly if the program is extended beyond the power sector.
• Even if Ridgeline's compressor station is not directly subject to RGGI, the Pipeline may be indirectly affected by increased electricity costs resulting from RGGI compliance by electric generators serving the System. Ridgeline purchases electricity for ancillary equipment, lighting, and controls at its compressor stations, and RGGI-driven increases in electricity costs would represent an indirect GHG compliance cost.
• If Pennsylvania expands its carbon pricing program or adopts a broader economy-wide cap-and-trade system — a possibility that has been discussed in the Pennsylvania state legislature — the Waynesburg Compressor Station could become a directly covered source.
We note, however, that Pennsylvania's participation in RGGI faces significant legal challenges. On November 1, 2023, the Commonwealth Court of Pennsylvania ruled in Bowfin KeyCon Holdings LLC v. Pennsylvania Department of Environmental Protection that the RGGI rulemaking exceeded the authority of the Environmental Quality Board and violated the Pennsylvania Air Pollution Control Act. The case is currently on appeal to the Pennsylvania Supreme Court, and the ultimate fate of Pennsylvania's RGGI participation remains uncertain. For purposes of our analysis, we estimate the potential annual cost impact of Pennsylvania RGGI-related obligations on the Waynesburg Compressor Station at $0.5 million to $1.5 million per year, with the wide range reflecting the uncertainty regarding the scope and durability of the program.
Pennsylvania Air Pollution Control Act. Independent of RGGI, Ridgeline's Waynesburg Compressor Station is subject to the Pennsylvania Air Pollution Control Act (35 P.S. §§ 4001–4015) and the implementing regulations of the Pennsylvania Department of Environmental Protection ("PaDEP"), Bureau of Air Quality. The station operates under a Title V operating permit incorporating applicable NSPS and NESHAP requirements. Current annual compliance costs for the Pennsylvania compressor station, including permit fees, emission monitoring, compliance reporting, and source testing, are estimated at approximately $80,000 to $120,000 per year.
Comparative Analysis — ATPC. A comparative analysis of ATPC's treatment of GHG costs is instructive. ATPC, headquartered at 2200 Penn Center West, Suite 300, Pittsburgh, PA 15276, operates its 640-mile interstate pipeline system predominantly in Pennsylvania, with substantial compression capacity. ATPC's FERC Gas Tariff, as most recently revised, does not contain a standalone GHG cost recovery tracker mechanism. ATPC has historically recovered its environmental compliance costs — including GHG-related costs — through its base cost of service, with adjustments made in periodic Section 4 rate filings. However, ATPC has not faced a recent FERC rate case in which GHG cost recovery was specifically at issue, and ATPC's parent, Tidewater Infrastructure Partners LP, may be developing its own approach to GHG cost recovery in light of evolving federal and state requirements.
The absence of a GHG cost tracker in ATPC's existing tariff does not preclude Ridgeline from proposing such a mechanism. To the contrary, Ridgeline's status as a new pipeline with an initial tariff filing provides an opportunity to incorporate forward-looking GHG cost recovery provisions from the outset — an approach that FERC staff has expressly identified as necessary through Deficiency Item 13.
C. Multi-State Compliance Coordination
The fact that Ridgeline's System spans the West Virginia–Pennsylvania border creates coordination challenges that the GHG Cost Tracker mechanism must address. Specifically:
Harmonized compliance approach. Ridgeline must comply with the distinct GHG regulatory frameworks of both states simultaneously. To the extent that West Virginia and Pennsylvania adopt divergent emission standards, monitoring requirements, or carbon pricing mechanisms, Ridgeline will incur state-specific compliance costs that must be appropriately tracked and allocated within the GHG Cost Tracker. The proposed tariff language defines "Applicable GHG Regulations" to include the laws and regulations of any state in which the Pipeline operates, ensuring comprehensive coverage.
Interconnection considerations. The Wetzel County Interconnect, located at ATPC Milepost 412.6, is the point at which the Ridgeline Pipeline System receives natural gas from ATPC's system. The proposed interconnection facilities, estimated at $22.3 million, include metering and measurement equipment (ultrasonic flow meters, gas chromatographs, and SCADA integration) designed to measure gas quality and quantity at the interconnection point. In light of the emerging GHG regulatory framework, Ridgeline and ATPC should consider whether GHG monitoring equipment — such as continuous emission monitoring systems ("CEMS") or methane detection sensors — should be incorporated into the interconnection metering station design. The incremental cost of integrating GHG monitoring equipment into the metering station is estimated at $250,000 to $500,000 (one-time capital cost), which could be included in the interconnection facilities cost and allocated between Ridgeline and ATPC pursuant to the interconnection agreement.
upstream/downstream GHG cost allocation. To the extent that GHG emissions at the Wetzel County Interconnect point are attributable to upstream activities on ATPC's system (e.g., methane slip or venting from ATPC's transmission operations) versus downstream activities on Ridgeline's system, questions of GHG cost allocation between the two pipelines may arise. The proposed GHG Cost Tracker mechanism is designed to recover only those GHG compliance costs that are directly attributable to Ridgeline's own operations and for which Ridgeline is legally liable. Costs attributable to ATPC's operations or emissions would not be included in Ridgeline's tracker.
V. FERC Policy on GHG Cost Recovery in Natural Gas Pipeline Tariffs
A. Current FERC Framework
The Federal Energy Regulatory Commission exercises jurisdiction over the rates, terms, and conditions of interstate natural gas pipeline transportation service pursuant to Sections 4 and 5 of the Natural Gas Act, 15 U.S.C. §§ 717c and 717d, and the Commission's implementing regulations at 18 C.F.R. Part 154. Under the NGA's regulatory framework, a pipeline's rates must be "just and reasonable" (NGA § 4(a)) and may not include any "undue preference or advantage" or "unreasonable difference in rates" (NGA § 4(b)). The Commission determines just and reasonable rates primarily through cost-of-service ratemaking, in which the pipeline's total cost of service — comprising return on rate base, depreciation, operations and maintenance expenses, administrative and general expenses, taxes, and revenue credits — is allocated among the pipeline's shippers on the basis of appropriate billing determinants.
Within this framework, GHG compliance costs represent a category of operating expense that must be addressed through the tariff rate structure. The critical analytical question is whether GHG compliance costs are properly characterized as "known and measurable" costs — i.e., costs that can be quantified with reasonable certainty and included in the pipeline's base cost of service at the time of a Section 4 rate filing — or as contingent, prospective, or variable costs that are more appropriately addressed through a tracker or surcharge mechanism.
This distinction is fundamental to the design of the GHG cost recovery mechanism. Known-and-measurable costs are "baked into" the base recourse rate at the time of the rate filing and remain fixed until the pipeline files a new Section 4 rate case or FERC initiates a Section 5 investigation. Tracker mechanisms, by contrast, allow for periodic (typically annual) adjustments to a separate rate component to reflect changes in specified cost categories, without the need for a full rate case filing.
FERC has long recognized the appropriateness of tracker mechanisms for cost categories that are: (i) subject to significant variability or uncertainty; (ii) driven by external regulatory requirements outside the pipeline's control; (iii) material in magnitude; and (iv) susceptible to reasonably accurate quantification on a periodic basis. GHG compliance costs exhibit all four of these characteristics, and the tracker approach is therefore well-suited to this cost category.
B. FERC Policy Statements and Orders on Environmental Costs
The Commission's evolving treatment of environmental compliance costs in the natural gas pipeline context provides important guidance for the design of Ridgeline's GHG Cost Tracker mechanism.
2022 Updated Policy Statement on Certification. On February 18, 2022, the Commission issued an Updated Policy Statement on Certification of New Interstate Natural Gas Facilities (178 FERC ¶ 61,107), which established a new framework for evaluating the environmental impact of proposed natural gas pipeline projects, including an assessment of GHG emissions. Although the Policy Statement was subsequently designated as a "draft" policy statement following industry and Congressional criticism, and its legal status remains somewhat unsettled, it reflects the Commission's increasing attention to GHG considerations in the natural gas pipeline context. The Policy Statement discussed, among other things, the Commission's interest in understanding the "reasonably foreseeable" GHG emissions associated with a proposed pipeline project and the extent to which those emissions would be mitigated.
While the Certification Policy Statement primarily addresses the Commission's certificate evaluation process rather than rate design, it is relevant to the GHG cost recovery analysis insofar as it signals the Commission's expectation that pipeline operators will address GHG emissions comprehensively — including the costs associated with monitoring, reporting, and mitigating those emissions. Deficiency Item 13 can be understood as the rate-side corollary of the Certificate Policy Statement's GHG assessment requirements.
Interim GHG Significance Thresholds. In connection with the 2022 Policy Statement, the Commission discussed the establishment of GHG significance thresholds that would trigger enhanced environmental review and potential mitigation requirements for proposed pipeline projects. Although no final threshold has been adopted, the Commission's discussion of significance thresholds (at both 100,000 and 300,000 metric tons of CO₂e per year) further underscores the regulatory salience of GHG emissions in the natural gas pipeline sector. Ridgeline's estimated annual emissions of 85,000 to 120,000 metric tons of CO₂e fall within the range that the Commission has identified as potentially significant.
Treatment of Environmental Compliance Costs in Rate Cases. FERC has consistently permitted pipelines to include documented, known-and-measurable environmental compliance costs in their cost of service as part of the operations and maintenance expense category. These costs may include air quality monitoring and reporting expenses, environmental remediation costs, and regulatory compliance program expenses. However, the Commission has also recognized that environmental compliance costs may be appropriately addressed through tracker mechanisms when the costs are subject to significant variability or are driven by regulatory requirements that may change during the rate period.
Precedent for Tracker Mechanisms. The Commission has approved range tracker mechanisms in natural gas pipeline tariffs, including:
• Fuel, Lost, and Unaccounted-for Gas ("FL&U") Trackers. FL&U trackers are the most common and well-established form of tracker mechanism in FERC-jurisdictional pipeline tariffs. These trackers allow pipelines to adjust a separate rate component annually (or more frequently) to reflect actual fuel consumption and gas losses, without the need for a full rate case. The FL&U tracker mechanism is directly analogous to the proposed GHG Cost Tracker in structure and purpose. We note that Deficiency Item 2 in the Ridgeline Deficiency Letter also required the inclusion of an FL&U tracker, and the GHG Cost Tracker is designed to be structurally consistent with and complementary to the FL&U tracker mechanism.
• Electric Power Cost Trackers. Several pipelines have obtained FERC approval for tracker mechanisms that adjust rates to reflect changes in the cost of electricity used to power electric-driven compression, which is a cost category subject to variability based on wholesale electricity market conditions.
• Tax Rate Change Trackers. Following the Tax Cuts and Jobs Act of 2017, which reduced the federal corporate income tax rate from 35% to 21%, FERC approved tracker mechanisms to flow through the tax rate change to shippers.
The structural features of these approved tracker mechanisms — annual filing, true-up procedures, shipper protest rights, and Commission oversight — provide the template for the proposed GHG Cost Tracker.
Rolled-In vs. Surcharge Treatment. FERC has generally expressed a preference for "rolled-in" cost-of-service treatment for routine, ongoing operating costs, and has reserved surcharge or tracker treatment for cost categories that are variable, uncertain, or driven by external factors. GHG compliance costs exhibit characteristics of both categories: some costs (e.g., annual reporting fees) are relatively stable and predictable, while others (e.g., methane fee charges, carbon pricing costs) are highly variable and subject to regulatory change. The proposed GHG Cost Tracker mechanism represents a pragmatic compromise, treating GHG compliance costs as a separate surcharge that is transparent to shippers and adjustable on an annual basis, while avoiding the need to embed volatile cost assumptions in the base recourse rate.
C. FERC Precedent — Comparable Pipeline Tariff Provisions
As part of our analysis, we conducted a survey of FERC-jurisdictional pipeline tariffs to identify existing GHG or environmental cost recovery provisions that could serve as models for the Ridgeline tariff. The results of this survey are summarized in full at Appendix A; key findings are presented here.
Of the eight comparable FERC-jurisdictional pipelines surveyed — selected on the basis of geographic location (Appalachian Basin or adjacent regions), pipeline diameter and capacity (20-inch to 36-inch diameter, 0.5 to 4.0 Bcf/d capacity), and recency of rate filing (Section 4 filings or initial tariff filings within the past five years) — we identified three that have adopted tariff provisions specifically addressing GHG or environmental compliance cost recovery:
1. Pipeline A (name withheld pending privilege review) adopted an "Environmental Compliance Cost Tracker" in its FERC Gas Tariff in connection with a 2021 Section 4 rate case settlement. The tracker covers "costs incurred by Pipeline in compliance with Environmental Laws and Regulations, including but not limited to greenhouse gas emission regulations, air quality standards, and water quality requirements." The tracker provides for annual filings with a 180-day true-up period, subject to a rate cap of $0.008/Dth per year.
2. Pipeline B included a "Carbon Cost Recovery Surcharge" provision in its initial tariff filing in 2022, specifically designed to address the anticipated costs of compliance with the IRA methane fee and potential state-level carbon pricing programs. The surcharge is calculated annually based on projected carbon-related costs, with a quarterly true-up mechanism and no rate cap. The tariff provision was approved by FERC without modification as part of an uncontested settlement.
3. Pipeline C adopted a general "Regulatory Compliance Cost Tracker" that encompasses a broader range of regulatory compliance costs, including GHG-related costs, safety compliance costs, and cybersecurity compliance costs. The tracker provides for semi-annual filings with shipper protest rights and independent audit requirements.
The remaining five pipelines surveyed do not have standalone GHG cost recovery provisions and recover environmental compliance costs through their base cost of service. However, several of these pipelines have pending Section 4 rate cases or anticipated rate filings in which GHG cost recovery provisions may be introduced.
Key observations from the survey include:
• Annual filing and true-up procedures are the most common structural feature, reflecting FERC's preference for periodic cost verification and adjustment.
• Shipper protections — including rate caps, protest rights, and independent audit or verification requirements — are consistently included and appear to be expected by FERC staff as a condition of approval.
• Broad definitions of covered cost categories are preferred over narrow enumerations, providing flexibility to accommodate evolving regulatory requirements while maintaining transparency through itemized supporting documentation.
• Separation from FL&U tracker mechanisms is important to avoid confusion or double-counting, as some GHG compliance costs (e.g., methane emissions from compressor stations) may overlap with fuel-use and lost-and-unaccounted-for gas measurement issues.
D. FERC Trial Staff Position
Based on our experience with the proceeding and our analysis of the Deficiency Letter, we anticipate that FERC Trial Staff will be generally supportive of a well-designed GHG Cost Tracker mechanism, given that Item 13 of the Deficiency Letter expressly directed Ridgeline to include GHG cost recovery provisions in the Tariff. However, staff's support is likely to be conditioned on several factors:
Lead Trial Attorney Jonathan Briggs has not taken a public position on GHG cost recovery mechanisms in natural gas pipeline tariffs, but his involvement in recent proceedings involving environmental compliance cost issues suggests a preference for transparency, documentation, and shipper protections. We anticipate that Mr. Briggs will scrutinize the proposed mechanism for any potential for over-recovery, cross-subsidization, or inclusion of costs that are properly borne by the Pipeline's equity owners rather than its shippers.
Lead Economic Analyst Dr. Miriam Okafor, who authored the Deficiency Letter language directing Ridgeline to address GHG cost recovery, is likely to evaluate the proposed mechanism against her analytical framework for cost tracker design. Based on the specificity of her Deficiency Letter language — which referenced the IRA methane fee provisions and state carbon pricing programs by name — we anticipate that Dr. Okafor will expect the tariff language to address each of these specific regulatory programs, with supporting cost estimates and allocation methodologies.
Anticipated staff concerns include:
• Cost pass-through limitations. Staff may seek to ensure that the Pipeline does not simply pass through all GHG-related costs to shippers without taking reasonable steps to minimize those costs. The proposed annual cap of $0.005/Dth addresses this concern by cre

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