PRIVILEGED & CONFIDENTIAL — ATTORNEY WORK PRODUCT
MEMORANDUM
This memorandum is protected by the attorney-client privilege and constitutes attorney work product. It is intended solely for the use of the named recipients and their authorized agents. Any disclosure, copying, or distribution to any person not authorized to receive this memorandum is strictly prohibited.
FROM: Calderwood & Harkness LLP 1601 K Street NW, Suite 900 Washington, DC 20006
TO: Dunmore Energy Holdings Ltd.
Attn: Patricia Dunmore, Founder & Chairperson
Ridgeline Midstream Services LLC
Attn: James K. Winfield, CEO & President
Dr. Natasha Orlov, Director of Rates & Regulatory
Date: May 2024
Re: Impact of FERC Order No. 2222 on Midstream Pipeline Tariffs — Analysis for Tariff Redesign in Docket Nos. RP22-847-000 and RP22-847-001
C&H Matter No.: 1016-00005
Authors:
George Trujillo, Responsible Partner, Energy & Infrastructure
Brett Callahan, Lead Associate, Energy & Infrastructure
David Stanton, Working Associate, Energy & Infrastructure
Purpose: This memorandum addresses Deficiency Item 14 from the FERC Office of Energy Market Regulation's Deficiency Letter dated January 19, 2023, which cited the failure to address Order No. 2222 distributed energy resource aggregation implications (renewable energy interconnection) in Ridgeline Midstream Services LLC's proposed FERC Gas Tariff, Original Volume No. 1, filed in Docket Nos. RP22-847-000 and RP22-847-001.
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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 potential implications for the tariff applicable to the Ridgeline Pipeline System (the "System"), specifically in the context of the comprehensive tariff redesign being undertaken by Ridgeline Midstream Services LLC ("Ridgeline") to cure all fourteen deficiency items identified by FERC's Office of Energy Market Regulation ("OEMR") in its Deficiency Letter dated January 19, 2023 (the "Deficiency Letter"). The purpose of this analysis is to provide Ridgeline and its parent entity, Dunmore Energy Holdings Ltd. ("DEH"), with the legal and regulatory foundation necessary to draft responsive tariff language and supporting testimony that will satisfy the Commission's concerns as expressed in Deficiency Item 14.
Order No. 2222, which was primarily directed at removing barriers to the participation of distributed energy resources ("DERs") in organized wholesale electric markets operated by Regional Transmission Organizations ("RTOs") and Independent System Operators ("ISOs"), does not directly impose requirements on natural gas pipelines operating under Part 284, Subpart G open-access transportation tariffs. The order addresses the wholesale electric market rules administered by RTOs and ISOs, and its compliance obligations fall on those entities rather than on interstate natural gas pipeline companies jurisdictional under the Natural Gas Act ("NGA"). However, FERC's inclusion of Deficiency Item 14 in the Deficiency Letter signals the Commission's interest in how midstream pipeline tariffs may accommodate or interact with emerging DER aggregation and renewable energy integration. This signal should not be dismissed. The staff-level inquiry suggests that FERC is developing a more expansive view of gas-electric coordination obligations, and the Commission may increasingly expect natural gas pipeline tariff filings to address the downstream and cross-sectoral effects of evolving electric market structures.
DEH's 250 MW wind portfolio currently under development adds a unique and significant dimension to this analysis. The parent company's renewable energy activities may create synergies or conflicts with the Ridgeline Pipeline System's tariff structure, and FERC staff appears interested in how the tariff addresses potential dual-fuel or hybrid interconnection scenarios. The factual predicate of common ownership between a natural gas pipeline and wind generation assets is precisely the type of arrangement that may prompt heightened regulatory scrutiny, particularly in light of FERC's affiliate transaction policies and the standards of conduct applicable under 18 C.F.R. Part 358.
Based on our analysis, we recommend the following approach: Ridgeline should include targeted provisions in the redesigned FERC Gas Tariff, Original Volume No. 1 (the "Redesigned Tariff") that address renewable energy interconnection at Ridgeline system points, DER-related gas demand variability, and coordination with electric grid operators. These provisions should be drafted as a new section within the General Terms and Conditions of the Redesigned Tariff, and should be accompanied by supplemental pre-filed testimony from Dr. Natasha Orlov explaining their purpose and regulatory basis. At the same time, the provisions must be carefully scoped to preserve the primary focus on the Part 284 open-access gas transportation framework and should not inadvertently expand Ridgeline's regulatory obligations beyond what is required to satisfy the Deficiency Letter.
This analysis has been coordinated with Braswell Energy Consulting Group LLC ("BEC"), Engagement No. BEC-2023-0041, led by Dr. Raymond Braswell, which is developing the economic modeling for the tariff redesign. Dr. Braswell's team is incorporating the Order No. 2222 analysis into the fourth draft of the Redesigned Tariff (near-final working version dated November 2024), and we anticipate that the economic modeling of DER-driven demand variability will also support Ridgeline's revised load factor assumptions, which are separately at issue in connection with Deficiency Item 4.
II. Background
A. The Ridgeline Pipeline System and Current Proceeding
Ridgeline Midstream Services LLC is a Delaware limited liability company and a wholly-owned subsidiary of Dunmore Energy Holdings Ltd., a Cayman Islands exempted company. Ridgeline owns and operates the Ridgeline Pipeline System, a 187-mile, 24-inch-diameter high-pressure natural gas pipeline extending from the Wetzel County Interconnect in Wetzel County, West Virginia, to the Waynesburg Compressor Station in Greene County, Pennsylvania. The System traverses the core of the Appalachian Basin's prolific Marcellus and Utica shale formations and serves as a critical link in the regional natural gas gathering and transportation infrastructure.
The Ridgeline Pipeline System has a design capacity of 1.2 billion cubic feet per day ("Bcf/d"), equivalent to 1,200,000 dekatherms per day ("Dth/d") at an assumed heat content of 1,000 British thermal units per cubic foot ("BTU/cf"). Current throughput on the System is approximately 680 million cubic feet per day ("MMcf/d"), representing a utilization rate of approximately 56.67 percent. The System is supported by three compressor stations—the Wetzel Station (located near the Wetzel County Interconnect), the Mannington Station (located in Marion County, West Virginia), and the Waynesburg Station (located at the downstream terminus in Greene County, Pennsylvania)—with aggregate installed compression of 45,000 horsepower ("HP"). The System was placed in service on October 1, 2021, and was constructed at an original cost of approximately $587.2 million.
On May 12, 2022, Ridgeline filed its application for an initial tariff rate and interconnection authorization with FERC in Docket Nos. RP22-847-000 (the rate case docket) and RP22-847-001 (the interconnection docket). The filing sought approval of a Part 284, Subpart G open-access transportation tariff, designated as FERC Gas Tariff, Original Volume No. 1, with a proposed initial recourse rate of $0.2265 per dekatherm ("Dth"). The rate was derived using a cost-of-service methodology based on the System's original construction cost, projected operating expenses, and a 100 percent load factor billing determinant.
Calderwood & Harkness LLP ("C&H") represents Ridgeline and DEH in all matters related to the proceeding. Patricia Dunmore serves in a dual capacity as both DEH Chairperson (holding a 72 percent controlling equity interest in DEH) and as the C&H billing partner for this engagement. This dual role has been fully disclosed to all relevant parties and has been the subject of a written conflict waiver executed by both DEH and Ridgeline, consistent with the applicable Rules of Professional Conduct. No challenge to this arrangement has been raised by any party to the proceeding or by FERC staff.
B. FERC Deficiency Letter and Item 14
On January 19, 2023, the FERC Office of Energy Market Regulation issued the Deficiency Letter, identifying fourteen separate deficiencies in Ridgeline's tariff filing. The Deficiency Letter was signed by the Director of OEMR and prepared under the supervision of Dr. Miriam Okafor, the lead economic analyst assigned to the Ridgeline proceeding. The fourteen deficiency items ranged from technical rate design issues (such as the load factor assumption and the interruptible transportation rate derivation) to structural tariff provisions (such as NAESB compliance, capacity release mechanisms, and segmentation) to broader policy-oriented concerns.
Deficiency Item 14, the final item in the letter and the subject of this memorandum, specifically cited the "failure to address Order No. 2222 distributed energy resource aggregation implications (renewable energy interconnection)" in Ridgeline's proposed tariff. The full text of Item 14 is reproduced in Appendix A to this memorandum. The item's inclusion in the Deficiency Letter is notable because Order No. 2222 is, on its face, directed at RTO/ISO market rules rather than at NGA-jurisdictional natural gas pipeline tariffs. FERC staff's decision to include this item suggests either an expansive interpretation of the tariff filing requirements applicable to new gas pipelines or a specific concern prompted by DEH's known renewable energy activities. We believe the latter is the more likely explanation, as discussed further in Section V below.
Following the issuance of the Deficiency Letter, Administrative Law Judge Clara Whitfield, who was assigned to preside over the proceeding, stayed the Track II procedural schedule on February 6, 2023, pending Ridgeline's response to the deficiency items. Ridgeline filed a partial response on March 15, 2023, addressing eight of the fourteen items—specifically, Items 1 through 4 and Items 7 through 10. The partial response did not address Item 14, which required more extensive analysis and coordination with outside consultants.
Since the initial partial response, three extensions of time have been granted by ALJ Whitfield to allow Ridgeline to complete the Redesigned Tariff addressing all remaining deficiency items. The extensions were granted by orders dated May 10, 2023; September 8, 2023; and March 4, 2024. The current deadline for filing the complete Redesigned Tariff and all supplemental testimony is February 21, 2025. The proceeding has been designated "dormant" since the September 8, 2023 order, and quarterly status reports have been required since the March 4, 2024 order. Ridgeline has filed three such status reports to date: June 15, 2024; September 14, 2024; and December 13, 2024. Each status report has confirmed that the tariff redesign is proceeding and that Ridgeline intends to meet the February 21, 2025 deadline.
C. DEH's Renewable Energy Portfolio
Understanding DEH's broader business portfolio is essential to this analysis. DEH is a diversified energy infrastructure holding company with assets spanning the natural gas midstream value chain and, increasingly, the renewable energy sector. In addition to the Ridgeline Pipeline System, DEH's portfolio includes approximately 1,200 miles of midstream gathering and transportation pipelines located primarily in the Appalachian Basin, as well as two cryogenic gas processing plants with combined processing capacity in excess of 1.5 Bcf/d. DEH's enterprise value is estimated at approximately $2.8 billion based on an internal valuation dated December 31, 2023, and consolidated annual revenue for the 2023 fiscal year was approximately $485 million.
Critically for this analysis, DEH has a 250 MW wind portfolio currently under development. While the specific location and development timeline of the wind portfolio have not been disclosed in the current FERC filing, the existence of the portfolio is a matter of public record through DEH's other regulatory filings and corporate disclosures. The wind portfolio's relationship to the natural gas midstream assets is directly relevant to the inquiry posed by Deficiency Item 14 because FERC staff's Deficiency Letter appears to contemplate scenarios in which renewable energy resources interconnect with, depend upon, or otherwise interact with natural gas pipeline systems for purposes of backup power, load balancing, or co-located energy infrastructure. The fact that DEH controls both a natural gas pipeline and a wind generation portfolio under common ownership creates a factual predicate that makes the Order No. 2222 analysis particularly salient and may explain why FERC staff included Item 14 in the Deficiency Letter.
III. Overview of FERC Order No. 2222
A. Regulatory History and Purpose
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, and is reported at 172 FERC ¶ 61,247. The order represented a landmark rulemaking in the Commission's ongoing efforts to modernize wholesale electric market rules and facilitate the integration of emerging energy technologies into the nation's energy infrastructure. The rulemaking proceeding was initiated under Docket No. RM18-9-000, and the final rule was adopted following an extensive notice-and-comment process that generated thousands of comments from a broad cross-section of industry participants, consumer advocates, state regulators, and environmental organizations.
The fundamental purpose of Order No. 2222 is to remove barriers to the participation of DER aggregations in the organized wholesale electric markets operated by RTOs and ISOs. Prior to the order, most RTO/ISO market rules either prohibited or severely limited the ability of small-scale distributed energy resources to participate directly in wholesale capacity, energy, and ancillary services markets. Individual DERs—such as a single residential rooftop solar installation, a behind-the-meter battery storage system, or a commercial demand response resource—are typically too small to meet the minimum size requirements for wholesale market participation. Order No. 2222 addressed this barrier by requiring RTOs and ISOs to establish rules that allow aggregations of DERs to participate in their markets on a comparable basis with traditional generation resources, subject to certain conditions designed to ensure reliability and coordination with distribution utilities and relevant electric retail regulatory authorities.
The order defines DERs broadly to include any resource located on the distribution system, any subsystem thereof, or behind a customer meter. This definition encompasses, but is not limited to, electric storage resources, intermittent generation resources (including solar photovoltaic and wind), 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 captures a wide range of technologies that may interact with the natural gas system in different ways—some by displacing gas-fired generation, some by increasing the need for gas-fired backup, and some by creating new patterns of energy consumption and production that affect gas demand in complex and sometimes unpredictable ways.
Order No. 2222 requires each RTO and ISO to revise its tariff to allow DER aggregations to register and participate in the wholesale markets for capacity, energy, and ancillary services. The order establishes minimum requirements for these tariff revisions, including provisions addressing aggregation size, geographic scope, metering and telemetry, coordination with distribution utilities, and the role of aggregators as market participants. The order also addresses the interaction between wholesale and retail DER programs, seeking to minimize conflicts between FERC-jurisdictional wholesale market rules and state-jurisdictional retail programs.
Two subsequent orders addressed clarifications and rehearing requests. Order No. 2222-A was issued in March 2021 and provided additional guidance on several issues raised during the rehearing process, including the treatment of demand response resources and the coordination requirements between RTOs/ISOs and distribution utilities. Order No. 2222-B was issued in June 2022 and addressed remaining rehearing issues, including the geographic scope of DER aggregations and the applicability of minimum size thresholds. Together, the three orders constitute the complete Order No. 2222 rulemaking and establish the current regulatory framework for DER aggregation in wholesale electric markets.
B. Applicability to Natural Gas Pipelines
A threshold question in this analysis is the extent to which Order No. 2222 applies to, or creates obligations for, interstate natural gas pipelines such as Ridgeline. The short answer is that Order No. 2222 does not directly apply to natural gas pipelines. The order is directed at RTOs and ISOs and their wholesale electric market tariffs. It was promulgated under the Commission's authority under the Federal Power Act ("FPA"), specifically Sections 205 and 206 (16 U.S.C. §§ 824d, 824e), and not under the Natural Gas Act (15 U.S.C. § 717 et seq.) or any of the implementing regulations codified at 18 C.F.R. Parts 154, 157, or 284 that govern natural gas pipeline tariffs and certificates.
No provision of Order No. 2222 explicitly addresses interstate natural gas pipeline tariffs, natural gas transportation rates, or the terms and conditions of open-access natural gas transportation service. The order does not amend any regulation applicable to natural gas pipelines, and it does not impose any reporting, compliance, or tariff revision obligations on NGA-jurisdictional entities. To the extent Order No. 2222 references natural gas at all, it does so only in the context of discussing the broader energy system interactions between gas and electric infrastructure—a topic that has been the subject of extensive FERC attention in other proceedings, including the gas-electric coordination dockets that followed the 2014 Polar Vortex and subsequent winter reliability events.
However, the absence of a direct legal mandate does not mean that Order No. 2222 is irrelevant to natural gas pipeline tariff proceedings. The order has significant indirect implications for gas pipelines to the extent that DER aggregation increases variability in gas-fired generation demand, alters load profiles on the gas system, and creates new patterns of gas nomination and scheduling that must be accommodated by pipeline tariff provisions. Moreover, FERC staff's decision to include Order No. 2222 in the Deficiency Letter for a natural gas pipeline tariff filing demonstrates that the Commission is prepared to consider the gas-electric coordination implications of Order No. 2222 in the context of NGA proceedings, even if the order itself does not formally apply. This is consistent with the Commission's broader trend toward viewing the gas and electric systems as interdependent and expecting pipeline operators to design tariffs that account for changing patterns of gas consumption driven by electric market developments.
C. Key Provisions Relevant to Gas-Electric Coordination
Several specific aspects of Order No. 2222 have particular relevance to gas-electric coordination and, by extension, to the design of natural gas pipeline tariffs serving markets with significant gas-fired electric generation.
First, DER aggregation may fundamentally alter the load patterns of gas-fired electric generators that are shippers on pipelines like Ridgeline. As DER aggregations grow in scale and market penetration, they will increasingly compete with gas-fired generators in the dispatch stack for energy and ancillary services. This competition will tend to displace gas-fired generation during periods when DER output is high (e.g., midday for solar-heavy aggregations, or during sustained high-wind periods for wind-heavy aggregations) and increase reliance on gas-fired generation during periods when DER output is low or unavailable. The result is a more variable and less predictable pattern of gas demand from the electric generation sector.
Second, the increased penetration of variable renewable energy resources—particularly wind and solar—into electric markets can increase the ramping requirements imposed on gas-fired generators. Gas-fired units may be called upon to ramp up quickly when renewable output drops and to ramp down quickly when renewable output surges. These ramping events translate directly into more volatile intraday gas nominations and scheduling requests on the pipeline system. The current NAESB nomination cycles (Timely, Evening, Intraday 1, Intraday 2, and Intraday 3) may come under increasing pressure as gas-fired generators seek greater scheduling flexibility to match the variable dispatch patterns created by DER competition.
Third, Order No. 2222's allowance for heterogeneous DER aggregations—meaning aggregations that combine different types of resources, such as solar generation, battery storage, and demand response, within a single market participant—may create complex and unpredictable dispatch patterns that cascade through to the gas system. For example, a heterogeneous DER aggregation that includes both solar generation and battery storage may be dispatched to provide energy during morning and evening peak hours (when the battery discharges) while the solar component provides energy during midday. The net effect on gas-fired generators depends on the size, composition, and dispatch strategy of the aggregation, as well as on the local market conditions—all of which creates uncertainty for gas pipeline operators attempting to forecast gas demand and manage system operations.
Fourth, Order No. 2222 requires RTOs and ISOs to allow DER aggregations to participate in ancillary services markets, including frequency regulation and spinning reserves. Gas-fired generators are currently significant providers of these services, and the entry of DER aggregations into these markets may displace gas-fired ancillary service provision, further altering gas demand patterns. The displacement effect may be particularly pronounced for fast-responding gas-fired units (such as combustion turbines and aeroderivative units) that are currently relied upon for frequency regulation, because battery storage resources—a common component of DER aggregations—are highly competitive in providing fast-response regulation services.
These considerations collectively establish that Order No. 2222, while not directly applicable to natural gas pipeline tariffs, has the potential to significantly affect the operating environment in which pipelines like Ridgeline provide service. The Redesigned Tariff should acknowledge and account for these dynamics, as discussed in the following sections.
IV. Analysis of Order No. 2222's Impact on Midstream Pipeline Tariffs
A. Gas-Electric Interdependency Considerations
The Ridgeline Pipeline System does not directly serve gas-fired electric generators. Rather, Ridgeline delivers gas into the broader Appalachian market via its interconnection with Appalachian Trunk Pipeline Company, LLC ("ATPC") at the Wetzel County Interconnect. ATPC operates a 640-mile, 3.8 Bcf/d transmission system serving markets in Pennsylvania, Ohio, and New York. ATPC's shipper base includes several gas-fired electric generating facilities that participate in the PJM Interconnection LLC ("PJM") wholesale electric market, as well as local distribution companies ("LDCs") serving residential, commercial, and industrial end-users throughout the region.
The gas-electric interdependency that is relevant to this analysis operates through the chain of physical and contractual relationships connecting Ridgeline to downstream gas-fired generators. Gas produced in the Marcellus and Utica shale formations enters the Ridgeline Pipeline System at various receipt points, is transported through the 187-mile System, and is delivered to ATPC at the Wetzel County Interconnect. ATPC then transports the gas to downstream delivery points, including points serving gas-fired electric generators. When those generators experience changes in dispatch patterns driven by DER competition under Order No. 2222, the effects propagate upstream through the pipeline network and ultimately affect the demand for transportation service on the Ridgeline Pipeline System.
As DER aggregation grows under Order No. 2222, gas-fired generators on ATPC's system may face more variable dispatch profiles. This variability increases the importance of flexible gas transportation service on upstream pipelines like Ridgeline. Shippers that are gas-fired generators, or that aggregate gas supply for gas-fired generators, may require more frequent changes in their nominated quantities, greater access to interruptible and short-term firm transportation service, and more flexible receipt and delivery point arrangements. The Ridgeline Pipeline System's proposed interconnection design capacity at the Wetzel County Interconnect is 800 MMcf/d bidirectional, expandable to 1.2 Bcf/d, which should provide sufficient physical capacity to accommodate increased variability in gas flows. However, the tariff provisions governing how that capacity is accessed, allocated, and scheduled must also reflect the evolving demand dynamics.
It is also worth noting that ATPC itself may face pressure to revise its own tariff provisions in response to DER-driven changes in its shipper base. To the extent ATPC implements enhanced flexibility provisions in its tariff, Ridgeline's tariff should be compatible with and complementary to those provisions, particularly with respect to nomination and scheduling procedures, operational flow orders, and capacity release mechanisms. Coordination between upstream and downstream pipeline tariffs is essential to ensuring that the overall pipeline network can respond efficiently to changes in gas demand patterns driven by electric market developments.
B. Nomination and Scheduling Flexibility
Order No. 2222's impact on gas nomination patterns suggests that Ridgeline's tariff should include provisions addressing intraday nomination flexibility. This is an area where the Order No. 2222 analysis intersects directly with Deficiency Item 6, which cited deficiencies in Ridgeline's operational flow order ("OFO") provisions and NAESB compliance. The current version of the proposed tariff does not fully comply with the North American Energy Standards Board ("NAESB") Wholesale Gas Quadrant ("WGQ") Version 3.2 standards for gas nomination and scheduling, and the Deficiency Letter specifically identified the need for more complete NAESB-compliant scheduling provisions.
The NAESB WGQ Version 3.2 standards establish five nomination cycles within each gas day: the Timely Nomination Cycle, the Evening Nomination Cycle, and three Intraday Nomination Cycles (Intraday 1, Intraday 2, and Intraday 3). These cycles were designed, in part, to provide gas-fired electric generators with greater scheduling flexibility to respond to changing electric market conditions—a concern that predates Order No. 2222 but is made more acute by the order's facilitation of DER aggregation. The Redesigned Tariff should incorporate all five nomination cycles with the timing, deadlines, and confirmation procedures specified in the NAESB standards, and should include provisions allowing shippers to adjust their nominations within and across cycles to respond to intraday changes in gas demand.
Existing tariff provisions on OFOs were cited as incomplete in Deficiency Item 6. OFOs are the mechanism by which a pipeline operator directs shippers to adjust their gas flows to maintain system integrity and operational balance. In an environment of increasing gas demand variability driven by DER-related dispatch changes, OFOs may need to be issued more frequently and with greater specificity. The Redesigned Tariff should incorporate more granular OFO provisions that specify the conditions under which OFOs may be issued, the magnitude of flow adjustments that may be required, the penalties for non-compliance, and the procedures for OFO notification and confirmation. These provisions should be designed to accommodate the type of rapid demand swings that may result from the variable dispatch of gas-fired generators competing with DER aggregations in the PJM and other wholesale electric markets.
Coordination with Deficiency Item 5 (capacity release provisions) and Deficiency Item 12 (segmentation and flexible receipt/delivery point provisions) is also important in this context. Enhanced capacity release provisions may allow shippers to release unused firm transportation capacity on short notice when gas-fired generators are displaced by DER output, enabling other shippers to use that capacity productively. Similarly, flexible receipt and delivery point provisions may allow shippers to redirect gas flows within the Ridgeline Pipeline System in response to changing demand patterns, reducing the risk of imbalances and improving overall system efficiency.
C. Interruptible Transportation Service Implications
The increased penetration of DERs into wholesale electric markets may lead to more variable demand for interruptible transportation ("IT") service on the Ridgeline Pipeline System. Gas-fired generators that do not hold firm transportation capacity on the System, or that hold firm capacity only for a portion of their potential gas consumption, may seek IT service on a more sporadic and unpredictable basis as their dispatch profiles become more variable in response to DER competition. Generators that were previously baseload or intermediate-duty resources may increasingly operate in a peaking or load-following mode, creating demand for IT service during periods when DER output is low but reducing or eliminating gas demand during periods when DER output is high.
The Redesigned Tariff's IT rate was separately addressed in the September 2023 IT rate memorandum prepared by Calderwood & Harkness in connection with Deficiency Item 3. That memorandum analyzed the appropriate IT rate derivation methodology, including the question of whether the IT rate should be set at the maximum firm recourse rate (as proposed in the original tariff filing) or at a discounted rate reflecting the lower priority and interruptible nature of the service. In light of the Order No. 2222 analysis presented in this memorandum, we recommend that the IT rate derivation be reviewed for consistency with the demand variability considerations discussed herein. Specifically, if DER-driven variability increases the value of IT service to shippers during peak demand periods (when DER output is low and gas-fired generators are dispatched at high levels), the IT rate structure should be designed to capture that value while maintaining the non-discriminatory rate structure required by FERC's open-access policy.
We also note that increased IT service variability may affect Ridgeline's revenue projections and, consequently, its cost-of-service calculations. If IT service revenues become more volatile, the Redesigned Tariff's reservation and usage charge structure should be designed to ensure that firm shippers bear the costs of the System on a stable and predictable basis, with IT service revenues flowing through the appropriate revenue crediting mechanism. This consideration should be addressed in coordination with Dr. Braswell's economic modeling for the tariff redesign.
D. Impact on Load Factor Assumptions
The load factor assumption is one of the most consequential elements of the Ridgeline rate case and has been a focal point of disagreement among the parties. Ridgeline's original tariff filing assumed a 100 percent load factor for the billing determinant calculation, resulting in a billing determinant of 438,000,000 Dth per year (1,200,000 Dth/d × 365 days) and a proposed initial recourse rate of $0.2265/Dth. Deficiency Item 4 challenged this assumption, and the revised tariff redesign currently under development uses a 75 percent load factor, resulting in a billing determinant of 328,500,000 Dth per year and a revised proposed recourse rate of $0.3140/Dth, allocated as $0.3102 for the reservation charge and $0.0038 for the usage charge.
The intervenors have taken different positions on the appropriate load factor. ATPC and the Mountainside Gas Producers Coalition ("MGPC") advocate for a load factor of 85 percent or higher, which would reduce the recourse rate. ATPC's position is motivated in part by its interest in ensuring competitive rates on the Ridgeline Pipeline System to maintain the attractiveness of gas supplies flowing through the Wetzel County Interconnect onto ATPC's system. MGPC's position reflects the interest of independent natural gas producers in maximizing pipeline throughput and minimizing the transportation costs embedded in the netback prices they receive for their gas production.
The Order No. 2222 analysis presented in this memorandum provides additional analytical support for Ridgeline's 75 percent load factor position. DER-driven variability in gas demand supports a lower load factor assumption because gas-fired generators may use pipeline capacity less uniformly as their dispatch profiles become more variable. If gas-fired generators are increasingly dispatched in a load-following or peaking mode rather than a baseload mode—as anticipated in an environment of growing DER penetration—they will require pipeline capacity during peak periods but will not utilize that capacity consistently throughout the gas day or across all days of the year. This pattern of use is precisely what a lower load factor is designed to capture: it reflects the reality that shippers will reserve capacity for peak needs but will not use all of that capacity at all times.
We anticipate that MGPC's rate expert, Dr. Eleanor Vasquez, may challenge this argument at hearing. Dr. Vasquez may contend that DER penetration in the PJM and other electric markets served by downstream pipelines is not yet sufficient to materially affect the load factor on the Ridgeline Pipeline System, or that the relationship between DER penetration and gas demand variability is too speculative to support a specific load factor adjustment. To counter this anticipated argument, Calderwood & Harkness should coordinate with Dr. Braswell to develop economic modeling of DER-related demand variability impacts on the Ridgeline Pipeline System's load factor. This modeling should draw on publicly available data from PJM and other RTOs regarding current and projected DER penetration levels, as well as on industry studies analyzing the relationship between renewable energy growth and gas-fired generation dispatch patterns.
The load factor issue is further complicated by the fact that the parties remain approximately $0.058/Dth apart on the rate—with Ridgeline proposing $0.3140/Dth and the ATPC/MGPC coalition advocating for an effective ceiling of approximately $0.2560/Dth. Any settlement of the rate case will likely require compromise on the load factor assumption, and the DER variability analysis may provide a useful analytical bridge between the parties' positions. This settlement dynamic is discussed further in Section IX.C below.
V. DEH's 250 MW Wind Portfolio: Tariff Implications
A. Nature of the Wind Portfolio
As noted in Section II.C above, DEH has a 250 MW wind portfolio currently under development. The wind portfolio represents a strategic diversification of DEH's asset base from its traditional natural gas midstream operations into the renewable energy sector. While the specific location and timeline of the wind portfolio have not been specified in the current FERC filing—and DEH may wish to consider the extent to which additional disclosure is necessary or advisable in the supplemental testimony—the existence of the portfolio is a matter of public record and is almost certainly known to FERC staff and to the intervenors in this proceeding.
The wind portfolio raises a fundamental question for the Ridgeline tariff redesign: should the tariff address scenarios involving physical or operational coordination between natural gas transportation and renewable energy generation assets owned by the same parent company? FERC staff's inclusion of Item 14 in the Deficiency Letter suggests that the Commission believes the answer is yes, at least to the extent of demonstrating that the tariff accommodates the potential interactions between these asset classes. The challenge for Ridgeline is to address this concern in a manner that satisfies FERC staff without creating unnecessary regulatory exposure or voluntarily expanding the scope of FERC's jurisdiction over DEH's renewable energy activities.
B. Potential Interconnection Scenarios
We have identified three principal scenarios in which DEH's wind portfolio could interact with the Ridgeline Pipeline System in ways that have tariff implications. Each scenario is discussed below, along with an assessment of the likelihood of the scenario materializing and the tariff provisions that would be needed to address it.
Scenario 1: Wind Power to Compressor Stations. DEH's wind generation facilities could potentially be co-located near one or more of Ridgeline's three compressor stations (Wetzel Station, Mannington Station, or Waynesburg Station). In this scenario, wind-generated electricity could provide power to the electric motor drives used at the compressor stations, thereby reducing the pipeline's consumption of fuel gas for compression. This would have a direct effect on the fuel, lost, and unaccounted-for gas ("FL&U") tracker mechanism, which is the subject of Deficiency Item 2. If wind power displaces a portion of the compressor fuel gas that would otherwise be consumed, the FL&U percentage assessed against shippers would decrease, reducing shippers' overall cost of transportation service. However, this reduction would need to be reflected in the FL&U tracker on a transparent and non-discriminatory basis, and the tariff should specify how wind-powered compression is accounted for in the FL&U calculation. Additionally, the reliability of wind power as a source of compressor station electricity must be addressed, as compressor station operations cannot be interrupted by wind variability without potentially triggering operational flow orders or system curtailments.
Scenario 2: Wind Generation Displacing Gas-Fired Generation. If DEH's wind generation facilities operate in a market served by gas-fired electric generators that receive gas through the Ridgeline Pipeline System (directly or via ATPC), the wind generation could displace gas-fired generation and thereby reduce throughput on the Ridgeline Pipeline System by reducing downstream gas demand. This scenario does not create a direct tariff issue per se, because the reservation charge structure of the Redesigned Tariff is designed to ensure that Ridgeline recovers its cost of service regardless of actual throughput levels. Firm shippers pay the reservation charge whether or not they actually use their reserved capacity, and the reservation charge accounts for the vast majority of Ridgeline's revenue requirement. However, this scenario does create a cost allocation issue for shippers: if gas demand declines as a result of wind generation displacing gas-fired generation, the load factor on the pipeline may decrease, potentially leading to a higher reservation rate in future rate proceedings. The tariff's reservation charge structure mitigates the immediate revenue risk for Ridgeline but may shift costs to remaining shippers over time.
Scenario 3: Hybrid Marketing Arrangements. DEH could develop hybrid projects in which wind power and natural gas transportation are marketed together as a bundled energy product. For example, DEH could offer a combined product to gas-fired generators that includes firm transportation on the Ridgeline Pipeline System paired with a specified quantity of wind-generated electricity, with the gas transportation serving as the backup fuel supply for periods when wind generation is insufficient. Such hybrid products would potentially require new rate schedule provisions or service agreements in the Redesigned Tariff, and would need to be structured carefully to comply with FERC's unbundling requirements and open-access principles. While this scenario is the most speculative of the three, it represents the type of innovative business model that DEH's diversified asset base could support, and the Redesigned Tariff should be designed with sufficient flexibility to accommodate such arrangements if they are pursued in the future.
C. Affiliate and Self-Dealing Considerations
The common ownership of the Ridgeline Pipeline System and the DEH wind portfolio creates potential affiliate transaction and self-dealing concerns that must be carefully managed in the Redesigned Tariff. FERC policy on affiliate transactions, codified in part at 18 C.F.R. Part 358 (Standards of Conduct for Transmission Providers), requires that interstate natural gas pipelines maintain independence between their transportation function and their marketing function, and that they provide non-discriminatory access to all shippers regardless of affiliate relationships. While the Part 358 standards of conduct were primarily designed to address the relationship between pipelines and their marketing affiliates, the principles underlying these standards—non-discrimination, transparency, and the prevention of undue self-dealing—apply with equal force to any arrangement in which a pipeline's affiliated renewable energy assets receive preferential treatment in connection with pipeline services.
The Redesigned Tariff should include provisions ensuring non-discriminatory access and transparency in any arrangements between Ridgeline and DEH-affiliated renewable energy projects. These provisions should specify that any interconnection of DEH renewable energy facilities at Ridgeline system points is subject to the same tariff terms, conditions, and procedures that would apply to a non-affiliated party seeking a comparable interconnection. The provisions should also require disclosure of any operational arrangements between Ridgeline and DEH renewable energy projects, including arrangements for the supply of electricity to compressor stations, the sharing of land or easements, or the joint marketing of energy products. Finally, the provisions should establish a mechanism for resolving complaints by non-affiliated shippers who believe that the Ridgeline-DEH relationship has resulted in discriminatory treatment.
We note that FERC's open-access principles are central to the regulatory framework governing interstate natural gas pipelines, and any real or perceived deviation from these principles could expose Ridgeline to enforcement action or to challenges by intervenors in this proceeding. The tariff provisions addressing affiliate and self-dealing considerations should be drafted conservatively and should err on the side of over-disclosure and transparency.
D. Recommended Tariff Provisions for Renewable Energy Interconnection
Based on the analysis set forth above, we recommend the inclusion of a new section in the General Terms and Conditions of the Redesigned Tariff addressing "Renewable Energy Interconnection and Coordination." This section should be added as a distinct article within the General Terms and Conditions, following the existing provisions on interconnection procedures but before the miscellaneous provisions at the end of the tariff. The recommended content of this new section is summarized below, with detailed draft tariff language provided in Appendix C:
(i) Process for Requesting Physical Interconnection. Provisions establishing a clear, transparent process for any party—whether affiliated or non-affiliated with Ridgeline or DEH—to request the physical interconnection of renewable energy facilities at Ridgeline system receipt or delivery points. The process should include application requirements, technical specifications, engineering review procedures, and timelines for Ridgeline's response.
(ii) Cost Allocation for Facilities Modifications. Provisions addressing the allocation of costs for any facilities modifications required to accommodate renewable energy interconnections, consistent with cost-causation principles and the interconnection cost allocation framework being developed for the Wetzel County Interconnect. The existing cost allocation for the Wetzel County Interconnect ($22.3 million total; Ridgeline $7.6 million / 34.1%; ATPC $14.7 million / 65.9%) provides a useful precedent for the allocation methodology.
(iii) Non-Discrimination and Open-Access Requirements. Provisions ensuring that all services involving renewable energy coordination are provided on a non-discriminatory basis and in compliance with FERC's open-access principles and the standards of conduct under 18 C.F.R. Part 358.
(iv) Metering and Measurement Standards. Provisions specifying the metering and measurement standards applicable to gas flows that are associated with renewable energy interconnections, including standards for the measurement of fuel gas savings attributable to wind-powered compression.
(v) Interaction with FL&U Tracker and GHG Cost Recovery Mechanisms. Provisions addressing how renewable energy interconnections interact with the FL&U tracker (Deficiency Item 2) and the greenhouse gas cost recovery mechanism (Deficiency Item 13), ensuring that the effects of renewable energy integration on these mechanisms are captured accurately and transparently.
(vi) Coordination with NAESB-Compliant Nomination and Scheduling Procedures. Provisions addressing how renewable energy interconnections interact with the nomination and scheduling procedures in the Redesigned Tariff, including any special scheduling requirements that may arise from the integration of variable renewable energy resources.
(vii) Reporting and Electronic Bulletin Board Requirements. Provisions requiring Ridgeline to post information regarding renewable energy interconnections and related services on its electronic bulletin board ("EBB"), consistent with FERC's transparency requirements.
VI. Survey of Other Pipeline Responses to Order No. 2222
A. Industry Trends
Order No. 2222 is a relatively recent rulemaking, and the compliance filing process at the RTO/ISO level has been protracted—several RTOs and ISOs have not yet received full FERC approval of their Order No. 2222 compliance filings as of the date of this memorandum. In this regulatory environment, few interstate natural gas pipelines have yet incorporated specific provisions addressing DER aggregation in their tariffs. The concept of including DER-related provisions in a natural gas pipeline tariff is largely without precedent, and Ridgeline's Redesigned Tariff may be among the first to include such provisions.
FERC staff's inclusion of Order No. 2222 in the Deficiency Letter for a midstream gas pipeline tariff may represent an emerging regulatory expectation that will become standard for new tariff filings and, eventually, for tariff revisions by existing pipelines. This expectation is consistent with the Commission's broader policy direction favoring enhanced gas-electric coordination, which has been manifested in a series of Commission orders, policy statements, and staff reports over the past decade. Notable examples include the Commission's orders on gas-electric coordination following the 2014 Polar Vortex, the Commission's 2018 policy statement on gas-electric harmonization, and the Commission's ongoing attention to fuel assurance issues in the context of winter reliability assessments.
Our survey of available precedent from other FERC-jurisdictional pipelines has identified limited examples of tariff provisions that directly address renewable energy coordination. Some pipelines have included general provisions in their tariffs addressing the coordination of pipeline operations with electric grid operations, typically in the context of electric-driven compression or emergency service provisions. A small number of pipelines that have recently filed new or revised tariffs have included brief references to gas-electric interdependency in their general terms and conditions, but none have included the type of comprehensive renewable energy interconnection provisions that we are recommending for the Redesigned Tariff. In this respect, Ridgeline has an opportunity to position its tariff as forward-looking and responsive to the evolving energy landscape—a posture that should be favorably received by FERC staff and that may reduce the risk of further deficiency proceedings.
B. Differentiation from Electric Utility Compliance
It is important to distinguish Ridgeline's compliance obligation from the direct compliance obligations imposed on RTOs and ISOs by Order No. 2222. Ridgeline is not required to implement DER aggregation market participation rules. It is not required to establish rules for DER aggregation registration, bidding, dispatch, or settlement. It is not required to coordinate with distribution utilities or relevant electric retail regulatory authorities regarding the participation of DERs in wholesale markets. These obligations fall exclusively on the RTOs and ISOs subject to Order No. 2222.
Ridgeline's obligation, as articulated in Deficiency Item 14, is more limited but still meaningful: it should demonstrate awareness of and accommodation for the downstream effects of DER integration on gas transportation service. This means that the Redesigned Tariff should acknowledge the potential for DER-driven changes in gas demand patterns, include tariff provisions that are flexible enough to accommodate those changes, and address the specific renewable energy interconnection scenarios that arise from DEH's ownership of both natural gas pipeline and wind generation assets. The tariff provisions should be framed as enabling rather than prescriptive—that is, they should create a framework for addressing renewable energy integration issues as they arise, rather than imposing rigid requirements that may not be appropriate given the current state of DER deployment in the markets served by the Ridgeline Pipeline System.
This distinction is important for several reasons. First, it establishes the appropriate scope of the tariff provisions, preventing Ridgeline from voluntarily assuming obligations that FERC has not imposed on natural gas pipelines. Second, it provides a defensible basis for the provisions in the event that intervenors challenge them as unnecessary or overly burdensome. Third, it preserves Ridgeline's flexibility to adjust the provisions in future tariff proceedings as the DER landscape evolves and as FERC's expectations for gas pipeline tariffs become more defined.
VII. Coordination with Other Deficiency Items
A. Cross-References to Related Deficiency Items
As noted throughout this memorandum, the Order No. 2222 analysis intersects with several other deficiency items identified in the Deficiency Letter. The Redesigned Tariff should be developed holistically, with the Order No. 2222 provisions integrated into the broader tariff structure in a manner that is consistent with the cures for all other deficiency items. The following cross-references identify the most significant points of intersection:
Deficiency Item 2 (FL&U Tracker). If wind power from DEH's renewable energy portfolio reduces compressor fuel gas consumption at one or more of Ridgeline's three compressor stations, the FL&U tracker mechanism must be designed to capture this effect accurately. The FL&U tracker should distinguish between fuel gas reductions attributable to wind power and fuel gas reductions attributable to other factors (such as pipeline efficiency improvements or changes in throughput levels), and should allocate the benefits of wind-powered compression in a non-discriminatory manner.
Deficiency Item 3 (IT Rate). DER-driven demand variability affects IT service usage patterns, as discussed in Section IV.C above. The IT rate derivation should be reviewed for consistency with the demand variability analysis and should be structured to accommodate the more sporadic and unpredictable IT service demand that may result from DER competition with gas-fired generators.
Deficiency Item 4 (Load Factor). DER variability supports a lower load factor assumption—specifically, Ridgeline's proposed 75 percent load factor rather than the 100 percent load factor used in the original filing or the 85 percent or higher load factor advocated by intervenors. The economic modeling being developed by Dr. Braswell should quantify the DER-related demand variability effects and provide empirical support for the 75 percent load factor position.
Deficiency Item 5 (Capacity Release). Enhanced capacity release provisions may be needed to accommodate shifting gas demand profiles driven by DER-related dispatch changes. Shippers whose gas-fired generator customers are dispatched less frequently due to DER competition may wish to release their firm transportation capacity on a short-term basis, and the tariff should facilitate such releases in a manner that is consistent with FERC's capacity release regulations.
Deficiency Item 6 (NAESB Compliance/OFO Provisions). Intraday nomination flexibility relates directly to the DER-driven scheduling variability discussed in Section IV.B above. The NAESB-compliant scheduling provisions in the Redesigned Tariff should be designed to accommodate the increased frequency and magnitude of intraday nomination changes that may result from DER competition.
Deficiency Item 12 (Segmentation and Flexible Receipt/Delivery Points). DER impacts on gas demand patterns may drive the need for more flexible service options, including the ability to segment firm transportation contracts and to utilize flexible receipt and delivery points. The tariff provisions addressing segmentation and flexible points should be designed to complement the Order No. 2222 provisions.
Deficiency Item 13 (GHG Cost Recovery). There is an important interaction between renewable energy integration and greenhouse gas emission cost recovery provisions. If wind power reduces compressor fuel gas consumption and associated GHG emissions, the GHG cost recovery mechanism should capture this effect. Conversely, if DER-driven changes in gas demand patterns lead to less efficient pipeline operations (e.g., more frequent compressor cycling), GHG emissions per unit of throughput could increase, affecting the GHG cost recovery tracker. This interaction is addressed in the separate March 2024 memorandum on Deficiency Item 13, and the two sets of tariff provisions should be coordinated for consistency.
A comprehensive cross-reference table mapping Order No. 2222 considerations to all fourteen deficiency items is provided in Appendix D to this memorandum.
B. Consistency with Redesigned Tariff
The tariff redesign consultant, Braswell Energy Consulting Group LLC, led by Dr. Raymond Braswell (Engagement No. BEC-2023-0041, engaged April 15, 2023), is incorporating the Order No. 2222 analysis into the fourth draft of the Redesigned Tariff. The fourth draft, which represents the near-final working version of the revised FERC Gas Tariff, Original Volume No. 1, is dated November 2024 and has been circulated to the Ridgeline regulatory team and to Calderwood & Harkness for review and comment.
Dr. Natasha Orlov, Director of Rates & Regulatory for Ridgeline, is coordinating internally on the technical aspects of the proposed tariff language. Dr. Orlov has extensive experience with FERC rate proceedings and has been the principal Ridgeline representative responsible for managing the tariff redesign process, including coordination with BEC and C&H. Dr. Orlov is also preparing draft supplemental pre-filed testimony for the February 21, 2025 filing deadline, and her testimony will include a dedicated section addressing Order No. 2222 and renewable energy interconnection. The testimony section is estimated at 15 to 20 pages and will explain the proposed tariff provisions, their rationale, their relationship to other deficiency item cures, and their consistency with FERC policy on gas-electric coordination.
Calderwood & Harkness's role in this process is to provide legal analysis and guidance to support the development of the tariff language and the preparation of Dr. Orlov's testimony. This memorandum represents the foundational legal analysis for the Order No. 2222 provisions. Once the tariff language is finalized by BEC and reviewed by Dr. Orlov, C&H will conduct a final legal review to ensure that the provisions are consistent with the NGA, the applicable FERC regulations, and the Commission's precedent on open-access transportation, affiliate transactions, and gas-electric coordination.
VIII. Intervenor and FERC Staff Positions
A. ATPC Position
Appalachian Trunk Pipeline Company, LLC ("ATPC") is the principal intervenor in this proceeding and is the operator of the downstream pipeline system with which the Ridgeline Pipeline System interconnects at the Wetzel County Interconnect. ATPC is represented by Kellner, Royce & Dillard LLP, with lead counsel William Pratt, of One PPG Place, Suite 2800, Pittsburgh, Pennsylvania 15222. ATPC's parent entity, Tidewater Infrastructure Partners LP, is a major energy infrastructure investment firm chaired by Harrison J. Alderman, with Marcus R. Alderman serving as President and CEO. Tidewater's estimated enterprise value is approximately $6.1 billion, making it a significantly larger entity than DEH.
To date, ATPC has not specifically addressed Order No. 2222 in its protest (filed August 15, 2022) or its answering testimony (filed January 9, 2023). ATPC's filings have focused primarily on the recourse rate, the load factor assumption, the interconnection cost allocation, and the capacity release and segmentation provisions—all of which are addressed in other deficiency items. However, ATPC's Vice President of Regulatory Affairs, Sandra K. Fenton, may raise Order No. 2222 issues in supplemental testimony once the Redesigned Tariff is filed and the full scope of Ridgeline's proposed Order No. 2222 provisions is known.
ATPC's position on Order No. 2222 is likely to be shaped by its own operational interests. ATPC's 640-mile system serves markets that include significant gas-fired electric generation capacity, and ATPC may have its own views on how DER aggregation under Order No. 2222 will affect gas demand patterns on its system. To the extent that ATPC supports enhanced gas-electric coordination provisions, it may welcome Ridgeline's inclusion of Order No. 2222 provisions in the Redesigned Tariff. Conversely, to the extent that ATPC views the provisions as creating additional regulatory complexity or as potentially affecting the interconnection cost allocation at the Wetzel County Interconnect, it may oppose specific elements of the proposed tariff language. Tidewater Infrastructure Partners may also have broader institutional views on renewable energy integration affecting its pipelin