memo-order-2222-renewable-interconnection.docx

1016-00005 · Dunmore Energy Holdings · Tariff Redesign

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MEMORANDUM

FROM: Calderwood & Harkness LLP George Trujillo, Partner (Responsible Partner, Energy & Infrastructure Practice) Brett Callahan, Associate (Lead Associate, Energy & Infrastructure Practice)

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

DATE: May 15, 2024

RE: FERC Order No. 2222 — Implications for Distributed Energy Resource Aggregation and Renewable Energy Interconnection at the Ridgeline Pipeline System; Response to Deficiency Item 14

MATTER: C&H Matter No. 1016-00005

DOCKET NOS.: RP22-847-000 (rate case); RP22-847-001 (interconnection)

PRIVILEGED & CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION / ATTORNEY WORK PRODUCT

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I. Executive Summary

This memorandum analyzes the Federal Energy Regulatory Commission's ("FERC" or the "Commission") Order No. 2222 and its implications for the redesigned FERC Gas Tariff, Original Volume No. 1, of Ridgeline Midstream Services LLC ("Ridgeline"), with specific focus on addressing Deficiency Item 14 of the January 19, 2023 Deficiency Letter issued by FERC's Office of Energy Market Regulation (Dr. Miriam Okafor, Lead Economic Analyst) (the "Deficiency Letter"). This memorandum is intended to guide the development of proposed tariff language responsive to Deficiency Item 14 and to inform the broader tariff redesign effort currently underway.

Deficiency Item 14 identified Ridgeline's failure to address Order No. 2222 distributed energy resource ("DER") aggregation implications, including renewable energy interconnection, in its original tariff filing. The Deficiency Letter stated, in relevant part, that Ridgeline's proposed tariff "contains no provisions addressing the potential for DER aggregations to affect pipeline operations, scheduling, or tariff design" and requested that Ridgeline supplement its filing with provisions responsive to these concerns. The full text of Deficiency Item 14 is reproduced at Appendix A to this memorandum.

This memorandum is being prepared in coordination with Braswell Energy Consulting Group LLC ("Braswell"), Engagement No. BEC-2023-0041, under the direction of lead consultant Dr. Raymond Braswell, a former FERC economist who was engaged on April 15, 2023 to lead the comprehensive tariff redesign necessitated by the Deficiency Letter. Braswell's engagement encompasses all fourteen deficiency items, and the analysis and recommendations set forth in this memorandum are intended to be integrated into the revised cost-of-service model and tariff drafting currently being undertaken by Braswell in consultation with Ridgeline's in-house regulatory team.

The nexus between Order No. 2222 — a rulemaking directed at regional transmission organizations ("RTOs") and independent system operators ("ISOs") in the electric sector — and Ridgeline's natural gas pipeline tariff requires careful analysis. While Order No. 2222 does not directly impose obligations on interstate natural gas pipelines, the Order's facilitation of DER aggregation participation in wholesale electricity markets has material implications for gas-fired electric generation facilities served by pipelines like Ridgeline, and consequently for pipeline demand patterns, scheduling, and tariff design. These implications are heightened in Ridgeline's case by the fact that Dunmore Energy Holdings Ltd. ("DEH"), Ridgeline's sole member, owns and is developing a 250 MW wind portfolio in the Appalachian region. DEH's dual role as both a natural gas midstream operator and a renewable energy developer positions the company — and by extension, the Ridgeline Pipeline System — at a critical intersection of the gas and electric sectors that Order No. 2222 was designed to reshape.

Based on our analysis of Order No. 2222 and its progeny, the specific requirements of Deficiency Item 14, relevant industry precedent, and the unique commercial and regulatory context of the Ridgeline Pipeline System and DEH's broader energy portfolio, we recommend the following:

1. New Tariff Section. The addition of a new section to the General Terms and Conditions of the redesigned tariff titled "Gas-Electric Coordination and Distributed Energy Resource Provisions," containing subsections addressing definitions, enhanced intraday nomination and scheduling flexibility, expedited operational flow order ("OFO") procedures, information-sharing protocols, periodic billing determinant review mechanisms, affiliate transaction safeguards, electronic bulletin board ("EBB") posting requirements, and a cost recovery mechanism for DER-driven operational costs.

2. Conforming Amendments. Conforming amendments to existing tariff sections, including Rate Schedules FT-1 and IT-1, and multiple provisions within the General Terms and Conditions addressing nominations, OFOs, EBB, and creditworthiness.

3. Coordination with Other Deficiency Item Responses. The proposed provisions must be coordinated with responses to Deficiency Items 2 (FL&U tracker), 5 (capacity release), 6 (NAESB compliance), 7 (EBB requirements), 10 (penalty revenue crediting), 11 (creditworthiness), 12 (segmentation and flexible receipt/delivery points), and 13 (GHG cost recovery) to ensure internal consistency across the redesigned tariff.

4. Affiliate Transaction Safeguards. Robust provisions prohibiting preferential treatment of DEH's wind portfolio or affiliated generation resources, consistent with FERC's Standards of Conduct at 18 C.F.R. Part 358 and the Commission's affiliate transaction policies.

The filing deadline for the supplemental response addressing all remaining deficiency items, including Item 14, is February 21, 2025, as established by Administrative Law Judge Clara Whitfield's March 4, 2024 order granting Ridgeline's third request for extension of time, subject to conditions including the filing of quarterly status reports. Three such quarterly reports have been filed to date (June 15, 2024; September 14, 2024; and December 13, 2024), and the proceeding has been classified as "dormant" by the Commission's Office of the Secretary since September 8, 2023.

The balance of this memorandum sets forth the factual and procedural background, a detailed analysis of Order No. 2222, the nexus between the Order and natural gas pipeline tariffs, our assessment of required tariff provisions, a survey of industry precedent, a summary of proposed tariff language recommendations, a risk assessment, settlement implications, coordination requirements with Braswell, and a timeline for next steps through the February 2025 filing deadline.

II. Background

A. The Ridgeline Pipeline System and DEH's Energy Portfolio

Ridgeline Midstream Services LLC is a Delaware limited liability company and a wholly owned subsidiary of Dunmore Energy Holdings Ltd. ("DEH"), a Cayman Islands exempted limited company, Registry No. CR-381204. Patricia Dunmore, the founder and chairperson of DEH, holds a 72% equity interest in DEH, with the remaining 28% held by institutional investors through a series of preferred equity instruments issued in connection with the Ridgeline Pipeline System's original construction financing. Ms. Dunmore's role as the controlling equity holder of DEH and as the C&H billing partner on this engagement has been fully disclosed and waived in accordance with applicable rules of professional conduct, as documented in the engagement letter dated March 22, 2022 and the supplemental conflict waiver executed on April 3, 2022.

The Ridgeline Pipeline System is a 187-mile, 24-inch-diameter high-pressure natural gas transportation pipeline located in West Virginia and Pennsylvania. The system was placed in service on October 1, 2021, following an original construction program costing approximately $587.2 million (inclusive of allowance for funds used during construction and capitalized overhead). The pipeline extends from a receipt point at the Wetzel County Interconnect in Wetzel County, West Virginia (39.6120° N, 80.7540° W) to a delivery point at the Waynesburg Compressor Station in Greene County, Pennsylvania (39.8965° N, 80.1810° W). The system is equipped with three compressor stations — the Wetzel Compressor Station (located at the receipt point), the Mannington Compressor Station (approximately milepost 88, in Marion County, West Virginia), and the Waynesburg Compressor Station (located at the delivery point) — with aggregate installed compression of 45,000 horsepower ("HP"). The design capacity of the system is 1.2 billion cubic feet per day ("Bcf/d"), equivalent to 1,200,000 dekatherms per day ("Dth/d"), assuming maximum operating pressure and full utilization of available compression. As of the most recent operational data available to us, current throughput is approximately 680 million cubic feet per day ("MMcf/d"), representing a utilization rate of approximately 56.67% of design capacity.

The Ridgeline Pipeline System was designed to transport natural gas produced from the Marcellus and Utica shale formations in northern West Virginia to interconnection points with downstream pipeline systems and distribution utilities in southwestern Pennsylvania. The pipeline's primary interconnection is with Appalachian Trunk Pipeline Company, LLC ("ATPC") at the Wetzel County Interconnect, which is the subject of the interconnection authorization proceeding at Docket No. RP22-847-001.

DEH's broader energy portfolio extends well beyond the Ridgeline Pipeline System. As of December 31, 2023, DEH owned and operated approximately 1,200 miles of midstream gathering and transportation pipelines across the Appalachian Basin, together with two cryogenic natural gas processing plants with aggregate processing capacity of approximately 800 MMcf/d. DEH's estimated enterprise value, based on internal valuation methodologies as of December 31, 2023, is approximately $2.8 billion. Consolidated annual revenue for the fiscal year ended December 31, 2023 was approximately $485 million.

Of particular relevance to this memorandum, DEH is also developing a 250 MW wind portfolio in the Appalachian region. The exact locations of the planned wind facilities have not yet been publicly disclosed, although DEH has indicated in investor presentations and public filings that the projects are in various stages of development, with commercial operation dates anticipated between 2026 and 2028. The 250 MW wind portfolio is a cornerstone of DEH's stated strategy to diversify its energy portfolio beyond natural gas midstream operations and to position the company as a participant in the growing renewable energy sector. This dual identity — as both a natural gas midstream operator and a renewable energy developer — is directly relevant to the Order No. 2222 analysis, because it means that DEH and its subsidiaries will be active participants on both sides of the gas-electric coordination equation. The Ridgeline tariff must be drafted with awareness of this reality, including the potential for affiliate transaction issues and the need for provisions that address the interaction between gas-fired generation served by the pipeline and DER aggregations that may include DEH's own renewable energy resources.

B. Procedural History and Deficiency Item 14

The procedural history of this matter is extensive and reflects the complexity of the issues involved. We summarize below the key events leading to the current posture of the proceeding, with particular emphasis on the genesis and substance of Deficiency Item 14.

On May 12, 2022, Ridgeline filed its application for initial tariff rate and interconnection authorization with the Commission, initiating the proceedings at Docket Nos. RP22-847-000 (rate case) and RP22-847-001 (interconnection). The application proposed an initial recourse rate of $0.2265 per Dth, comprising a reservation charge of $0.2223 per Dth and a usage charge of $0.0042 per Dth. The proposed rate was based on a rate base of $612.40 million, a total cost of service of $97.36 million, a return on equity ("ROE") of 14.00%, and billing determinants calculated using a 100% load factor. The filing was accompanied by a proposed FERC Gas Tariff, Original Volume No. 1, containing rate schedules and general terms and conditions in conformity with the Commission's regulations at 18 C.F.R. Part 154.

The application also sought authorization for interconnection with ATPC at the Wetzel County Interconnect, with total interconnection facilities estimated at $22.3 million. The interconnection facilities would be jointly owned and operated by Ridgeline and ATPC under a proposed Construction, Ownership, and Operating Agreement ("COOA"), the terms of which were included in the filing.

Multiple parties intervened in the proceeding. On August 15, 2022, ATPC filed a protest and motion to intervene, represented by William Pratt of Kellner, Royce & Dillard LLP. ATPC's protest raised concerns regarding, inter alia, the proposed allocation of interconnection costs, the appropriateness of a 100% load factor, and the proposed ROE of 14.00%, which ATPC characterized as "substantially in excess of the range of reasonableness as established by Commission precedent." On July 28, 2022, the Mountainside Gas Producers Coalition ("MGPC"), a coalition of fourteen independent natural gas producers operating in the Marcellus and Utica shale formations, filed a motion to intervene through its Executive Director, Calvin Dreyer, and counsel of record, Rebekah Montague of Whitmore & Sable LLP. MGPC raised concerns regarding the proposed rate level, load factor assumptions, and cost allocation methodology. On August 1, 2022, Clearwater Municipal Gas Authority ("CMGA"), a municipal gas distribution utility serving approximately 42,000 customers in Greene and Washington Counties, Pennsylvania, filed a motion to intervene through its General Manager, Dennis Ott, and counsel of record, Stephen Greer of Fordham Municipal Law Group PC. CMGA expressed interest in ensuring that the tariff provisions adequately protect end-use customers and municipal distribution utilities.

On September 22, 2022, the Commission issued an order granting all pending interventions, setting the proceeding for hearing under a Track II procedural schedule, and appointing Settlement Judge Howard Margolis to oversee settlement negotiations. The procedural schedule established dates for direct testimony, responsive testimony, cross-answering testimony, and hearing.

On December 5, 2022, Ridgeline filed the direct testimony and exhibits of seven witnesses, covering topics including cost of service, rate design, depreciation, return on equity, pipeline operations, interconnection engineering, and tariff terms and conditions.

On January 19, 2023, the Commission's Office of Energy Market Regulation issued the Deficiency Letter, identifying fourteen deficiencies in Ridgeline's tariff filing. The Deficiency Letter was prepared under the direction of Dr. Miriam Okafor, Lead Economic Analyst, and signed by the Director of the Office of Energy Market Regulation. The fourteen deficiencies spanned a wide range of issues, from fuel, lost, and unaccounted-for gas tracking mechanisms (Item 2) to creditworthiness provisions (Item 11) to greenhouse gas cost recovery (Item 13).

Deficiency Item 14 is the focus of this memorandum. The item stated, in its entirety:

"The proposed tariff fails to address the implications of Commission Order No. 2222, Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, 172 FERC ¶ 61,247 (2020), for distributed energy resource aggregation and renewable energy interconnection. The Applicant's proposed tariff contains no provisions addressing the potential for DER aggregations to affect pipeline operations, scheduling, or tariff design. Given the Applicant's parent company's publicly disclosed development of renewable energy resources, the Commission Staff requires the Applicant to supplement its filing with provisions that adequately address the implications of Order No. 2222 for the proposed tariff, including but not limited to the potential impact of DER aggregation growth on gas demand patterns, operational coordination between gas pipeline scheduling and electric market dispatch, and provisions for renewable energy interconnection scenarios relevant to the Applicant's system."

The Deficiency Letter established a response deadline of ninety days (April 19, 2023). On February 6, 2023, ALJ Whitfield issued an order staying the procedural schedule pending resolution of the deficiency items. On March 15, 2023, Ridgeline filed a partial response to the Deficiency Letter, addressing eight of the fourteen items (Items 1, 3, 4, 8, 9, 10, 11, and a partial response to Item 6). Item 14 was not among the items addressed in the partial response, as Ridgeline determined that a comprehensive analysis was required before a substantive response could be prepared.

On April 15, 2023, Ridgeline engaged Braswell Energy Consulting Group LLC to lead the comprehensive tariff redesign necessitated by the remaining deficiency items. Dr. Raymond Braswell, the firm's founder and principal consultant, assumed responsibility for the engagement under Engagement No. BEC-2023-0041. Dr. Braswell's scope of work encompasses the full revision of the tariff to address all fourteen deficiency items, including the development of revised cost-of-service calculations, rate design methodology, and tariff language.

Ridgeline has sought and obtained multiple extensions of the filing deadline. The original ninety-day deadline (April 19, 2023) was extended by agreement to August 18, 2023 (first extension), then to December 15, 2023 (second extension), and most recently to February 21, 2025, pursuant to ALJ Whitfield's March 4, 2024 order granting Ridgeline's third request for extension. The March 4, 2024 order imposed conditions on the extension, including the requirement that Ridgeline file quarterly status reports with the Commission detailing progress on the tariff redesign and the expected timeline for addressing remaining deficiency items. Three quarterly status reports have been filed to date: June 15, 2024; September 14, 2024; and December 13, 2024.

The proceeding has been classified as "dormant" by the Commission's Office of the Secretary since September 8, 2023. No contested hearing has been scheduled, and the procedural schedule remains stayed pending the supplemental filing.

C. The Tariff Redesign Context

The tariff redesign is proceeding under the joint direction of Braswell, Calderwood & Harkness, and Ridgeline's in-house regulatory team, led by Dr. Natasha Orlov, Director of Rates & Regulatory. The redesign reflects substantial changes from the original filing, driven by both the deficiency items and by the evolution of Ridgeline's operating and financial circumstances since May 2022.

Key changes from the original filing include:

• Load factor: The proposed load factor has been reduced from 100% to 75%, reflecting Ridgeline's actual throughput experience (56.67% utilization as of the most recent data) and a more conservative projection of system utilization over the initial rate period. The revised 75% load factor yields billing determinants of 328,500,000 Dth per year, down from the originally proposed 438,000,000 Dth per year.

• Return on equity: The proposed ROE has been reduced from 14.00% to 12.50%. This reduction reflects a reassessment of market conditions, including declining risk-free rates since the original filing and recognition that the original 14.00% proposal substantially exceeded the range of returns approved by the Commission in recent pipeline rate cases. The revised 12.50% ROE, while still above the intervenors' positions (10.75% proposed by ATPC; 11.25% proposed by MGPC), represents a significant movement toward a zone of potential settlement.

• Weighted average cost of capital: The revised weighted average cost of capital ("WACC") is 9.2375%, reflecting the reduced ROE and adjustments to the capital structure assumptions in the original filing.

• Total cost of service: The revised total cost of service is $103.15 million, an increase from the original $97.36 million. The increase is attributable primarily to updated depreciation rates, revised estimates of operations and maintenance expenses (including costs associated with the tariff redesign itself), and the incorporation of additional cost elements identified through the deficiency item analysis.

• Revised proposed recourse rate: The revised proposed recourse rate is $0.3140 per Dth, comprising a reservation charge of $0.3102 per Dth and a usage charge of $0.0038 per Dth. The increase from the original proposed rate of $0.2265 per Dth is driven primarily by the reduction in the load factor from 100% to 75% (which reduces billing determinants and increases the per-unit rate necessary to recover the cost of service) and the increase in the total cost of service.

The current working version of the revised tariff is the fourth draft, dated November 2024. It is into this version that the Order No. 2222 provisions recommended in this memorandum must be incorporated. We note that the fourth draft reflects the cumulative results of the tariff redesign effort to date, including responses to all deficiency items other than Item 14 and certain aspects of Items 12 and 13 that remain in progress.

Settlement discussions among the parties remain ongoing but have not produced agreement. Four formal settlement conferences have been conducted before Settlement Judge Margolis: November 30, 2022; March 8, 2023; July 12, 2023; and January 18, 2024. The parties remain approximately $0.058 per Dth apart, with Ridgeline maintaining a floor position of $0.3140 per Dth and the ATPC/MGPC coalition maintaining a ceiling position of approximately $0.2560 per Dth. CMGA has generally aligned with the intervenors on rate level but has indicated flexibility on certain tariff terms and conditions. The settlement dynamics are discussed further in Section IX of this memorandum.

III. Overview of FERC Order No. 2222

A. Regulatory History and Objectives

FERC Order No. 2222, titled Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, was issued on September 17, 2020 in Docket No. RM18-9-000. 172 FERC ¶ 61,247 (2020). The Order became effective on March 1, 2021, and required RTO/ISO tariff compliance filings within a specified timeframe.

The Order represented the culmination of a multi-year rulemaking process that began with the Commission's issuance of a Notice of Proposed Rulemaking ("NOPR") on November 17, 2016 (Docket No. RM18-9-000, 157 FERC ¶ 61,121). The NOPR, in turn, was preceded by several years of Commission engagement with the issue of DER participation in wholesale markets, including a 2015 technical conference on DER aggregation and the Commission's growing recognition that the rapid proliferation of distributed energy technologies — solar photovoltaic systems, battery storage, demand response, smart thermostats, electric vehicles, and other behind-the-meter resources — was creating a significant pool of energy resources that could, in aggregate, provide meaningful services to the wholesale electric grid but were effectively barred from participation by existing RTO/ISO market rules.

The Commission's stated objective in issuing Order No. 2222 was to "remove barriers to the participation of distributed energy resource aggregations in the organized wholesale electric energy, capacity, and ancillary services markets operated by regional transmission organizations and independent system operators." The Commission found that existing RTO/ISO tariffs either did not permit DER aggregations to participate in wholesale markets or imposed minimum size thresholds and other participation requirements that effectively excluded the vast majority of DERs. The Commission concluded that these barriers "may result in unjust and unreasonable rates" and that the removal of such barriers would "enhance competition" and "help ensure that the wholesale electricity markets produce just and reasonable rates."

Order No. 2222 defined "distributed energy resource" broadly. Under the Order, a DER is "any resource located on the distribution system, any subsystem thereof, or behind a customer meter." The definition encompasses, without limitation, electric storage resources, distributed generation (including rooftop solar, small wind, and combined heat and power systems), demand response resources, energy efficiency resources, thermal storage resources, and electric vehicles capable of providing grid services. The breadth of this definition is significant because it means that the DER aggregations contemplated by the Order may include a wide and heterogeneous mix of technologies, each with different operational characteristics, response times, and impacts on the broader energy system — including the natural gas system.

B. Key Provisions of Order No. 2222

The operative provisions of Order No. 2222 are directed at RTOs and ISOs, requiring each to revise its tariff to accommodate DER aggregation participation. The key provisions are as follows:

DER Aggregation Participation. RTOs and ISOs must allow DER aggregators to register aggregations of individual DERs to participate in the wholesale markets operated by the RTO or ISO. An aggregator may be any entity that meets the RTO's/ISO's participation requirements, including third-party aggregators, distribution utilities, and, in some cases, the DER owners themselves. The aggregation model allows multiple small DERs — none of which would individually meet minimum size requirements for wholesale market participation — to be combined into a single, dispatchable resource that can bid into and be dispatched by the RTO/ISO markets.

Minimum Size Thresholds. The Order prohibits RTOs and ISOs from establishing minimum size requirements for DER aggregations that exceed 100 kilowatts ("kW"). This is a significant provision because it ensures that even very small aggregations — as few as two or three residential-scale resources — can, in principle, participate in wholesale markets if they meet other participation requirements.

Locational Requirements. DER aggregations must be located within a single pricing node (i.e., a single locational marginal price or "LMP" zone) for purposes of market participation. The Order includes limited exceptions for DERs served by small utilities and for aggregations in areas where the pricing node structure is sufficiently granular to accommodate geographically dispersed DERs. These locational requirements are relevant to the gas-electric coordination analysis because they determine the geographic areas in which DER aggregations may compete with or displace gas-fired generation.

Participation Models. The Order requires RTOs and ISOs to establish participation models for DER aggregations that encompass all types of DER technologies. This means that a single aggregation may include a mix of solar, storage, demand response, and other DER types, and the RTO/ISO must have market rules capable of dispatching and settling such heterogeneous aggregations.

Metering and Telemetry. DER aggregators are responsible for the metering of individual DERs within the aggregation, subject to metering and telemetry requirements established by the RTO/ISO. The RTO/ISO may require sub-metering of individual DERs for settlement purposes, real-time or near-real-time telemetry for dispatch purposes, and performance verification testing.

Distribution Utility Coordination. Order No. 2222 addresses the relationship between DER aggregators, distribution utilities, and the RTO/ISO. The Order recognizes that DER aggregations operate on the distribution system and that their dispatch by the RTO/ISO could have implications for distribution system reliability and operations. The Order requires coordination protocols between the DER aggregator, the relevant distribution utility, and the RTO/ISO to ensure that DER dispatch does not create reliability concerns on the distribution system.

Dual Participation. The Order includes provisions addressing DERs that participate in both wholesale markets (through the RTO/ISO) and retail programs (through the distribution utility or state commission). The Order generally permits dual participation but requires adequate accounting mechanisms to prevent double-counting of services and to ensure that the DER's contribution to the wholesale market does not compromise its commitments under retail programs.

C. Order No. 2222-A and Subsequent Clarifications

On March 18, 2021, the Commission issued Order No. 2222-A, a rehearing order that clarified certain provisions of the original Order. 175 FERC ¶ 61,197 (2021). Among the clarifications, Order No. 2222-A addressed the treatment of states with retail choice, providing that DERs in retail choice states could opt in to wholesale market participation through DER aggregations even where the state commission had not affirmatively authorized such participation. Order No. 2222-A also clarified certain aspects of the distribution utility coordination requirements and the metering and telemetry provisions.

Subsequent to Order No. 2222-A, the Commission has issued a series of orders on the compliance filings submitted by individual RTOs and ISOs. These compliance orders have addressed RTO/ISO-specific implementation issues and have provided additional guidance on the application of the Order's requirements in different market contexts. As of the date of this memorandum, compliance proceedings remain pending before several RTOs/ISOs, including PJM Interconnection, LLC ("PJM"), which is the RTO most relevant to the Ridgeline Pipeline System given PJM's coverage of the Pennsylvania and West Virginia markets served by the pipeline.

While Order No. 2222 was directed primarily at RTOs and ISOs in the electric sector and does not, on its face, impose obligations on interstate natural gas pipelines regulated under the Natural Gas Act ("NGA") and the Natural Gas Policy Act ("NGPA"), the Commission has signaled a growing interest in gas-electric coordination and the impact of DER growth on natural gas demand patterns. This interest is reflected in the Deficiency Letter's inclusion of Item 14, which, as discussed below, requires Ridgeline to address Order No. 2222's implications for its tariff despite the fact that the Order's direct legal obligations run to electric-sector entities. The Commission's approach in Item 14 is consistent with its broader policy of encouraging natural gas pipelines to consider gas-electric interdependencies in their tariff filings and operations planning, a theme that has been developing since at least the polar vortex events of 2013-2014 and the issuance of Order No. 809 in 2015.

IV. Nexus Between Order No. 2222 and Natural Gas Pipeline Tariffs

A. Gas-Electric Interdependence

The fundamental nexus between Order No. 2222 and natural gas pipeline tariffs is the deep and growing interdependence between the natural gas and electric power sectors. Natural gas pipelines serve gas-fired electric generation facilities — including combined-cycle plants, combustion turbines, and peaking units — that are major consumers of pipeline transportation capacity and significant drivers of pipeline throughput and revenue. Gas-fired generation is the single largest source of electricity in the United States, accounting for approximately 43% of total electricity generation in 2023 according to the U.S. Energy Information Administration. In the PJM footprint, which encompasses the geographic area served by the Ridgeline Pipeline System, gas-fired generation represents a substantial and growing share of the generation fleet, driven by the retirement of coal-fired plants and the construction of new gas-fired facilities to support grid reliability.

The growth of DER aggregations, as facilitated by Order No. 2222, has the potential to alter gas demand profiles in several significant ways:

• Reduction in baseload gas-fired generation. As DER aggregations provide increasing quantities of energy, capacity, and ancillary services to the wholesale electric market, they may displace some portion of baseload gas-fired generation. Solar and wind resources within DER aggregations produce energy during periods of high resource availability (daytime for solar, wind-dependent periods for wind), potentially reducing the need for gas-fired generation during those periods.

• Shift to peaking and ramping services. Even as DER aggregations reduce baseload gas demand, they may increase the need for gas-fired generation to provide peaking and ramping services. DERs — particularly solar and wind — are intermittent resources whose output varies with weather conditions. When DER output drops unexpectedly (e.g., due to cloud cover or a wind lull), gas-fired generators must ramp up quickly to fill the gap. This creates a more volatile gas demand profile, characterized by rapid ramp-ups and ramp-downs rather than steady-state operation.

• Increased intraday gas nomination volatility. The shift from baseload to peaking and ramping operations implies more volatile intraday gas nominations. Gas-fired generators responding to rapid changes in DER output will need to adjust their gas nominations more frequently and on shorter notice, potentially straining the existing nomination and scheduling framework.

These dynamics are directly relevant to the Ridgeline Pipeline System. The pipeline's Waynesburg delivery point in Greene County, Pennsylvania, is located in an area that includes multiple gas-fired electric generation facilities operating within the PJM footprint. To the extent that DER aggregation growth in PJM reduces or alters demand for gas-fired generation in southwestern Pennsylvania, the Ridgeline Pipeline System will experience corresponding changes in throughput and nomination patterns. The pipeline's current throughput of approximately 680 MMcf/d (56.67% of 1.2 Bcf/d design capacity) means that there is significant headroom to accommodate increases in gas demand driven by peaking and ramping needs. However, the current underutilization also underscores the pipeline's sensitivity to demand-side changes: a significant reduction in gas demand driven by DER penetration could further reduce utilization and put pressure on Ridgeline's ability to recover its cost of service.

B. DEH's 250 MW Wind Portfolio

DEH's development of a 250 MW wind portfolio adds a unique dimension to the Order No. 2222 analysis. As noted above, the wind portfolio is in various stages of development at locations within the Appalachian region, with anticipated commercial operation dates between 2026 and 2028. Depending on the interconnection voltage and participation model selected for each wind facility, the facilities may be classified as either wholesale generating resources interconnecting at the transmission level or as distributed energy resources operating on the distribution system. In either case, the wind facilities will participate in the PJM wholesale electricity markets — either directly as wholesale generators or as components of DER aggregations under Order No. 2222 — and their output will affect the dispatch of gas-fired generators in the same region.

This dual identity of DEH — as both the sole member of a natural gas pipeline and the developer of renewable energy resources that may compete with gas-fired generation served by that pipeline — creates several important considerations:

First, DEH's wind portfolio positions the company to benefit from the growth of renewable energy and DER aggregation even as that growth may adversely affect gas demand and Ridgeline's throughput. This is a strategic reality that DEH must navigate in its business planning and that the Ridgeline tariff should acknowledge.

Second, the dual identity creates potential affiliate transaction concerns. If DEH's wind resources displace gas-fired generation that would otherwise utilize the Ridgeline Pipeline System, questions may arise about whether DEH is prioritizing the interests of its renewable energy operations over the interests of Ridgeline's shippers and ratepayers. Conversely, if Ridgeline's tariff provisions are designed to disadvantage DERs or renewable energy — for example, by imposing punitive scheduling penalties on gas-fired generators that ramp down in response to DER output — questions may arise about whether the tariff is being used to protect the pipeline's revenue at the expense of efficient electric market operations and clean energy policy objectives.

Third, the tariff itself must be drafted with attention to the FERC Standards of Conduct at 18 C.F.R. Part 358, which prohibit regulated entities from providing preferential treatment to affiliates. While the Standards of Conduct were developed primarily in the context of pipeline-marketer affiliates, the principles apply with equal force to the relationship between Ridgeline and DEH's renewable energy operations. The tariff should include explicit provisions ensuring that Ridgeline does not provide preferential pipeline service to support or disadvantage DEH's wind portfolio or any affiliated generation resource.

C. FERC's Deficiency Item 14 — Specific Requirements

Having analyzed the full text of Deficiency Item 14 (reproduced above and at Appendix A) in the context of Order No. 2222, the broader regulatory landscape, and the specific circumstances of the Ridgeline Pipeline System and DEH, we interpret the Item as requiring the following:

1. Acknowledgment of DER aggregation impact. The tariff must acknowledge the potential impact of DER aggregation growth on gas demand and pipeline scheduling. This is a threshold requirement: FERC Staff expects the tariff to demonstrate awareness that the growth of DER aggregations in the wholesale electric markets may affect the demand for gas transportation on the Ridgeline system.

2. Operational coordination provisions. The tariff must address operational coordination between gas pipeline scheduling and electric market dispatch as affected by DER aggregations. This includes provisions for enhanced intraday nomination flexibility, expedited OFO procedures, and information-sharing protocols with electric system operators.

3. Renewable energy interconnection provisions. The tariff must include provisions addressing renewable energy interconnection scenarios relevant to the Ridgeline system. This requirement is driven in part by DEH's 250 MW wind portfolio, which the Deficiency Letter specifically referenced in noting the applicant's parent company's "publicly disclosed development of renewable energy resources." Importantly, this does not require Ridgeline to create a full renewable energy interconnection tariff — wind turbines do not physically interconnect with natural gas pipelines. Rather, the requirement is for the tariff to address the operational and commercial implications of renewable energy development in the region served by the pipeline.

4. Tariff flexibility. The tariff must include provisions ensuring flexibility to accommodate changing gas-electric dynamics driven by DER growth. This may include mechanisms for periodic reassessment of billing determinants, cost recovery provisions for DER-driven operational costs, and provisions for modification of tariff terms in response to material changes in gas-electric market conditions.

We believe that the recommendations set forth in Section V of this memorandum are responsive to each of these requirements while maintaining Ridgeline's commercial flexibility and supporting the redesigned rate of $0.3140 per Dth.

V. Analysis of Required Tariff Provisions

A. Scheduling and Nomination Flexibility

The current Ridgeline tariff, as originally filed, uses the standard NAESB Wholesale Gas Quadrant ("WGQ") nomination timelines, including the Timely nomination cycle (commencing at 11:30 a.m. Central Clock Time ("CCT") for the following gas day), the Evening nomination cycle (commencing at 6:00 p.m. CCT), and Intraday nomination cycles 1, 2, and 3 (commencing at 10:00 a.m., 2:30 p.m., and 7:00 p.m. CCT, respectively, during the gas day). These nomination cycles align with the standard NAESB WGQ business practice standards and, since Order No. 809, with the electric market scheduling timelines.

While the standard NAESB nomination cycles provide a baseline framework for gas scheduling, they may not be sufficient to accommodate the more volatile gas demand patterns anticipated in a high-DER-penetration scenario. As DER aggregations participate more actively in PJM's wholesale markets, the dispatch of gas-fired generators served by the Ridgeline Pipeline System will be increasingly responsive to real-time changes in DER output. A sudden drop in wind generation across the PJM footprint, for example, could trigger rapid ramp-ups of gas-fired generators and corresponding spikes in gas demand at Ridgeline's delivery points. Conversely, a sustained period of high DER output could reduce gas demand well below scheduled levels, creating pipeline imbalances.

We recommend that the redesigned tariff include enhanced intraday nomination provisions that go beyond the standard NAESB cycles. Specifically:

• Additional intraday nomination flexibility. The tariff should include provisions allowing for supplemental intraday nominations outside the standard NAESB cycles when electric market dispatch changes rapidly due to DER output variability. This could take the form of a "DER-driven scheduling adjustment" provision that permits shippers to submit nomination changes on an accelerated timeline when the shipper demonstrates that the nomination change is responsive to a material change in electric market dispatch driven by DER output variability.

• Real-time scheduling coordination. The tariff should include provisions for real-time scheduling coordination between Ridgeline's gas control center and the relevant electric system operators (in this case, PJM) when DER-driven changes in electric market dispatch create operational challenges for the pipeline. This would not require Ridgeline to participate directly in PJM's dispatch process, but rather to establish communication protocols and operational procedures that allow Ridgeline to anticipate and respond to rapid changes in gas demand driven by DER dispatch.

• Cross-reference to NAESB compliance. Any enhanced intraday nomination provisions must be consistent with NAESB WGQ Version 3.2 business practice standards, as required by Deficiency Item 6. We recommend that the tariff include explicit language confirming compliance with NAESB standards while reserving the right to implement additional scheduling flexibility as warranted by DER-driven market conditions.

The proposed scheduling and nomination flexibility provisions should be drafted in consultation with Braswell and Dr. Orlov to ensure consistency with the overall tariff structure and with the operational capabilities of Ridgeline's gas control center and scheduling systems.

B. Operational Flow Order (OFO) Provisions

DER intermittency — particularly wind intermittency — can cause rapid and unpredictable swings in gas-fired generation output. These swings, in turn, can stress pipeline hydraulic balance by creating sudden changes in gas flow volumes and pressures at delivery points. The Ridgeline Pipeline System's three compressor stations (Wetzel, Mannington, and Waynesburg), with aggregate installed compression of 45,000 HP, provide operational flexibility to manage normal variations in gas flow. However, extreme or rapid demand swings driven by DER output variability may exceed the system's ability to maintain hydraulic balance through normal operating procedures, requiring the issuance of operational flow orders to restore system integrity.

We recommend that the redesigned tariff include provisions for expedited OFO issuance in response to DER-driven demand volatility. Specifically:

• Expedited OFO triggers. The tariff should define specific triggers for expedited OFO issuance, including situations where a material change in gas-fired generation dispatch — driven by changes in DER output — creates a pipeline imbalance exceeding defined tolerance bands. The tolerance bands should be calibrated to the Ridgeline system's hydraulic capabilities and should be developed in consultation with Ridgeline's pipeline engineering team.

• Tolerance bands and penalty provisions. Shippers that fail to comply with OFOs issued in response to DER-driven demand volatility should be subject to penalty provisions consistent with the Commission's policies. These penalty provisions should be coordinated with the penalty revenue crediting mechanism required by Deficiency Item 10, which addresses the disposition of penalty revenue collected under the tariff.

• Shipper notification protocols. The tariff should specify notification protocols for expedited OFO issuance, including electronic notification through Ridgeline's EBB, direct communication with affected shippers, and, where feasible, advance notification based on forecasted DER output changes.

• Coordination with compressor station operations. The tariff should acknowledge that expedited OFO procedures may require Ridgeline to adjust compressor station operations at the Wetzel, Mannington, and Waynesburg stations. The costs associated with such operational adjustments — including additional fuel consumption, maintenance costs, and potential wear on compression equipment — should be addressed through the cost recovery mechanism discussed in Section V.C below.

C. Renewable Energy Interconnection Provisions

The phrase "renewable energy interconnection" in Deficiency Item 14 requires careful interpretation in the context of a natural gas pipeline tariff. Wind turbines, solar panels, and battery storage systems do not physically interconnect with natural gas pipelines. The "interconnection" contemplated by Deficiency Item 14 is not a physical interconnection but rather an operational and commercial relationship between the gas pipeline system and the renewable energy resources that affect gas demand and pipeline operations.

DEH's 250 MW wind portfolio may require coordination with Ridgeline's gas pipeline operations in several ways, even though the wind facilities themselves will not directly interconnect with the gas system. If gas-fired generators at or near the Waynesburg delivery point ramp up to compensate for periods of low wind output — or ramp down when wind output is high — the pipeline must accommodate those swings in gas demand. This dynamic creates a de facto operational relationship between the wind portfolio and the gas pipeline, even in the absence of any physical connection between the two.

We recommend the addition of the following tariff provisions:

1. New section in the General Terms and Conditions. A new section titled "Gas-Electric Coordination and Distributed Energy Resource Provisions" (or, alternatively, "Coordination with Renewable Energy Resources") should be added to the General Terms and Conditions of the redesigned tariff. This section would serve as the primary repository for all DER-related provisions and would be cross-referenced from other relevant tariff sections.

2. Information sharing. The new section should include provisions for information sharing between Ridgeline and electric system operators regarding renewable energy output forecasts. This could include arrangements for Ridgeline to receive forecasted wind and solar generation data from PJM or from individual renewable energy operators (including DEH's wind facilities) to assist in pipeline operations planning and scheduling.

3. Scheduling coordination procedures. The new section should include procedures for coordinating pipeline scheduling with electric market real-time dispatch signals. These procedures would complement the enhanced intraday nomination provisions discussed in Section V.A and would provide a framework for Ridgeline to adjust pipeline operations in response to rapid changes in electric market dispatch driven by DER output variability.

4. Cost recovery mechanism. The new section should include a mechanism to address costs incurred by Ridgeline due to DER-driven demand volatility. Such costs could include additional compression fuel, increased maintenance expense associated with more frequent compressor cycling, administrative costs associated with enhanced scheduling and coordination, and capital costs associated with any system modifications needed to accommodate more volatile gas flow patterns. The mechanism could take the form of a surcharge applied to shippers whose nominations are most affected by DER-driven volatility, or a broader tracker mechanism that socializes DER-related costs across all firm shippers. The choice of mechanism should be developed in consultation with Braswell and Dr. Orlov and should be tested against Commission precedent on cost recovery trackers.

We emphasize the importance of distinguishing in the tariff between physical interconnection of renewable resources to the gas system (which is not applicable — wind turbines do not connect to gas pipelines) and operational coordination between gas and electric systems affected by DER growth (which is applicable and required by Deficiency Item 14). Clear drafting on this point will avoid potential confusion among shippers, intervenors, and FERC Staff and will demonstrate that Ridgeline understands the nature of the gas-electric coordination challenge posed by Order No. 2222.

D. DER Aggregation Impact on Billing Determinants

The long-term growth of DER aggregations in the PJM footprint and more broadly could result in a material reduction in overall gas demand for electricity generation, which would directly affect Ridgeline's throughput and revenue. This concern is not merely theoretical: Ridgeline's current utilization rate of approximately 56.67% of design capacity already indicates significant exposure to demand-side risk. Any incremental reduction in gas demand driven by DER penetration would further widen the gap between design capacity and actual throughput.

The tariff redesign's move from a 100% load factor (as originally filed) to a 75% load factor (as proposed in the redesigned tariff) partially addresses this concern by reducing the billing determinants from 438,000,000 Dth per year to 328,500,000 Dth per year. This adjustment increases the per-unit rate (from $0.2265/Dth to $0.3140/Dth) to ensure that the reduced billing determinants still recover the full cost of service. However, the load factor adjustment does not explicitly link to DER growth or provide a mechanism for ongoing reassessment of billing determinants in light of DER penetration trends.

We recommend that the redesigned tariff include a periodic review mechanism that allows Ridgeline to reassess billing determinants in light of material changes in gas demand driven by DER growth. Specifically:

• Periodic review provision. The tariff should include a provision allowing Ridgeline to file a limited NGA Section 4 rate proceeding, or alternatively to invoke a tariff-based tracker mechanism, to reassess billing determinants in the event that DER-driven demand changes cause actual throughput to deviate materially (e.g., by more than 10%) from the billing determinant assumptions underlying the approved rate.

• DER penetration reporting. The periodic review mechanism could be triggered by defined DER penetration milestones published by PJM or by changes in Ridgeline's actual throughput that are reasonably attributable to DER growth.

• Strategic implications for the load factor dispute. The inclusion of a DER-linked billing determinant review mechanism has strategic implications for the ongoing settlement discussions. MGPC and ATPC have advocated for a load factor of 85% or higher, arguing that Ridgeline's system should be capable of achieving higher utilization. However, a DER-driven demand decline could actually support a lower load factor assumption by demonstrating that gas demand is subject to structural headwinds that reduce the probability of achieving high utilization rates. This argument could bolster Ridgeline's 75% load factor position in settlement or hearing.

E. Affiliate Transaction Provisions

Given DEH's dual role as Ridgeline's sole member and the developer of the 250 MW wind portfolio, the tariff must include robust affiliate transaction provisions that address the specific risks created by this dual identity. The FERC Standards of Conduct at 18 C.F.R. Part 358 provide the general framework, but the tariff should include specific provisions tailored to the gas-electric coordination and DER context.

We recommend the following:

• Non-preferential service provision. The tariff should include explicit language prohibiting Ridgeline from providing preferential pipeline service to support or disadvantage DEH's wind portfolio or any affiliated generation resource. This provision should make clear that Ridgeline will not condition the availability, quality, or pricing of transportation service on a shipper's participation (or non-participation) in DEH's renewable energy operations or on the shipper's competitive relationship with DEH's renewable energy portfolio.

• Anti-tying provisions. The tariff should include anti-tying provisions prohibiting Ridgeline from conditioning transportation service on a shipper's relationship with DEH or any DEH affiliate. These provisions should be drafted broadly to cover any form of tying arrangement, including bundling of gas transportation with renewable energy credits, environmental attribute transactions, or participation in DEH-sponsored energy programs.

• Information firewall. The tariff should include provisions requiring Ridgeline to maintain an information firewall between its gas transportation operations and DEH's renewable energy development activities. While Ridgeline and DEH share common ownership, non-public operational information about pipeline scheduling, capacity availability, and shipper activity should not be shared with DEH's renewable energy development team except through publicly available channels (i.e., the EBB).

• Compliance officer designation. The tariff should require Ridgeline to designate a compliance officer responsible for monitoring and enforcing the affiliate transaction provisions, with periodic reporting to the Commission as required by 18 C.F.R. Part 358.

Ms. Dunmore's 72% equity interest in DEH, and her role as the controlling shareholder of both the pipeline operator and the renewable energy developer, underscores the importance of visible compliance with affiliate transaction rules. FERC Staff and intervenors will scrutinize any tariff provisions that could be perceived as facilitating preferential treatment of DEH's renewable energy interests, and robust affiliate transaction safeguards will be essential to securing approval of the redesigned tariff.

F. Electronic Bulletin Board (EBB) Posting of DER-Related Information

The redesigned tariff's EBB provisions, which are also the subject of Deficiency Item 7, should be expanded to include DER-related operational information. We recommend the following:

• Gas-electric coordination notices. Ridgeline's EBB should include a dedicated section for gas-electric coordination notices, including notices of anticipated DER-driven demand changes, OFO issuances related to renewable energy variability, and other operational information relevant to shippers whose gas nominations may be affected by changes in electric market dispatch driven by DER aggregations.

• Real-time capacity availability data. The EBB should include real-time (or near-real-time) capacity availability data to assist gas-fired generators in making scheduling decisions responsive to DER output changes. If a gas-fired generator anticipates needing to ramp up quickly to compensate for a drop in DER output, access to real-time pipeline capacity data will assist the generator in determining whether pipeline capacity is available to support the required increase in gas nominations.

• DER-related OFO postings. Any OFOs issued on an expedited basis in response to DER-driven demand volatility should be prominently posted on the EBB with clear identification of the DER-related trigger, in addition to standard OFO notification procedures.

• Consistency with Deficiency Item 7. All EBB enhancements related to DER information must be consistent with the broader EBB reforms being developed in response to Deficiency Item 7, which addresses EBB transparency, accessibility, and information content more generally. We recommend that the DER-related EBB provisions be integrated into the overall EBB section of the tariff rather than maintained as a separate, standalone provision.

VI. Survey of Industry Precedent

A. Other Pipeline Tariff Approaches to Order No. 2222

Our survey of recently filed or approved FERC-jurisdictional pipeline tariffs reveals that most natural gas pipelines have not yet comprehensively addressed Order No. 2222 or DER aggregation in their tariff filings. This is not surprising: Order No. 2222's direct obligations run to RTOs and ISOs, and the Commission has not issued a generic rulemaking requiring natural gas pipelines to address DER aggregation in their tariffs. The Deficiency Letter's Item 14 reflects a case-specific initiative by FERC Staff, likely prompted by the unique circumstances of the Ridgeline filing — including DEH's publicly disclosed wind portfolio — rather than a broad policy directive applicable to all pipeline tariffs.

Notwithstanding the general absence of comprehensive DER provisions in pipeline tariffs, several pipelines have addressed gas-electric coordination in ways that provide useful precedent for Ridgeline's tariff redesign:

• Enhanced intraday nomination provisions. Following Order No. 809 (discussed below), several major pipelines revised their tariffs to include enhanced intraday nomination flexibility, including more frequent nomination cycles and expedited scheduling procedures during periods of high electric-sector demand volatility. These provisions, while not specifically tied to Order No. 2222, address the same underlying dynamic of gas demand volatility driven by changes in electric market conditions.

• Gas-electric coordination sections. A small number of pipelines have included dedicated "Gas-Electric Coordination" sections in their tariffs, typically addressing information sharing with electric system operators, coordination of scheduling timelines, and operational procedures for managing gas demand changes driven by electric market conditions. These sections provide a template for the new tariff section recommended in this memorandum.

• OFO provisions referencing electric market conditions. Some pipeline tariffs include OFO trigger criteria that explicitly reference changes in electric market dispatch or electric system emergency conditions as grounds for expedited OFO issuance. These provisions recognize the reality that electric market conditions are a signifi

PRIVILEGED & CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION / ATTORNEY WORK PRODUCT This memorandum is protected from disclosure by the attorney-client privilege and the work product doctrine. It is intended solely for the use of the named recipients and their authorized representatives. Any dissemination, distribution, or copying of this memorandum without the express written consent of Calderwood & Harkness LLP is strictly prohibited.
MEMORANDUM
FROM: Calderwood & Harkness LLP George Trujillo, Partner (Responsible Partner, Energy & Infrastructure Practice) Brett Callahan, Associate (Lead Associate, Energy & Infrastructure Practice)
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
DATE: May 15, 2024
RE: FERC Order No. 2222 — Implications for Distributed Energy Resource Aggregation and Renewable Energy Interconnection at the Ridgeline Pipeline System; Response to Deficiency Item 14
MATTER: C&H Matter No. 1016-00005
DOCKET NOS.: RP22-847-000 (rate case); RP22-847-001 (interconnection)
PRIVILEGED & CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION / ATTORNEY WORK PRODUCT
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I. Executive Summary
This memorandum analyzes the Federal Energy Regulatory Commission's ("FERC" or the "Commission") Order No. 2222 and its implications for the redesigned FERC Gas Tariff, Original Volume No. 1, of Ridgeline Midstream Services LLC ("Ridgeline"), with specific focus on addressing Deficiency Item 14 of the January 19, 2023 Deficiency Letter issued by FERC's Office of Energy Market Regulation (Dr. Miriam Okafor, Lead Economic Analyst) (the "Deficiency Letter"). This memorandum is intended to guide the development of proposed tariff language responsive to Deficiency Item 14 and to inform the broader tariff redesign effort currently underway.
Deficiency Item 14 identified Ridgeline's failure to address Order No. 2222 distributed energy resource ("DER") aggregation implications, including renewable energy interconnection, in its original tariff filing. The Deficiency Letter stated, in relevant part, that Ridgeline's proposed tariff "contains no provisions addressing the potential for DER aggregations to affect pipeline operations, scheduling, or tariff design" and requested that Ridgeline supplement its filing with provisions responsive to these concerns. The full text of Deficiency Item 14 is reproduced at Appendix A to this memorandum.
This memorandum is being prepared in coordination with Braswell Energy Consulting Group LLC ("Braswell"), Engagement No. BEC-2023-0041, under the direction of lead consultant Dr. Raymond Braswell, a former FERC economist who was engaged on April 15, 2023 to lead the comprehensive tariff redesign necessitated by the Deficiency Letter. Braswell's engagement encompasses all fourteen deficiency items, and the analysis and recommendations set forth in this memorandum are intended to be integrated into the revised cost-of-service model and tariff drafting currently being undertaken by Braswell in consultation with Ridgeline's in-house regulatory team.
The nexus between Order No. 2222 — a rulemaking directed at regional transmission organizations ("RTOs") and independent system operators ("ISOs") in the electric sector — and Ridgeline's natural gas pipeline tariff requires careful analysis. While Order No. 2222 does not directly impose obligations on interstate natural gas pipelines, the Order's facilitation of DER aggregation participation in wholesale electricity markets has material implications for gas-fired electric generation facilities served by pipelines like Ridgeline, and consequently for pipeline demand patterns, scheduling, and tariff design. These implications are heightened in Ridgeline's case by the fact that Dunmore Energy Holdings Ltd. ("DEH"), Ridgeline's sole member, owns and is developing a 250 MW wind portfolio in the Appalachian region. DEH's dual role as both a natural gas midstream operator and a renewable energy developer positions the company — and by extension, the Ridgeline Pipeline System — at a critical intersection of the gas and electric sectors that Order No. 2222 was designed to reshape.
Based on our analysis of Order No. 2222 and its progeny, the specific requirements of Deficiency Item 14, relevant industry precedent, and the unique commercial and regulatory context of the Ridgeline Pipeline System and DEH's broader energy portfolio, we recommend the following:
1. New Tariff Section. The addition of a new section to the General Terms and Conditions of the redesigned tariff titled "Gas-Electric Coordination and Distributed Energy Resource Provisions," containing subsections addressing definitions, enhanced intraday nomination and scheduling flexibility, expedited operational flow order ("OFO") procedures, information-sharing protocols, periodic billing determinant review mechanisms, affiliate transaction safeguards, electronic bulletin board ("EBB") posting requirements, and a cost recovery mechanism for DER-driven operational costs.
2. Conforming Amendments. Conforming amendments to existing tariff sections, including Rate Schedules FT-1 and IT-1, and multiple provisions within the General Terms and Conditions addressing nominations, OFOs, EBB, and creditworthiness.
3. Coordination with Other Deficiency Item Responses. The proposed provisions must be coordinated with responses to Deficiency Items 2 (FL&U tracker), 5 (capacity release), 6 (NAESB compliance), 7 (EBB requirements), 10 (penalty revenue crediting), 11 (creditworthiness), 12 (segmentation and flexible receipt/delivery points), and 13 (GHG cost recovery) to ensure internal consistency across the redesigned tariff.
4. Affiliate Transaction Safeguards. Robust provisions prohibiting preferential treatment of DEH's wind portfolio or affiliated generation resources, consistent with FERC's Standards of Conduct at 18 C.F.R. Part 358 and the Commission's affiliate transaction policies.
The filing deadline for the supplemental response addressing all remaining deficiency items, including Item 14, is February 21, 2025, as established by Administrative Law Judge Clara Whitfield's March 4, 2024 order granting Ridgeline's third request for extension of time, subject to conditions including the filing of quarterly status reports. Three such quarterly reports have been filed to date (June 15, 2024; September 14, 2024; and December 13, 2024), and the proceeding has been classified as "dormant" by the Commission's Office of the Secretary since September 8, 2023.
The balance of this memorandum sets forth the factual and procedural background, a detailed analysis of Order No. 2222, the nexus between the Order and natural gas pipeline tariffs, our assessment of required tariff provisions, a survey of industry precedent, a summary of proposed tariff language recommendations, a risk assessment, settlement implications, coordination requirements with Braswell, and a timeline for next steps through the February 2025 filing deadline.
II. Background
A. The Ridgeline Pipeline System and DEH's Energy Portfolio
Ridgeline Midstream Services LLC is a Delaware limited liability company and a wholly owned subsidiary of Dunmore Energy Holdings Ltd. ("DEH"), a Cayman Islands exempted limited company, Registry No. CR-381204. Patricia Dunmore, the founder and chairperson of DEH, holds a 72% equity interest in DEH, with the remaining 28% held by institutional investors through a series of preferred equity instruments issued in connection with the Ridgeline Pipeline System's original construction financing. Ms. Dunmore's role as the controlling equity holder of DEH and as the C&H billing partner on this engagement has been fully disclosed and waived in accordance with applicable rules of professional conduct, as documented in the engagement letter dated March 22, 2022 and the supplemental conflict waiver executed on April 3, 2022.
The Ridgeline Pipeline System is a 187-mile, 24-inch-diameter high-pressure natural gas transportation pipeline located in West Virginia and Pennsylvania. The system was placed in service on October 1, 2021, following an original construction program costing approximately $587.2 million (inclusive of allowance for funds used during construction and capitalized overhead). The pipeline extends from a receipt point at the Wetzel County Interconnect in Wetzel County, West Virginia (39.6120° N, 80.7540° W) to a delivery point at the Waynesburg Compressor Station in Greene County, Pennsylvania (39.8965° N, 80.1810° W). The system is equipped with three compressor stations — the Wetzel Compressor Station (located at the receipt point), the Mannington Compressor Station (approximately milepost 88, in Marion County, West Virginia), and the Waynesburg Compressor Station (located at the delivery point) — with aggregate installed compression of 45,000 horsepower ("HP"). The design capacity of the system is 1.2 billion cubic feet per day ("Bcf/d"), equivalent to 1,200,000 dekatherms per day ("Dth/d"), assuming maximum operating pressure and full utilization of available compression. As of the most recent operational data available to us, current throughput is approximately 680 million cubic feet per day ("MMcf/d"), representing a utilization rate of approximately 56.67% of design capacity.
The Ridgeline Pipeline System was designed to transport natural gas produced from the Marcellus and Utica shale formations in northern West Virginia to interconnection points with downstream pipeline systems and distribution utilities in southwestern Pennsylvania. The pipeline's primary interconnection is with Appalachian Trunk Pipeline Company, LLC ("ATPC") at the Wetzel County Interconnect, which is the subject of the interconnection authorization proceeding at Docket No. RP22-847-001.
DEH's broader energy portfolio extends well beyond the Ridgeline Pipeline System. As of December 31, 2023, DEH owned and operated approximately 1,200 miles of midstream gathering and transportation pipelines across the Appalachian Basin, together with two cryogenic natural gas processing plants with aggregate processing capacity of approximately 800 MMcf/d. DEH's estimated enterprise value, based on internal valuation methodologies as of December 31, 2023, is approximately $2.8 billion. Consolidated annual revenue for the fiscal year ended December 31, 2023 was approximately $485 million.
Of particular relevance to this memorandum, DEH is also developing a 250 MW wind portfolio in the Appalachian region. The exact locations of the planned wind facilities have not yet been publicly disclosed, although DEH has indicated in investor presentations and public filings that the projects are in various stages of development, with commercial operation dates anticipated between 2026 and 2028. The 250 MW wind portfolio is a cornerstone of DEH's stated strategy to diversify its energy portfolio beyond natural gas midstream operations and to position the company as a participant in the growing renewable energy sector. This dual identity — as both a natural gas midstream operator and a renewable energy developer — is directly relevant to the Order No. 2222 analysis, because it means that DEH and its subsidiaries will be active participants on both sides of the gas-electric coordination equation. The Ridgeline tariff must be drafted with awareness of this reality, including the potential for affiliate transaction issues and the need for provisions that address the interaction between gas-fired generation served by the pipeline and DER aggregations that may include DEH's own renewable energy resources.
B. Procedural History and Deficiency Item 14
The procedural history of this matter is extensive and reflects the complexity of the issues involved. We summarize below the key events leading to the current posture of the proceeding, with particular emphasis on the genesis and substance of Deficiency Item 14.
On May 12, 2022, Ridgeline filed its application for initial tariff rate and interconnection authorization with the Commission, initiating the proceedings at Docket Nos. RP22-847-000 (rate case) and RP22-847-001 (interconnection). The application proposed an initial recourse rate of $0.2265 per Dth, comprising a reservation charge of $0.2223 per Dth and a usage charge of $0.0042 per Dth. The proposed rate was based on a rate base of $612.40 million, a total cost of service of $97.36 million, a return on equity ("ROE") of 14.00%, and billing determinants calculated using a 100% load factor. The filing was accompanied by a proposed FERC Gas Tariff, Original Volume No. 1, containing rate schedules and general terms and conditions in conformity with the Commission's regulations at 18 C.F.R. Part 154.
The application also sought authorization for interconnection with ATPC at the Wetzel County Interconnect, with total interconnection facilities estimated at $22.3 million. The interconnection facilities would be jointly owned and operated by Ridgeline and ATPC under a proposed Construction, Ownership, and Operating Agreement ("COOA"), the terms of which were included in the filing.
Multiple parties intervened in the proceeding. On August 15, 2022, ATPC filed a protest and motion to intervene, represented by William Pratt of Kellner, Royce & Dillard LLP. ATPC's protest raised concerns regarding, inter alia, the proposed allocation of interconnection costs, the appropriateness of a 100% load factor, and the proposed ROE of 14.00%, which ATPC characterized as "substantially in excess of the range of reasonableness as established by Commission precedent." On July 28, 2022, the Mountainside Gas Producers Coalition ("MGPC"), a coalition of fourteen independent natural gas producers operating in the Marcellus and Utica shale formations, filed a motion to intervene through its Executive Director, Calvin Dreyer, and counsel of record, Rebekah Montague of Whitmore & Sable LLP. MGPC raised concerns regarding the proposed rate level, load factor assumptions, and cost allocation methodology. On August 1, 2022, Clearwater Municipal Gas Authority ("CMGA"), a municipal gas distribution utility serving approximately 42,000 customers in Greene and Washington Counties, Pennsylvania, filed a motion to intervene through its General Manager, Dennis Ott, and counsel of record, Stephen Greer of Fordham Municipal Law Group PC. CMGA expressed interest in ensuring that the tariff provisions adequately protect end-use customers and municipal distribution utilities.
On September 22, 2022, the Commission issued an order granting all pending interventions, setting the proceeding for hearing under a Track II procedural schedule, and appointing Settlement Judge Howard Margolis to oversee settlement negotiations. The procedural schedule established dates for direct testimony, responsive testimony, cross-answering testimony, and hearing.
On December 5, 2022, Ridgeline filed the direct testimony and exhibits of seven witnesses, covering topics including cost of service, rate design, depreciation, return on equity, pipeline operations, interconnection engineering, and tariff terms and conditions.
On January 19, 2023, the Commission's Office of Energy Market Regulation issued the Deficiency Letter, identifying fourteen deficiencies in Ridgeline's tariff filing. The Deficiency Letter was prepared under the direction of Dr. Miriam Okafor, Lead Economic Analyst, and signed by the Director of the Office of Energy Market Regulation. The fourteen deficiencies spanned a wide range of issues, from fuel, lost, and unaccounted-for gas tracking mechanisms (Item 2) to creditworthiness provisions (Item 11) to greenhouse gas cost recovery (Item 13).
Deficiency Item 14 is the focus of this memorandum. The item stated, in its entirety:
"The proposed tariff fails to address the implications of Commission Order No. 2222, Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, 172 FERC ¶ 61,247 (2020), for distributed energy resource aggregation and renewable energy interconnection. The Applicant's proposed tariff contains no provisions addressing the potential for DER aggregations to affect pipeline operations, scheduling, or tariff design. Given the Applicant's parent company's publicly disclosed development of renewable energy resources, the Commission Staff requires the Applicant to supplement its filing with provisions that adequately address the implications of Order No. 2222 for the proposed tariff, including but not limited to the potential impact of DER aggregation growth on gas demand patterns, operational coordination between gas pipeline scheduling and electric market dispatch, and provisions for renewable energy interconnection scenarios relevant to the Applicant's system."
The Deficiency Letter established a response deadline of ninety days (April 19, 2023). On February 6, 2023, ALJ Whitfield issued an order staying the procedural schedule pending resolution of the deficiency items. On March 15, 2023, Ridgeline filed a partial response to the Deficiency Letter, addressing eight of the fourteen items (Items 1, 3, 4, 8, 9, 10, 11, and a partial response to Item 6). Item 14 was not among the items addressed in the partial response, as Ridgeline determined that a comprehensive analysis was required before a substantive response could be prepared.
On April 15, 2023, Ridgeline engaged Braswell Energy Consulting Group LLC to lead the comprehensive tariff redesign necessitated by the remaining deficiency items. Dr. Raymond Braswell, the firm's founder and principal consultant, assumed responsibility for the engagement under Engagement No. BEC-2023-0041. Dr. Braswell's scope of work encompasses the full revision of the tariff to address all fourteen deficiency items, including the development of revised cost-of-service calculations, rate design methodology, and tariff language.
Ridgeline has sought and obtained multiple extensions of the filing deadline. The original ninety-day deadline (April 19, 2023) was extended by agreement to August 18, 2023 (first extension), then to December 15, 2023 (second extension), and most recently to February 21, 2025, pursuant to ALJ Whitfield's March 4, 2024 order granting Ridgeline's third request for extension. The March 4, 2024 order imposed conditions on the extension, including the requirement that Ridgeline file quarterly status reports with the Commission detailing progress on the tariff redesign and the expected timeline for addressing remaining deficiency items. Three quarterly status reports have been filed to date: June 15, 2024; September 14, 2024; and December 13, 2024.
The proceeding has been classified as "dormant" by the Commission's Office of the Secretary since September 8, 2023. No contested hearing has been scheduled, and the procedural schedule remains stayed pending the supplemental filing.
C. The Tariff Redesign Context
The tariff redesign is proceeding under the joint direction of Braswell, Calderwood & Harkness, and Ridgeline's in-house regulatory team, led by Dr. Natasha Orlov, Director of Rates & Regulatory. The redesign reflects substantial changes from the original filing, driven by both the deficiency items and by the evolution of Ridgeline's operating and financial circumstances since May 2022.
Key changes from the original filing include:
• Load factor: The proposed load factor has been reduced from 100% to 75%, reflecting Ridgeline's actual throughput experience (56.67% utilization as of the most recent data) and a more conservative projection of system utilization over the initial rate period. The revised 75% load factor yields billing determinants of 328,500,000 Dth per year, down from the originally proposed 438,000,000 Dth per year.
• Return on equity: The proposed ROE has been reduced from 14.00% to 12.50%. This reduction reflects a reassessment of market conditions, including declining risk-free rates since the original filing and recognition that the original 14.00% proposal substantially exceeded the range of returns approved by the Commission in recent pipeline rate cases. The revised 12.50% ROE, while still above the intervenors' positions (10.75% proposed by ATPC; 11.25% proposed by MGPC), represents a significant movement toward a zone of potential settlement.
• Weighted average cost of capital: The revised weighted average cost of capital ("WACC") is 9.2375%, reflecting the reduced ROE and adjustments to the capital structure assumptions in the original filing.
• Total cost of service: The revised total cost of service is $103.15 million, an increase from the original $97.36 million. The increase is attributable primarily to updated depreciation rates, revised estimates of operations and maintenance expenses (including costs associated with the tariff redesign itself), and the incorporation of additional cost elements identified through the deficiency item analysis.
• Revised proposed recourse rate: The revised proposed recourse rate is $0.3140 per Dth, comprising a reservation charge of $0.3102 per Dth and a usage charge of $0.0038 per Dth. The increase from the original proposed rate of $0.2265 per Dth is driven primarily by the reduction in the load factor from 100% to 75% (which reduces billing determinants and increases the per-unit rate necessary to recover the cost of service) and the increase in the total cost of service.
The current working version of the revised tariff is the fourth draft, dated November 2024. It is into this version that the Order No. 2222 provisions recommended in this memorandum must be incorporated. We note that the fourth draft reflects the cumulative results of the tariff redesign effort to date, including responses to all deficiency items other than Item 14 and certain aspects of Items 12 and 13 that remain in progress.
Settlement discussions among the parties remain ongoing but have not produced agreement. Four formal settlement conferences have been conducted before Settlement Judge Margolis: November 30, 2022; March 8, 2023; July 12, 2023; and January 18, 2024. The parties remain approximately $0.058 per Dth apart, with Ridgeline maintaining a floor position of $0.3140 per Dth and the ATPC/MGPC coalition maintaining a ceiling position of approximately $0.2560 per Dth. CMGA has generally aligned with the intervenors on rate level but has indicated flexibility on certain tariff terms and conditions. The settlement dynamics are discussed further in Section IX of this memorandum.
III. Overview of FERC Order No. 2222
A. Regulatory History and Objectives
FERC Order No. 2222, titled Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, was issued on September 17, 2020 in Docket No. RM18-9-000. 172 FERC ¶ 61,247 (2020). The Order became effective on March 1, 2021, and required RTO/ISO tariff compliance filings within a specified timeframe.
The Order represented the culmination of a multi-year rulemaking process that began with the Commission's issuance of a Notice of Proposed Rulemaking ("NOPR") on November 17, 2016 (Docket No. RM18-9-000, 157 FERC ¶ 61,121). The NOPR, in turn, was preceded by several years of Commission engagement with the issue of DER participation in wholesale markets, including a 2015 technical conference on DER aggregation and the Commission's growing recognition that the rapid proliferation of distributed energy technologies — solar photovoltaic systems, battery storage, demand response, smart thermostats, electric vehicles, and other behind-the-meter resources — was creating a significant pool of energy resources that could, in aggregate, provide meaningful services to the wholesale electric grid but were effectively barred from participation by existing RTO/ISO market rules.
The Commission's stated objective in issuing Order No. 2222 was to "remove barriers to the participation of distributed energy resource aggregations in the organized wholesale electric energy, capacity, and ancillary services markets operated by regional transmission organizations and independent system operators." The Commission found that existing RTO/ISO tariffs either did not permit DER aggregations to participate in wholesale markets or imposed minimum size thresholds and other participation requirements that effectively excluded the vast majority of DERs. The Commission concluded that these barriers "may result in unjust and unreasonable rates" and that the removal of such barriers would "enhance competition" and "help ensure that the wholesale electricity markets produce just and reasonable rates."
Order No. 2222 defined "distributed energy resource" broadly. Under the Order, a DER is "any resource located on the distribution system, any subsystem thereof, or behind a customer meter." The definition encompasses, without limitation, electric storage resources, distributed generation (including rooftop solar, small wind, and combined heat and power systems), demand response resources, energy efficiency resources, thermal storage resources, and electric vehicles capable of providing grid services. The breadth of this definition is significant because it means that the DER aggregations contemplated by the Order may include a wide and heterogeneous mix of technologies, each with different operational characteristics, response times, and impacts on the broader energy system — including the natural gas system.
B. Key Provisions of Order No. 2222
The operative provisions of Order No. 2222 are directed at RTOs and ISOs, requiring each to revise its tariff to accommodate DER aggregation participation. The key provisions are as follows:
DER Aggregation Participation. RTOs and ISOs must allow DER aggregators to register aggregations of individual DERs to participate in the wholesale markets operated by the RTO or ISO. An aggregator may be any entity that meets the RTO's/ISO's participation requirements, including third-party aggregators, distribution utilities, and, in some cases, the DER owners themselves. The aggregation model allows multiple small DERs — none of which would individually meet minimum size requirements for wholesale market participation — to be combined into a single, dispatchable resource that can bid into and be dispatched by the RTO/ISO markets.
Minimum Size Thresholds. The Order prohibits RTOs and ISOs from establishing minimum size requirements for DER aggregations that exceed 100 kilowatts ("kW"). This is a significant provision because it ensures that even very small aggregations — as few as two or three residential-scale resources — can, in principle, participate in wholesale markets if they meet other participation requirements.
Locational Requirements. DER aggregations must be located within a single pricing node (i.e., a single locational marginal price or "LMP" zone) for purposes of market participation. The Order includes limited exceptions for DERs served by small utilities and for aggregations in areas where the pricing node structure is sufficiently granular to accommodate geographically dispersed DERs. These locational requirements are relevant to the gas-electric coordination analysis because they determine the geographic areas in which DER aggregations may compete with or displace gas-fired generation.
Participation Models. The Order requires RTOs and ISOs to establish participation models for DER aggregations that encompass all types of DER technologies. This means that a single aggregation may include a mix of solar, storage, demand response, and other DER types, and the RTO/ISO must have market rules capable of dispatching and settling such heterogeneous aggregations.
Metering and Telemetry. DER aggregators are responsible for the metering of individual DERs within the aggregation, subject to metering and telemetry requirements established by the RTO/ISO. The RTO/ISO may require sub-metering of individual DERs for settlement purposes, real-time or near-real-time telemetry for dispatch purposes, and performance verification testing.
Distribution Utility Coordination. Order No. 2222 addresses the relationship between DER aggregators, distribution utilities, and the RTO/ISO. The Order recognizes that DER aggregations operate on the distribution system and that their dispatch by the RTO/ISO could have implications for distribution system reliability and operations. The Order requires coordination protocols between the DER aggregator, the relevant distribution utility, and the RTO/ISO to ensure that DER dispatch does not create reliability concerns on the distribution system.
Dual Participation. The Order includes provisions addressing DERs that participate in both wholesale markets (through the RTO/ISO) and retail programs (through the distribution utility or state commission). The Order generally permits dual participation but requires adequate accounting mechanisms to prevent double-counting of services and to ensure that the DER's contribution to the wholesale market does not compromise its commitments under retail programs.
C. Order No. 2222-A and Subsequent Clarifications
On March 18, 2021, the Commission issued Order No. 2222-A, a rehearing order that clarified certain provisions of the original Order. 175 FERC ¶ 61,197 (2021). Among the clarifications, Order No. 2222-A addressed the treatment of states with retail choice, providing that DERs in retail choice states could opt in to wholesale market participation through DER aggregations even where the state commission had not affirmatively authorized such participation. Order No. 2222-A also clarified certain aspects of the distribution utility coordination requirements and the metering and telemetry provisions.
Subsequent to Order No. 2222-A, the Commission has issued a series of orders on the compliance filings submitted by individual RTOs and ISOs. These compliance orders have addressed RTO/ISO-specific implementation issues and have provided additional guidance on the application of the Order's requirements in different market contexts. As of the date of this memorandum, compliance proceedings remain pending before several RTOs/ISOs, including PJM Interconnection, LLC ("PJM"), which is the RTO most relevant to the Ridgeline Pipeline System given PJM's coverage of the Pennsylvania and West Virginia markets served by the pipeline.
While Order No. 2222 was directed primarily at RTOs and ISOs in the electric sector and does not, on its face, impose obligations on interstate natural gas pipelines regulated under the Natural Gas Act ("NGA") and the Natural Gas Policy Act ("NGPA"), the Commission has signaled a growing interest in gas-electric coordination and the impact of DER growth on natural gas demand patterns. This interest is reflected in the Deficiency Letter's inclusion of Item 14, which, as discussed below, requires Ridgeline to address Order No. 2222's implications for its tariff despite the fact that the Order's direct legal obligations run to electric-sector entities. The Commission's approach in Item 14 is consistent with its broader policy of encouraging natural gas pipelines to consider gas-electric interdependencies in their tariff filings and operations planning, a theme that has been developing since at least the polar vortex events of 2013-2014 and the issuance of Order No. 809 in 2015.
IV. Nexus Between Order No. 2222 and Natural Gas Pipeline Tariffs
A. Gas-Electric Interdependence
The fundamental nexus between Order No. 2222 and natural gas pipeline tariffs is the deep and growing interdependence between the natural gas and electric power sectors. Natural gas pipelines serve gas-fired electric generation facilities — including combined-cycle plants, combustion turbines, and peaking units — that are major consumers of pipeline transportation capacity and significant drivers of pipeline throughput and revenue. Gas-fired generation is the single largest source of electricity in the United States, accounting for approximately 43% of total electricity generation in 2023 according to the U.S. Energy Information Administration. In the PJM footprint, which encompasses the geographic area served by the Ridgeline Pipeline System, gas-fired generation represents a substantial and growing share of the generation fleet, driven by the retirement of coal-fired plants and the construction of new gas-fired facilities to support grid reliability.
The growth of DER aggregations, as facilitated by Order No. 2222, has the potential to alter gas demand profiles in several significant ways:
• Reduction in baseload gas-fired generation. As DER aggregations provide increasing quantities of energy, capacity, and ancillary services to the wholesale electric market, they may displace some portion of baseload gas-fired generation. Solar and wind resources within DER aggregations produce energy during periods of high resource availability (daytime for solar, wind-dependent periods for wind), potentially reducing the need for gas-fired generation during those periods.
• Shift to peaking and ramping services. Even as DER aggregations reduce baseload gas demand, they may increase the need for gas-fired generation to provide peaking and ramping services. DERs — particularly solar and wind — are intermittent resources whose output varies with weather conditions. When DER output drops unexpectedly (e.g., due to cloud cover or a wind lull), gas-fired generators must ramp up quickly to fill the gap. This creates a more volatile gas demand profile, characterized by rapid ramp-ups and ramp-downs rather than steady-state operation.
• Increased intraday gas nomination volatility. The shift from baseload to peaking and ramping operations implies more volatile intraday gas nominations. Gas-fired generators responding to rapid changes in DER output will need to adjust their gas nominations more frequently and on shorter notice, potentially straining the existing nomination and scheduling framework.
These dynamics are directly relevant to the Ridgeline Pipeline System. The pipeline's Waynesburg delivery point in Greene County, Pennsylvania, is located in an area that includes multiple gas-fired electric generation facilities operating within the PJM footprint. To the extent that DER aggregation growth in PJM reduces or alters demand for gas-fired generation in southwestern Pennsylvania, the Ridgeline Pipeline System will experience corresponding changes in throughput and nomination patterns. The pipeline's current throughput of approximately 680 MMcf/d (56.67% of 1.2 Bcf/d design capacity) means that there is significant headroom to accommodate increases in gas demand driven by peaking and ramping needs. However, the current underutilization also underscores the pipeline's sensitivity to demand-side changes: a significant reduction in gas demand driven by DER penetration could further reduce utilization and put pressure on Ridgeline's ability to recover its cost of service.
B. DEH's 250 MW Wind Portfolio
DEH's development of a 250 MW wind portfolio adds a unique dimension to the Order No. 2222 analysis. As noted above, the wind portfolio is in various stages of development at locations within the Appalachian region, with anticipated commercial operation dates between 2026 and 2028. Depending on the interconnection voltage and participation model selected for each wind facility, the facilities may be classified as either wholesale generating resources interconnecting at the transmission level or as distributed energy resources operating on the distribution system. In either case, the wind facilities will participate in the PJM wholesale electricity markets — either directly as wholesale generators or as components of DER aggregations under Order No. 2222 — and their output will affect the dispatch of gas-fired generators in the same region.
This dual identity of DEH — as both the sole member of a natural gas pipeline and the developer of renewable energy resources that may compete with gas-fired generation served by that pipeline — creates several important considerations:
First, DEH's wind portfolio positions the company to benefit from the growth of renewable energy and DER aggregation even as that growth may adversely affect gas demand and Ridgeline's throughput. This is a strategic reality that DEH must navigate in its business planning and that the Ridgeline tariff should acknowledge.
Second, the dual identity creates potential affiliate transaction concerns. If DEH's wind resources displace gas-fired generation that would otherwise utilize the Ridgeline Pipeline System, questions may arise about whether DEH is prioritizing the interests of its renewable energy operations over the interests of Ridgeline's shippers and ratepayers. Conversely, if Ridgeline's tariff provisions are designed to disadvantage DERs or renewable energy — for example, by imposing punitive scheduling penalties on gas-fired generators that ramp down in response to DER output — questions may arise about whether the tariff is being used to protect the pipeline's revenue at the expense of efficient electric market operations and clean energy policy objectives.
Third, the tariff itself must be drafted with attention to the FERC Standards of Conduct at 18 C.F.R. Part 358, which prohibit regulated entities from providing preferential treatment to affiliates. While the Standards of Conduct were developed primarily in the context of pipeline-marketer affiliates, the principles apply with equal force to the relationship between Ridgeline and DEH's renewable energy operations. The tariff should include explicit provisions ensuring that Ridgeline does not provide preferential pipeline service to support or disadvantage DEH's wind portfolio or any affiliated generation resource.
C. FERC's Deficiency Item 14 — Specific Requirements
Having analyzed the full text of Deficiency Item 14 (reproduced above and at Appendix A) in the context of Order No. 2222, the broader regulatory landscape, and the specific circumstances of the Ridgeline Pipeline System and DEH, we interpret the Item as requiring the following:
1. Acknowledgment of DER aggregation impact. The tariff must acknowledge the potential impact of DER aggregation growth on gas demand and pipeline scheduling. This is a threshold requirement: FERC Staff expects the tariff to demonstrate awareness that the growth of DER aggregations in the wholesale electric markets may affect the demand for gas transportation on the Ridgeline system.
2. Operational coordination provisions. The tariff must address operational coordination between gas pipeline scheduling and electric market dispatch as affected by DER aggregations. This includes provisions for enhanced intraday nomination flexibility, expedited OFO procedures, and information-sharing protocols with electric system operators.
3. Renewable energy interconnection provisions. The tariff must include provisions addressing renewable energy interconnection scenarios relevant to the Ridgeline system. This requirement is driven in part by DEH's 250 MW wind portfolio, which the Deficiency Letter specifically referenced in noting the applicant's parent company's "publicly disclosed development of renewable energy resources." Importantly, this does not require Ridgeline to create a full renewable energy interconnection tariff — wind turbines do not physically interconnect with natural gas pipelines. Rather, the requirement is for the tariff to address the operational and commercial implications of renewable energy development in the region served by the pipeline.
4. Tariff flexibility. The tariff must include provisions ensuring flexibility to accommodate changing gas-electric dynamics driven by DER growth. This may include mechanisms for periodic reassessment of billing determinants, cost recovery provisions for DER-driven operational costs, and provisions for modification of tariff terms in response to material changes in gas-electric market conditions.
We believe that the recommendations set forth in Section V of this memorandum are responsive to each of these requirements while maintaining Ridgeline's commercial flexibility and supporting the redesigned rate of $0.3140 per Dth.
V. Analysis of Required Tariff Provisions
A. Scheduling and Nomination Flexibility
The current Ridgeline tariff, as originally filed, uses the standard NAESB Wholesale Gas Quadrant ("WGQ") nomination timelines, including the Timely nomination cycle (commencing at 11:30 a.m. Central Clock Time ("CCT") for the following gas day), the Evening nomination cycle (commencing at 6:00 p.m. CCT), and Intraday nomination cycles 1, 2, and 3 (commencing at 10:00 a.m., 2:30 p.m., and 7:00 p.m. CCT, respectively, during the gas day). These nomination cycles align with the standard NAESB WGQ business practice standards and, since Order No. 809, with the electric market scheduling timelines.
While the standard NAESB nomination cycles provide a baseline framework for gas scheduling, they may not be sufficient to accommodate the more volatile gas demand patterns anticipated in a high-DER-penetration scenario. As DER aggregations participate more actively in PJM's wholesale markets, the dispatch of gas-fired generators served by the Ridgeline Pipeline System will be increasingly responsive to real-time changes in DER output. A sudden drop in wind generation across the PJM footprint, for example, could trigger rapid ramp-ups of gas-fired generators and corresponding spikes in gas demand at Ridgeline's delivery points. Conversely, a sustained period of high DER output could reduce gas demand well below scheduled levels, creating pipeline imbalances.
We recommend that the redesigned tariff include enhanced intraday nomination provisions that go beyond the standard NAESB cycles. Specifically:
• Additional intraday nomination flexibility. The tariff should include provisions allowing for supplemental intraday nominations outside the standard NAESB cycles when electric market dispatch changes rapidly due to DER output variability. This could take the form of a "DER-driven scheduling adjustment" provision that permits shippers to submit nomination changes on an accelerated timeline when the shipper demonstrates that the nomination change is responsive to a material change in electric market dispatch driven by DER output variability.
• Real-time scheduling coordination. The tariff should include provisions for real-time scheduling coordination between Ridgeline's gas control center and the relevant electric system operators (in this case, PJM) when DER-driven changes in electric market dispatch create operational challenges for the pipeline. This would not require Ridgeline to participate directly in PJM's dispatch process, but rather to establish communication protocols and operational procedures that allow Ridgeline to anticipate and respond to rapid changes in gas demand driven by DER dispatch.
• Cross-reference to NAESB compliance. Any enhanced intraday nomination provisions must be consistent with NAESB WGQ Version 3.2 business practice standards, as required by Deficiency Item 6. We recommend that the tariff include explicit language confirming compliance with NAESB standards while reserving the right to implement additional scheduling flexibility as warranted by DER-driven market conditions.
The proposed scheduling and nomination flexibility provisions should be drafted in consultation with Braswell and Dr. Orlov to ensure consistency with the overall tariff structure and with the operational capabilities of Ridgeline's gas control center and scheduling systems.
B. Operational Flow Order (OFO) Provisions
DER intermittency — particularly wind intermittency — can cause rapid and unpredictable swings in gas-fired generation output. These swings, in turn, can stress pipeline hydraulic balance by creating sudden changes in gas flow volumes and pressures at delivery points. The Ridgeline Pipeline System's three compressor stations (Wetzel, Mannington, and Waynesburg), with aggregate installed compression of 45,000 HP, provide operational flexibility to manage normal variations in gas flow. However, extreme or rapid demand swings driven by DER output variability may exceed the system's ability to maintain hydraulic balance through normal operating procedures, requiring the issuance of operational flow orders to restore system integrity.
We recommend that the redesigned tariff include provisions for expedited OFO issuance in response to DER-driven demand volatility. Specifically:
• Expedited OFO triggers. The tariff should define specific triggers for expedited OFO issuance, including situations where a material change in gas-fired generation dispatch — driven by changes in DER output — creates a pipeline imbalance exceeding defined tolerance bands. The tolerance bands should be calibrated to the Ridgeline system's hydraulic capabilities and should be developed in consultation with Ridgeline's pipeline engineering team.
• Tolerance bands and penalty provisions. Shippers that fail to comply with OFOs issued in response to DER-driven demand volatility should be subject to penalty provisions consistent with the Commission's policies. These penalty provisions should be coordinated with the penalty revenue crediting mechanism required by Deficiency Item 10, which addresses the disposition of penalty revenue collected under the tariff.
• Shipper notification protocols. The tariff should specify notification protocols for expedited OFO issuance, including electronic notification through Ridgeline's EBB, direct communication with affected shippers, and, where feasible, advance notification based on forecasted DER output changes.
• Coordination with compressor station operations. The tariff should acknowledge that expedited OFO procedures may require Ridgeline to adjust compressor station operations at the Wetzel, Mannington, and Waynesburg stations. The costs associated with such operational adjustments — including additional fuel consumption, maintenance costs, and potential wear on compression equipment — should be addressed through the cost recovery mechanism discussed in Section V.C below.
C. Renewable Energy Interconnection Provisions
The phrase "renewable energy interconnection" in Deficiency Item 14 requires careful interpretation in the context of a natural gas pipeline tariff. Wind turbines, solar panels, and battery storage systems do not physically interconnect with natural gas pipelines. The "interconnection" contemplated by Deficiency Item 14 is not a physical interconnection but rather an operational and commercial relationship between the gas pipeline system and the renewable energy resources that affect gas demand and pipeline operations.
DEH's 250 MW wind portfolio may require coordination with Ridgeline's gas pipeline operations in several ways, even though the wind facilities themselves will not directly interconnect with the gas system. If gas-fired generators at or near the Waynesburg delivery point ramp up to compensate for periods of low wind output — or ramp down when wind output is high — the pipeline must accommodate those swings in gas demand. This dynamic creates a de facto operational relationship between the wind portfolio and the gas pipeline, even in the absence of any physical connection between the two.
We recommend the addition of the following tariff provisions:
1. New section in the General Terms and Conditions. A new section titled "Gas-Electric Coordination and Distributed Energy Resource Provisions" (or, alternatively, "Coordination with Renewable Energy Resources") should be added to the General Terms and Conditions of the redesigned tariff. This section would serve as the primary repository for all DER-related provisions and would be cross-referenced from other relevant tariff sections.
2. Information sharing. The new section should include provisions for information sharing between Ridgeline and electric system operators regarding renewable energy output forecasts. This could include arrangements for Ridgeline to receive forecasted wind and solar generation data from PJM or from individual renewable energy operators (including DEH's wind facilities) to assist in pipeline operations planning and scheduling.
3. Scheduling coordination procedures. The new section should include procedures for coordinating pipeline scheduling with electric market real-time dispatch signals. These procedures would complement the enhanced intraday nomination provisions discussed in Section V.A and would provide a framework for Ridgeline to adjust pipeline operations in response to rapid changes in electric market dispatch driven by DER output variability.
4. Cost recovery mechanism. The new section should include a mechanism to address costs incurred by Ridgeline due to DER-driven demand volatility. Such costs could include additional compression fuel, increased maintenance expense associated with more frequent compressor cycling, administrative costs associated with enhanced scheduling and coordination, and capital costs associated with any system modifications needed to accommodate more volatile gas flow patterns. The mechanism could take the form of a surcharge applied to shippers whose nominations are most affected by DER-driven volatility, or a broader tracker mechanism that socializes DER-related costs across all firm shippers. The choice of mechanism should be developed in consultation with Braswell and Dr. Orlov and should be tested against Commission precedent on cost recovery trackers.
We emphasize the importance of distinguishing in the tariff between physical interconnection of renewable resources to the gas system (which is not applicable — wind turbines do not connect to gas pipelines) and operational coordination between gas and electric systems affected by DER growth (which is applicable and required by Deficiency Item 14). Clear drafting on this point will avoid potential confusion among shippers, intervenors, and FERC Staff and will demonstrate that Ridgeline understands the nature of the gas-electric coordination challenge posed by Order No. 2222.
D. DER Aggregation Impact on Billing Determinants
The long-term growth of DER aggregations in the PJM footprint and more broadly could result in a material reduction in overall gas demand for electricity generation, which would directly affect Ridgeline's throughput and revenue. This concern is not merely theoretical: Ridgeline's current utilization rate of approximately 56.67% of design capacity already indicates significant exposure to demand-side risk. Any incremental reduction in gas demand driven by DER penetration would further widen the gap between design capacity and actual throughput.
The tariff redesign's move from a 100% load factor (as originally filed) to a 75% load factor (as proposed in the redesigned tariff) partially addresses this concern by reducing the billing determinants from 438,000,000 Dth per year to 328,500,000 Dth per year. This adjustment increases the per-unit rate (from $0.2265/Dth to $0.3140/Dth) to ensure that the reduced billing determinants still recover the full cost of service. However, the load factor adjustment does not explicitly link to DER growth or provide a mechanism for ongoing reassessment of billing determinants in light of DER penetration trends.
We recommend that the redesigned tariff include a periodic review mechanism that allows Ridgeline to reassess billing determinants in light of material changes in gas demand driven by DER growth. Specifically:
• Periodic review provision. The tariff should include a provision allowing Ridgeline to file a limited NGA Section 4 rate proceeding, or alternatively to invoke a tariff-based tracker mechanism, to reassess billing determinants in the event that DER-driven demand changes cause actual throughput to deviate materially (e.g., by more than 10%) from the billing determinant assumptions underlying the approved rate.
• DER penetration reporting. The periodic review mechanism could be triggered by defined DER penetration milestones published by PJM or by changes in Ridgeline's actual throughput that are reasonably attributable to DER growth.
• Strategic implications for the load factor dispute. The inclusion of a DER-linked billing determinant review mechanism has strategic implications for the ongoing settlement discussions. MGPC and ATPC have advocated for a load factor of 85% or higher, arguing that Ridgeline's system should be capable of achieving higher utilization. However, a DER-driven demand decline could actually support a lower load factor assumption by demonstrating that gas demand is subject to structural headwinds that reduce the probability of achieving high utilization rates. This argument could bolster Ridgeline's 75% load factor position in settlement or hearing.
E. Affiliate Transaction Provisions
Given DEH's dual role as Ridgeline's sole member and the developer of the 250 MW wind portfolio, the tariff must include robust affiliate transaction provisions that address the specific risks created by this dual identity. The FERC Standards of Conduct at 18 C.F.R. Part 358 provide the general framework, but the tariff should include specific provisions tailored to the gas-electric coordination and DER context.
We recommend the following:
• Non-preferential service provision. The tariff should include explicit language prohibiting Ridgeline from providing preferential pipeline service to support or disadvantage DEH's wind portfolio or any affiliated generation resource. This provision should make clear that Ridgeline will not condition the availability, quality, or pricing of transportation service on a shipper's participation (or non-participation) in DEH's renewable energy operations or on the shipper's competitive relationship with DEH's renewable energy portfolio.
• Anti-tying provisions. The tariff should include anti-tying provisions prohibiting Ridgeline from conditioning transportation service on a shipper's relationship with DEH or any DEH affiliate. These provisions should be drafted broadly to cover any form of tying arrangement, including bundling of gas transportation with renewable energy credits, environmental attribute transactions, or participation in DEH-sponsored energy programs.
• Information firewall. The tariff should include provisions requiring Ridgeline to maintain an information firewall between its gas transportation operations and DEH's renewable energy development activities. While Ridgeline and DEH share common ownership, non-public operational information about pipeline scheduling, capacity availability, and shipper activity should not be shared with DEH's renewable energy development team except through publicly available channels (i.e., the EBB).
• Compliance officer designation. The tariff should require Ridgeline to designate a compliance officer responsible for monitoring and enforcing the affiliate transaction provisions, with periodic reporting to the Commission as required by 18 C.F.R. Part 358.
Ms. Dunmore's 72% equity interest in DEH, and her role as the controlling shareholder of both the pipeline operator and the renewable energy developer, underscores the importance of visible compliance with affiliate transaction rules. FERC Staff and intervenors will scrutinize any tariff provisions that could be perceived as facilitating preferential treatment of DEH's renewable energy interests, and robust affiliate transaction safeguards will be essential to securing approval of the redesigned tariff.
F. Electronic Bulletin Board (EBB) Posting of DER-Related Information
The redesigned tariff's EBB provisions, which are also the subject of Deficiency Item 7, should be expanded to include DER-related operational information. We recommend the following:
• Gas-electric coordination notices. Ridgeline's EBB should include a dedicated section for gas-electric coordination notices, including notices of anticipated DER-driven demand changes, OFO issuances related to renewable energy variability, and other operational information relevant to shippers whose gas nominations may be affected by changes in electric market dispatch driven by DER aggregations.
• Real-time capacity availability data. The EBB should include real-time (or near-real-time) capacity availability data to assist gas-fired generators in making scheduling decisions responsive to DER output changes. If a gas-fired generator anticipates needing to ramp up quickly to compensate for a drop in DER output, access to real-time pipeline capacity data will assist the generator in determining whether pipeline capacity is available to support the required increase in gas nominations.
• DER-related OFO postings. Any OFOs issued on an expedited basis in response to DER-driven demand volatility should be prominently posted on the EBB with clear identification of the DER-related trigger, in addition to standard OFO notification procedures.
• Consistency with Deficiency Item 7. All EBB enhancements related to DER information must be consistent with the broader EBB reforms being developed in response to Deficiency Item 7, which addresses EBB transparency, accessibility, and information content more generally. We recommend that the DER-related EBB provisions be integrated into the overall EBB section of the tariff rather than maintained as a separate, standalone provision.
VI. Survey of Industry Precedent
A. Other Pipeline Tariff Approaches to Order No. 2222
Our survey of recently filed or approved FERC-jurisdictional pipeline tariffs reveals that most natural gas pipelines have not yet comprehensively addressed Order No. 2222 or DER aggregation in their tariff filings. This is not surprising: Order No. 2222's direct obligations run to RTOs and ISOs, and the Commission has not issued a generic rulemaking requiring natural gas pipelines to address DER aggregation in their tariffs. The Deficiency Letter's Item 14 reflects a case-specific initiative by FERC Staff, likely prompted by the unique circumstances of the Ridgeline filing — including DEH's publicly disclosed wind portfolio — rather than a broad policy directive applicable to all pipeline tariffs.
Notwithstanding the general absence of comprehensive DER provisions in pipeline tariffs, several pipelines have addressed gas-electric coordination in ways that provide useful precedent for Ridgeline's tariff redesign:
• Enhanced intraday nomination provisions. Following Order No. 809 (discussed below), several major pipelines revised their tariffs to include enhanced intraday nomination flexibility, including more frequent nomination cycles and expedited scheduling procedures during periods of high electric-sector demand volatility. These provisions, while not specifically tied to Order No. 2222, address the same underlying dynamic of gas demand volatility driven by changes in electric market conditions.
• Gas-electric coordination sections. A small number of pipelines have included dedicated "Gas-Electric Coordination" sections in their tariffs, typically addressing information sharing with electric system operators, coordination of scheduling timelines, and operational procedures for managing gas demand changes driven by electric market conditions. These sections provide a template for the new tariff section recommended in this memorandum.
• OFO provisions referencing electric market conditions. Some pipeline tariffs include OFO trigger criteria that explicitly reference changes in electric market dispatch or electric system emergency conditions as grounds for expedited OFO issuance. These provisions recognize the reality that electric market conditions are a signifi

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