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This memorandum is a privileged and confidential attorney-client communication prepared by Calderwood & Harkness LLP at the direction of the Board of Directors of Dunmore Energy Holdings Ltd. and is protected by the attorney-client privilege, the work-product doctrine, and all other applicable privileges and immunities. This memorandum contains the mental impressions, conclusions, opinions, and legal theories of counsel. Any disclosure, copying, distribution, or use of the contents of this memorandum by any person other than the intended recipients is strictly prohibited. If you have received this memorandum in error, please notify the sender immediately and destroy all copies.
December 20, 2024
MEMORANDUM
FROM: George Trujillo, Responsible Partner Energy & Infrastructure Practice Group Calderwood & Harkness LLP 1601 K Street NW, Suite 900 Washington, DC 20006
TO: Board of Directors Dunmore Energy Holdings Ltd. 4th Floor, Harbour Place 103 South Church Street George Town, Grand Cayman KY1-1002 Cayman Islands
ATTENTION: Patricia Dunmore, Chairperson
CC: Brett Callahan, Lead Associate, Calderwood & Harkness LLP David Stanton, Working Associate, Calderwood & Harkness LLP James K. Winfield, CEO, Ridgeline Midstream Services LLC Angela Moretti, VP Finance & Treasurer, Ridgeline Midstream Services LLC Dr. Natasha Orlov, Director of Rates & Regulatory, Ridgeline Midstream Services LLC
RE: Regulatory Risk Assessment and Litigation Budget Update — FERC Docket Nos. RP22-847-000 and RP22-847-001; C&H Matter No. 1016-00005
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I. Executive Summary
The purpose of this memorandum is to provide the Board of Directors of Dunmore Energy Holdings Ltd. ("DEH" or the "Company") with an updated regulatory risk assessment for the Federal Energy Regulatory Commission ("FERC" or the "Commission") proceeding involving Ridgeline Midstream Services LLC ("Ridgeline"), DEH's wholly-owned U.S. subsidiary, together with a revised litigation budget as the matter approaches a critical procedural milestone. Specifically, the proceeding is approaching the February 21, 2025, filing deadline for Ridgeline's redesigned FERC Gas Tariff, Original Volume No. 1, and supplemental testimony, and the Board must be apprised of the current risk landscape and resource requirements to navigate the path ahead.
The underlying proceeding was initiated on May 12, 2022, when Ridgeline filed an application before FERC under Sections 4 and 7 of the Natural Gas Act seeking approval of an initial tariff rate for interstate natural gas transportation service on the Ridgeline Pipeline System and authorization for a physical interconnection with Appalachian Trunk Pipeline Company, LLC ("ATPC"). The matter was assigned two docket numbers: Docket No. RP22-847-000 (addressing the initial tariff rate) and Docket No. RP22-847-001 (addressing the interconnection authorization with ATPC).
The proceeding has been in a dormant posture since September 8, 2023, following issuance of a Deficiency Letter by FERC's Office of Energy Market Regulation identifying fourteen deficiencies in the original tariff filing. Administrative Law Judge Clara Whitfield granted a third extension of time on March 4, 2024, subject to conditions that include the filing of quarterly status reports with the Commission. The current, firm deadline for filing the redesigned tariff and supplemental testimony is February 21, 2025. Three quarterly status reports have been filed to date — on June 15, 2024; September 14, 2024; and December 13, 2024 — and the proceeding remains on track for the February filing.
Calderwood & Harkness LLP ("C&H") assesses a moderate-to-favorable probability of obtaining FERC approval of a recourse rate in the range of $0.2700–$0.3140 per Dth, which would represent a commercially viable outcome for Ridgeline and DEH. However, significant litigation risk remains on three key issues: (1) return on equity ("ROE"), where downward pressure could reduce the approved ROE from Ridgeline's proposed 12.50% to as low as 11.00%; (2) load factor, where opposing parties advocate for 85% or higher versus Ridgeline's proposed 75%; and (3) interconnection cost allocation under Docket No. RP22-847-001, where ATPC contests Ridgeline's proposed 34.1%/65.9% split in favor of a 50/50 allocation. A settlement gap of approximately $0.058 per Dth persists between Ridgeline's floor of $0.3140/Dth and the intervenors' ceiling of approximately $0.2560/Dth, though C&H believes this gap is potentially bridgeable through targeted negotiation on a package of rate, cost allocation, and tariff enhancement terms.
The revised total estimated budget to complete all remaining phases of the proceeding — encompassing the February 2025 filing through potential Commission rehearing — is set forth in detail in Section VIII below, with separate estimates provided for a settlement-track resolution and a full litigation-track resolution.
This memorandum addresses each of these matters in turn and concludes with five specific recommendations for Board action.
II. Proceeding Background and Current Posture
A. Filing and Initial Proceedings (May 2022 – January 2023)
On May 12, 2022, Ridgeline filed an application with FERC under Sections 4 and 7 of the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717c and 717f, and implementing regulations at 18 C.F.R. Parts 154, 157, and 284. The application sought two forms of relief: (i) approval of an initial tariff rate for firm and interruptible interstate natural gas transportation service on the Ridgeline Pipeline System, and (ii) authorization for a physical interconnection between the Ridgeline Pipeline System and ATPC's existing 30-inch mainline at Wetzel County, West Virginia.
The Ridgeline Pipeline System. The Ridgeline Pipeline System is a 187-mile, 24-inch-diameter, high-pressure natural gas pipeline extending from a receipt point at the Wetzel County Interconnect in Wetzel County, West Virginia, to a delivery point at the Waynesburg Compressor Station in Greene County, Pennsylvania. The system has a design capacity of 1.2 billion cubic feet per day ("Bcf/d") and currently achieves throughput of approximately 680 million cubic feet per day ("MMcf/d"), representing approximately 56.67% utilization of design capacity. The system includes three compressor stations — Wetzel, Mannington, and Waynesburg — with aggregate installed compression of 45,000 horsepower ("HP"). The pipeline was placed in service on October 1, 2021, at an original construction cost of $587.2 million.
Original Rate Filing. The original rate filing proposed the following key rate design parameters:
• Rate base: $612.40 million
• Total cost of service: $97.36 million
• Proposed recourse rate: $0.2265/Dth ($0.2223 reservation charge + $0.0042 usage charge)
• Load factor: 100%
• Return on equity: 14.00%
• Capital structure: 55% equity / 45% debt
• Cost of debt: 5.25%
• Weighted average cost of capital ("WACC"): 10.0625%
FERC issued its Notice of Filing on June 14, 2022, establishing an intervention and protest deadline of August 15, 2022.
Interventions and Protests. Three parties intervened and/or filed protests:
1. Mountainside Gas Producers Coalition ("MGPC"). Filed intervention on July 28, 2022. MGPC is a coalition of fourteen independent natural gas producers operating in the Appalachian Basin with production interests directly served by or adjacent to the Ridgeline Pipeline System. MGPC generally supports the proposed interconnection with ATPC — which would expand market access for MGPC members' production — but opposes Ridgeline's proposed recourse rate as excessive. MGPC initially advocated for a rate of no more than $0.1740/Dth, a position that was subsequently revised upward to approximately $0.2560/Dth in the course of settlement discussions. MGPC's lead counsel is Rebekah Montague of Whitmore & Sable LLP, and its rate expert is Dr. Eleanor Vasquez.
2. Clearwater Municipal Gas Authority ("CMGA"). Filed intervention on August 1, 2022. CMGA is a municipal natural gas distribution utility serving approximately 47,000 residential and commercial customers in southwestern Pennsylvania. CMGA's primary concern is the impact of Ridgeline's proposed tariff rate on downstream rates paid by its customers. CMGA supports ATPC's position on interconnection cost allocation and is generally aligned with the intervenor rate positions. CMGA's lead counsel is Stephen Greer of Fordham Municipal Law Group PC.
3. Appalachian Trunk Pipeline Company, LLC ("ATPC"). Filed protest and intervention on the August 15, 2022, deadline. ATPC is the owner and operator of the interstate trunk pipeline with which Ridgeline seeks to interconnect. ATPC opposes Ridgeline's proposed interconnection configuration and, most significantly, contests the proposed allocation of $14.7 million in interconnection costs to ATPC's shippers. ATPC's lead counsel is William Pratt of Kellner, Royce & Dillard LLP.
FERC granted all three interventions by order dated September 22, 2022, and established a Track II procedural schedule for the rate case. Settlement Judge Howard Margolis was appointed to oversee settlement discussions.
ALJ Clara Whitfield was appointed as the presiding administrative law judge on November 14, 2022, and conducted a prehearing conference the same day. ALJ Whitfield established a procedural schedule for testimony exchange, discovery, and hearing.
In accordance with that schedule, Ridgeline filed its direct testimony on December 5, 2022. Ridgeline's direct case comprised the testimony of seven witnesses: James K. Winfield (CEO, Ridgeline — project overview and need for the pipeline); Angela Moretti (VP Finance & Treasurer, Ridgeline — cost of service, capital structure, and financial operations); Thomas Greaves (VP Engineering & Construction, Ridgeline — pipeline facilities, construction costs, and interconnection design); Dr. Natasha Orlov (Director of Rates & Regulatory, Ridgeline — rate design, billing determinants, and tariff provisions); Dr. Raymond Braswell (Braswell Energy Consulting Group LLC — ROE and WACC analysis); and two additional technical witnesses addressing operations and environmental compliance matters.
Answering testimony was filed by ATPC, MGPC, and CMGA on January 9, 2023, presenting their respective positions on the tariff rate, ROE, load factor, cost allocation, and interconnection configuration. FERC Trial Staff also participated in the proceedings, with Lead Trial Attorney Jonathan Briggs and Lead Economic Analyst Dr. Miriam Okafor designated as the principal Trial Staff representatives.
B. Deficiency Letter and Stay (January 2023 – September 2023)
On January 19, 2023, FERC's Office of Energy Market Regulation ("OEMR") issued a Deficiency Letter identifying fourteen specific deficiencies in Ridgeline's tariff filing. The issuance of the Deficiency Letter materially altered the trajectory of the proceeding, as the scope of the required corrections extended well beyond the original rate design issues in dispute. The fourteen deficiency items were as follows:
1. Inadequate ROE Support. The filing did not include an updated discounted cash flow ("DCF") proxy group analysis reflecting market conditions after 2021, rendering the 14.00% ROE insufficiently supported.
2. Missing FL&U Tracker Mechanism. The tariff lacked a fuel, lost and unaccounted-for gas ("FL&U") tracker mechanism to account for gas consumed or lost in the provision of transportation service.
3. Missing Interruptible Transportation ("IT") Rate Derivation. The tariff did not include a derivation of the interruptible transportation rate or the methodology for calculating the IT rate from the firm rate components.
4. Insufficient Support for 100% Load Factor. The filing did not provide adequate support for the use of a 100% load factor in the rate design, particularly given that actual throughput was materially below design capacity.
5. No Capacity Release Provisions. The tariff did not include provisions for capacity release consistent with 18 C.F.R. § 284.8.
6. Incomplete NAESB Standards Compliance. The tariff did not fully incorporate the standards promulgated by the North American Energy Standards Board Wholesale Gas Quadrant ("NAESB WGQ"), Version 3.2.
7. Missing Electronic Bulletin Board ("EBB") Posting Requirements. The tariff lacked provisions requiring the posting of capacity, operational, and transactional information on an Internet-accessible EBB.
8. Inadequate Shipper-Must-Have-Title ("SMHT") Provisions. The tariff provisions addressing the shipper-must-have-title requirement were incomplete and did not conform to FERC Order No. 712.
9. Interconnection Agreement Not Filed as Rate Schedule. The proposed interconnection agreement with ATPC was not filed as a rate schedule within the tariff, as required by FERC regulations.
10. No Penalty Revenue Crediting Mechanism. The tariff did not include a mechanism for crediting penalty revenues to non-offending shippers, as required by FERC policy.
11. Inadequate Creditworthiness Provisions. The tariff's creditworthiness provisions did not include adequate specificity regarding collateral requirements, unsecured credit limits, and credit rating thresholds.
12. Missing Segmentation and Flexible Receipt/Delivery Point Provisions. The tariff did not include provisions allowing segmentation of capacity or flexible receipt and delivery point usage.
13. No GHG Emission Cost Recovery Provisions. The tariff did not address cost recovery for greenhouse gas ("GHG") emission-related costs, including potential carbon pricing or compliance costs.
14. Failure to Address Order No. 2222 DER Aggregation Implications. The tariff did not address the implications of FERC Order No. 2222 regarding distributed energy resource ("DER") aggregation, which may be relevant given DEH's 250 MW wind portfolio under development.
ALJ Whitfield stayed the procedural schedule on February 6, 2023, pending resolution of the deficiency items.
Ridgeline filed a partial response to the Deficiency Letter on March 15, 2023, substantively addressing eight of the fourteen items — specifically, Items 1 through 4 and Items 7 through 10. The partial response included an updated DCF proxy group analysis (addressing Item 1), a proposed FL&U tracker (Item 2), an IT rate derivation (Item 3), revised load factor support at 75% rather than 100% (Item 4), EBB posting provisions (Item 7), revised SMHT provisions conforming to Order No. 712 (Item 8), a commitment to file the interconnection agreement as a rate schedule (Item 9), and a penalty revenue crediting mechanism (Item 10).
Recognizing that a comprehensive resolution of all fourteen deficiency items — particularly the more novel issues presented by Items 13 and 14 — would require a substantial redesign of the tariff, C&H engaged the Braswell Energy Consulting Group LLC ("Braswell") on April 15, 2023, under engagement number BEC-2023-0041. Dr. Raymond Braswell, a former FERC economist with over thirty years of experience in natural gas pipeline rate regulation, was retained to lead the comprehensive tariff redesign effort in coordination with Ridgeline's internal rates and regulatory team led by Dr. Natasha Orlov.
To accommodate the scope of the tariff redesign, Ridgeline filed its first extension request on April 28, 2023, seeking an additional 120 days. ALJ Whitfield granted the request on May 10, 2023, establishing a new deadline of August 28, 2023. As the redesign effort progressed and the scope of required changes became more fully apparent — particularly with respect to the GHG cost recovery mechanism (Item 13) and the Order No. 2222 analysis (Item 14) — Ridgeline filed a second extension request on August 25, 2023, seeking an additional 180 days. ALJ Whitfield granted this request on September 8, 2023, establishing a new deadline of February 23, 2024, and changing the proceeding's status to "dormant."
C. Tariff Redesign Phase and Current Status (October 2023 – Present)
On February 20, 2024, Ridgeline filed its third extension request, seeking an additional twelve months to complete the tariff redesign. The request cited material changes in the scope of the redesign effort, including the development of an entirely new GHG cost tracker and passthrough mechanism, the Order No. 2222 DER aggregation analysis, and the comprehensive revision of the rate design from a 100% load factor to a 75% load factor with revised billing determinants. ALJ Whitfield granted the request on March 4, 2024, establishing the current deadline of February 21, 2025, subject to the condition that Ridgeline file quarterly status reports with the Commission detailing the progress of the tariff redesign.
The tariff redesign is now substantively complete. Over the course of the redesign effort, four successive drafts of the revised FERC Gas Tariff, Original Volume No. 1, have been produced:
• First Draft (August 2023): Initial restructured tariff incorporating the partial deficiency response items and preliminary revisions to the rate design.
• Second Draft (January 2024): Incorporated the GHG cost tracker framework, capacity release provisions, and revised creditworthiness standards.
• Third Draft (June 2024): Added segmentation and flexible receipt/delivery point provisions, refined the NAESB WGQ Version 3.2 compliance provisions, and incorporated the interconnection agreement as a rate schedule.
• Fourth Draft — Near-Final (November 2024): Comprehensive near-final draft incorporating all fourteen deficiency item cures, the Order No. 2222 DER aggregation analysis, and final rate design parameters. This draft is the version that will, with any final refinements, be filed on February 21, 2025.
The revised rate design reflected in the near-final fourth draft represents a material departure from the original filing. The key parameters are as follows:
The revised total cost of service of $103.15 million comprises the following components:
The increase in the proposed recourse rate from $0.2265/Dth to $0.3140/Dth is primarily driven by the reduction in the load factor from 100% to 75%, which reduces billing determinants from 438,000,000 Dth/yr to 328,500,000 Dth/yr. While the total cost of service increased by approximately $5.79 million (from $97.36 million to $103.15 million), the more significant factor is the reduction in the denominator over which costs are spread. The revised ROE of 12.50% (down from 14.00%) partially offsets the cost of service increase.
Settlement Status. Four settlement conferences have been held under the auspices of Settlement Judge Howard Margolis: November 30, 2022; March 8, 2023; July 12, 2023; and January 18, 2024. No settlement has been reached. As of the most recent conference, the parties remain approximately $0.058/Dth apart: Ridgeline maintains a floor of $0.3140/Dth, while ATPC and MGPC have stated a ceiling of approximately $0.2560/Dth. CMGA has generally aligned itself with the ATPC/MGPC position on rate matters.
Supplemental Testimony. Supplemental testimony is currently in preparation for the February 21, 2025, filing. Dr. Natasha Orlov is preparing supplemental testimony addressing the revised rate design, billing determinants, and tariff provisions, including the novel GHG cost tracker and Order No. 2222 provisions. Angela Moretti is preparing supplemental testimony addressing the updated cost of service, capital structure, and financial data. C&H and Braswell are coordinating closely with both witnesses on testimony preparation.
III. Risk Assessment: Rate Case (Docket No. RP22-847-000)
This section presents C&H's assessment of the principal risks associated with the tariff rate proceeding under Docket No. RP22-847-000. The analysis addresses each major rate design component and its potential impact on the final approved rate.
A. Return on Equity
The ROE is the single most significant variable in the rate design and represents the area of greatest contention among the parties. The current positions are as follows:
Ridgeline's revised ROE of 12.50% — reduced from the original 14.00% in response to Deficiency Item 1 — is supported by an updated DCF proxy group analysis as of the third quarter of 2024. The proxy group comprises nine natural gas pipeline companies of comparable size, risk profile, and geographic footprint, and the analysis applies FERC's standard two-step DCF methodology as established in Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity, 123 FERC ¶ 61,048 (2008), and as refined in subsequent Commission orders. The analysis yields a median ROE of 12.34% and a mean ROE of 12.62%, with Ridgeline's proposed 12.50% falling squarely within that range.
ATPC's proposed ROE of 10.75% is based on a DCF analysis using a somewhat narrower proxy group and incorporating what C&H believes are overly conservative growth rate assumptions. MGPC's proposed ROE of 11.25% reflects a more moderate position but still falls below the range supported by Ridgeline's analysis. FERC Trial Staff has not yet formally stated a position, but based on Dr. Miriam Okafor's prior publications and FERC's recent determinations in analogous proceedings — including Southern Union Gas Pipeline Co., 180 FERC ¶ 61,107 (2022) (approving 10.55% ROE) and Millennium Pipeline Company, L.L.C., 183 FERC ¶ 61,024 (2023) (approving 12.00% ROE) — C&H expects the Trial Staff's recommended ROE to fall in the 10.5%–11.5% range.
Risk Assessment. The Commission has generally approved ROEs in the range of 10.5%–12.5% for new pipeline projects in recent years, with outcomes depending heavily on the composition of the proxy group, the time period selected for dividend yield and growth rate data, and the specific risk characteristics of the pipeline at issue. Ridgeline's updated DCF analysis as of Q3 2024 provides a reasonable basis for the 12.50% ROE, but this figure is at the upper end of the recent range and may face challenge from Trial Staff and the ALJ. C&H assesses the likely outcome range for ROE as 11.00%–12.25%, with a central tendency around 11.50%–12.00%.
Impact Analysis. Each 50-basis-point reduction in ROE reduces the annual return on rate base by approximately $1.69 million, calculated as follows: $612.40 million (rate base) × 0.55 (equity ratio) × 0.50% = $1.69 million. At billing determinants of 328,500,000 Dth/yr, this reduces the recourse rate by approximately $0.0051/Dth.
The following table illustrates the recourse rate at various ROE levels, holding all other variables constant (including the 75% load factor):
As shown, even at the low end of the likely ROE range (11.00%), the recourse rate would remain above $0.29/Dth if the 75% load factor is maintained. However, the combined effect of ROE reduction and load factor increase (discussed in Sections III.B and III.C below) could produce significantly greater rate compression.
B. Load Factor
The load factor is the second major variable in the rate design and is the subject of substantial dispute. The load factor determines the billing determinants (i.e., the volume of gas throughput over which the total cost of service is spread). A higher load factor increases billing determinants and thus reduces the per-unit rate, all else being equal.
Current Positions:
• Ridgeline (revised position): 75% load factor, yielding billing determinants of 328,500,000 Dth/yr (calculated as 1,200,000 Dth/d × 365 days × 0.75).
• ATPC and MGPC: Advocate for 85% or higher load factor. CMGA supports the intervenor position.
Load Factor Impact on Rate. The relationship between load factor and recourse rate, holding the total cost of service constant at $103.15 million, is as follows:
Factual Context. The factual backdrop on load factor presents a nuanced picture. Ridgeline's current throughput of approximately 680 MMcf/d represents only 56.67% utilization of the system's 1.2 Bcf/d design capacity. At the current throughput level, the actual load factor is well below 75%, which would appear to support Ridgeline's revised position — or even a lower load factor. However, the intervenors argue that Ridgeline's proposed 75% load factor is artificially low given the pipeline's design capacity and expected growth in Appalachian Basin production, and that FERC should apply a higher load factor based on expected average utilization over the pipeline's useful life.
Ridgeline's original filing used a 100% load factor, which was identified as Deficiency Item 4 due to insufficient factual support. The revised 75% load factor was selected based on the "design-day" rate design methodology, which uses a load factor that reflects the ratio of average-day deliveries to peak-day deliveries. FERC precedent generally permits load factors in the range of 75%–100% for design-day rate design, with the specific factor depending on the characteristics of the pipeline and the transportation service being offered. See, e.g., Crowne Albany Group, LLC, 158 FERC ¶ 61,125 (2017) (accepting 75% load factor for design-day rate design); Iroquois Gas Transmission System, L.P., 145 FERC ¶ 61,143 (2013) (accepting 85% load factor).
Risk Assessment. C&H assesses a moderate risk that FERC will set the load factor between 80% and 90%. The principal vulnerability is that Ridgeline's current utilization of 56.67% does not, on its face, support even a 75% load factor on an actual-throughput basis — though this is not the correct analytical framework for design-day rate design. ALJ Whitfield may, however, give weight to the intervenors' argument that the 75% load factor overstates peak-to-average differentials for a pipeline system in the Appalachian Basin, where seasonal variation in natural gas production is relatively modest compared to demand-driven pipeline systems. Conversely, if FERC applies a strict design-day methodology, the 75% load factor has defensible support.
C. Combined ROE and Load Factor Scenario Matrix
The combined effect of ROE and load factor on the recourse rate is the most critical analytical consideration for the Board. Because these two variables can move independently, the range of possible outcomes is wide. The following matrix presents estimated recourse rates at various combinations of ROE and load factor, holding all other cost-of-service components constant:
A detailed version of this matrix with revenue impact calculations is provided in Appendix A.
Several observations emerge from this analysis:
First, at the combination of ROE 11.25% and load factor 85%, the resulting rate of approximately $0.2658/Dth approaches the MGPC proposed ceiling of approximately $0.2560/Dth, significantly narrowing the settlement gap. This suggests that if the Commission's determination on these two variables falls in the range advocated by the intervenors, Ridgeline may achieve a rate only marginally above the intervenors' preferred range.
Second, at the more adverse combinations (ROE at or below 11.00% and load factor at 85% or above), the resulting rate could fall below $0.27/Dth, which is at the lower boundary of the range C&H considers commercially acceptable given Ridgeline's debt service obligations (discussed in Section VI below).
Third, C&H's base case projection is that the Commission's likely determination falls approximately within the range of ROE 11.25%–12.00% and load factor 80%–85%, yielding a recourse rate in the range of approximately $0.2700–$0.3000/Dth. This range represents a favorable but not exceptional outcome for Ridgeline, and it overlaps with what C&H believes is a realistic settlement zone (discussed in Section V below).
D. Cost-of-Service Components
Beyond ROE and load factor, the individual components of the cost of service present varying degrees of risk:
Rate Base ($612.40 million). The rate base methodology has not been challenged by any party, and C&H assesses the risk of a material adjustment as low. However, it should be noted that the test year ended March 31, 2022, and accumulated depreciation and other rate base components may need updating if the Commission requires a new test period. Given the elapsed time since the original filing — nearly three years — there is some risk that the ALJ or Commission could require Ridgeline to update its rate base to reflect a more current test year. C&H and Braswell have prepared contingency analyses for a test year ending March 31, 2024, or December 31, 2024, and the impact on rate base is estimated to be modest (an increase of approximately $3.5–$5.2 million due to additions to plant in service, offset by accumulated depreciation).
Depreciation ($14.68 million). Ridgeline applies a 2.5% straight-line depreciation rate, which is consistent with FERC norms for natural gas pipeline systems and has not been challenged. The risk of adjustment is assessed as low.
Operations & Maintenance ($13.92 million revised) and Administrative & General ($5.14 million revised). These cost categories present moderate risk. The intervenors — particularly ATPC — have challenged certain cost allocations between Ridgeline and its parent company, DEH, arguing that some costs attributed to Ridgeline are in fact parent-company overhead that should not be borne by Ridgeline's ratepayers. FERC Trial Staff may also scrutinize these allocations in its answering testimony. C&H has worked with Angela Moretti and the Ridgeline finance team to document the cost allocation methodology and ensure that it conforms to FERC's affiliate cost allocation standards under 18 C.F.R. Part 35. While C&H is confident in the defensibility of the revised O&M and A&G figures, some downward adjustment — on the order of $0.5–$1.5 million — is possible.
Income Tax Allowance ($15.04 million revised). This component presents elevated risk due to the intersection of FERC's income tax allowance policy and DEH's corporate structure. Following the Commission's decision in Sterling Reach Holdings, Inc. v. FERC, 827 F.3d 122 (D.C. Cir. 2016), and the Commission's subsequent Policy Statement on Treatment of Income Tax Allowances, FERC permits an income tax allowance in cost-of-service calculations only to the extent that the pipeline's equity owners actually pay or will pay income taxes on the income generated by the pipeline. Because DEH is domiciled in the Cayman Islands and Ridgeline is structured as a limited liability company with pass-through tax treatment, there is a risk that FERC will scrutinize whether income taxes are actually paid by the equity holders who ultimately benefit from the income tax allowance. C&H has prepared a detailed analysis demonstrating that DEH's equity owners who are subject to U.S. income tax — or the income tax of their respective jurisdictions — bear the economic burden of income taxes on Ridgeline's income, and that the income tax allowance is therefore appropriate. However, the Commission's application of its income tax allowance policy has been inconsistent in recent years, and the Cayman domicile of the parent entity adds an unusual wrinkle that could attract heightened scrutiny.
Revenue Credits ($6.00 million revised). The revision of revenue credits from $16.10 million in the original filing to $6.00 million in the revised filing reflects a reduction in projected interruptible transportation revenues and other miscellaneous revenues. The intervenors are likely to challenge this reduction and argue that revenue credits should be higher, which would reduce the total cost of service to be recovered through the recourse rate. C&H assesses a moderate risk that FERC may increase the revenue credit to the $8.00–$10.00 million range, which would reduce the recourse rate by approximately $0.006–$0.012/Dth.
Taxes Other Than Income ($3.80 million). This component, consisting primarily of property taxes and other state and local assessments, is well-documented and has not been challenged. The risk of adjustment is assessed as low.
E. Tariff Provisions — Deficiency Cure Risk
The redesigned tariff addresses all fourteen deficiency items identified in the January 19, 2023, Deficiency Letter. C&H's assessment of the residual risk associated with each item is as follows:
Items 1–4 and 7–10 (eight items): Low residual risk. These items were substantively addressed in the March 15, 2023, partial response and have been further refined through the tariff redesign process. The revised ROE support (Item 1), FL&U tracker (Item 2), IT rate derivation (Item 3), load factor support at 75% (Item 4), EBB posting requirements (Item 7), SMHT provisions (Item 8), interconnection agreement filing as rate schedule (Item 9), and penalty revenue crediting mechanism (Item 10) all conform to established FERC requirements and precedent. While FERC may request minor technical corrections to certain provisions, C&H does not anticipate any material deficiency findings on these eight items.
Item 5 — Capacity Release Provisions: Moderate risk. Capacity release provisions consistent with 18 C.F.R. § 284.8 were incorporated in the third and fourth tariff drafts. The provisions address both permanent and temporary capacity release, the right of first refusal, and the posting and bidding requirements. However, FERC's capacity release requirements are detailed and prescriptive, and there is a moderate risk that the Commission may request additional specificity in certain areas — such as the treatment of pre-arranged capacity release transactions and the recall rights of releasing shippers. Any such requests are likely to result in compliance filings rather than a rejection of the tariff.
Item 6 — NAESB WGQ Version 3.2 Compliance: Low risk. C&H and Braswell conducted a comprehensive gap analysis comparing Ridgeline's tariff provisions against all applicable NAESB WGQ Version 3.2 standards. The results of that gap analysis were incorporated into the tariff redesign, and the near-final fourth draft includes specific cross-references to the applicable NAESB standards for each tariff provision. C&H assesses the risk of a deficiency finding on NAESB compliance as low.
Item 11 — Creditworthiness Provisions: Moderate risk. The redesigned tariff includes new creditworthiness provisions that establish collateral requirements (letters of credit and cash deposits), unsecured credit limits based on tangible net worth and credit ratings, and credit rating thresholds (investment-grade from at least two of S&P, Moody's, and Fitch). These provisions are generally consistent with FERC precedent, but the Commission has shown increased sensitivity to creditworthiness issues in recent years and may request adjustments to the specific thresholds or collateral requirements. C&H assesses the risk as moderate.
Item 12 — Segmentation and Flexible Receipt/Delivery Points: Moderate risk. Provisions for segmentation of capacity and flexible receipt and delivery point usage were added in the third tariff draft and refined in the fourth draft. These provisions are consistent with FERC's general policy of promoting flexibility in pipeline transportation service but involve some complexity in application to a pipeline system of Ridgeline's size and configuration. There is a moderate risk that FERC may request modifications to the specific terms and conditions governing segmented service.
Item 13 — GHG Emission Cost Recovery Provisions: High risk. This is the most novel and uncertain of the fourteen deficiency items. C&H prepared a comprehensive analysis in March 2024 proposing a GHG cost tracker and passthrough mechanism that would allow Ridgeline to recover costs associated with GHG emissions compliance — including carbon taxes, emission allowances, and environmental mitigation costs — through a separate surcharge on transportation rates. FERC's policy on GHG cost recovery for interstate natural gas pipelines is evolving and, as of the date of this memorandum, there is no established precedent for a midstream pipeline GHG cost recovery tariff provision of the type proposed. While FERC has generally expressed receptivity to addressing climate-related costs in pipeline proceedings, the specific mechanism proposed by Ridgeline is without direct precedent and may be deferred for consideration in a future rulemaking proceeding rather than approved on a case-specific basis. C&H assesses the risk as high that FERC may decline to approve the GHG cost tracker in its proposed form, though C&H also believes there is a reasonable probability that the Commission will permit some form of GHG cost recovery provision, potentially with modifications.
Item 14 — Order No. 2222 DER Aggregation Implications: Moderate-to-high risk. C&H prepared a comprehensive analysis in May 2024 addressing the implications of FERC Order No. 2222 — which requires regional transmission organizations and independent system operators to establish participation models for DER aggregations — for Ridgeline's tariff. The relevance of Order No. 2222 to a natural gas pipeline tariff is itself a novel question, and the Deficiency Letter's reference to Order No. 2222 appears to stem from DEH's 250 MW wind portfolio under development, which could potentially participate in DER aggregation programs in the PJM Interconnection region. C&H's analysis takes the position that Order No. 2222's requirements are directed at electric transmission providers and do not directly apply to natural gas pipeline tariffs, but proposes informational provisions addressing coordination between Ridgeline's transportation service and the potential for DER aggregation by DEH affiliates. C&H assesses the risk as moderate-to-high that FERC may require additional or different provisions, particularly if the Commission views the intersection of gas pipeline service and DER aggregation as an area warranting further development.
IV. Risk Assessment: Interconnection (Docket No. RP22-847-001)
A. Interconnection Configuration and Metering Design
The proposed interconnection at the Wetzel County Interconnect involves the construction of a new meter station and pig launcher/receiver facilities at Ridgeline milepost 0.0, tying into ATPC's existing 30-inch mainline at ATPC Milepost 412.6. The interconnection is designed for a capacity of 800 MMcf/d with bidirectional flow capability, expandable to 1.2 Bcf/d through the addition of metering runs and compression. The metering equipment comprises three runs of 12-inch ultrasonic flow meters, dual gas chromatographs for gas quality measurement, and full SCADA integration with both Ridgeline's and ATPC's existing control systems.
ATPC filed a protest on August 15, 2022, in which it argued, among other things, that Ridgeline's proposed receipt-point metering station design is inadequate for the volumes and pressures involved, and that additional metering redundancy and gas quality monitoring equipment should be required. Ridgeline filed an answer to ATPC's protest on October 17, 2022, defending the adequacy of the proposed metering design and providing additional technical specifications. Technical clarifications were exchanged between lead associate Brett Callahan (C&H, for Ridgeline) and William Pratt (Kellner, Royce & Dillard LLP, for ATPC) in December 2022, which narrowed but did not fully resolve the metering design dispute.
Risk Assessment. C&H assesses the metering design dispute as presenting moderate risk. Metering design disputes are fundamentally technical in nature and are generally susceptible to resolution through negotiation between the pipeline engineering teams or through FERC staff review. The key risk is that FERC could require additional or alternative metering configurations — such as additional meter runs, enhanced gas quality monitoring, or independent third-party metering — that would increase Ridgeline's costs for the interconnection facilities. Based on preliminary engineering estimates provided by Thomas Greaves, the cost of the most aggressive metering configuration proposed by ATPC would add approximately $1.8–$2.5 million to the interconnection facilities cost. While this is a meaningful incremental cost, it is manageable within the overall project budget and does not present a material risk to the commercial viability of the interconnection.
B. Interconnection Cost Allocation
The total estimated cost of the interconnection facilities is $22.3 million, encompassing the meter station, pig launcher/receiver, valve assemblies, tie-in facilities, modifications to ATPC's existing mainline at the interconnection point, and associated engineering, permitting, and construction management costs.
The principal dispute between Ridgeline and ATPC concerns the allocation of these costs between the two systems:
Ridgeline's proposed allocation is based on a cost-causation analysis prepared by Thomas Greaves, which demonstrates that the majority of the interconnection facility costs are attributable to modifications required on ATPC's existing 30-inch mainline system — including mainline reinforcement, hot-tap installation, and valve modifications — rather than the new metering and pig launcher/receiver facilities on Ridgeline's side of the interconnection. Because ATPC's existing system requires more extensive modifications than would otherwise be necessary, Ridgeline argues that ATPC is the "cost-causer" with respect to the majority of the interconnection costs and should bear a proportionally larger share.
ATPC's position is that Ridgeline, as the interconnecting pipeline, is the cost-causer as a matter of policy and that a 50/50 split is the most equitable allocation. ATPC relies on several FERC orders in which the Commission has approved equal cost-sharing arrangements for pipeline interconnections, though C&H notes that those precedents are distinguishable on their facts.
FERC Precedent. The Commission's approach to interconnection cost allocation is governed by the principles of Order No. 2004 and its progeny, which apply a cost-causation framework. Under this framework, the costs of interconnection facilities should generally be allocated to the party whose actions or facilities necessitate the expenditure. The outcomes are highly case-specific, and the Commission has approved a range of allocations in prior proceedings — from 100% to one party to 50/50 splits — depending on the circumstances. C&H's analysis, set forth in detail in the October 2022 memorandum to the Board, supports Ridgeline's proposed 34.1%/65.9% allocation, but acknowledges that the Commission has broad discretion in this area and could adopt an alternative allocation.
Risk Assessment. C&H assesses the interconnection cost allocation as presenting moderate-to-high risk. The most likely outcome, in C&H's view, is that FERC adopts a cost allocation somewhere between the two parties' positions — potentially in the range of 40%/60% to 50%/50%.
Financial Impact. If FERC orders a 50/50 split, Ridgeline's share of the interconnection costs increases by $3.55 million ($11.15 million minus $7.6 million). If the incremental $3.55 million is rolled into Ridgeline's rate base, the impact on the recourse rate is approximately $0.001/Dth per year — a minimal impact in absolute terms but a relevant consideration in the context of settlement negotiations, where small per-unit adjustments can facilitate agreement.
Interconnection Agreement as Rate Schedule. Per Deficiency Item 9, the interconnection agreement must be filed as a FERC rate schedule within the tariff. Ridgeline and ATPC have been negotiating the terms of the interconnection agreement, and Version 3.0 of the agreement was prepared in April 2023. C&H has reviewed and revised the interconnection agreement through multiple iterations, and the current version (Version 4.2, September 2024) is included as a rate schedule in the near-final fourth draft of the tariff. ATPC has not yet agreed to the terms of Version 4.2, and the interconnection agreement terms may need to be resolved as part of a broader settlement or through litigated proceedings.
C. Target In-Service Date for Interconnection
The original target in-service date for the interconnection was the fourth quarter of 2023. This date is no longer achievable due to the extended dormancy of the proceeding. The revised estimate is that the interconnection can be placed in service approximately 18 to 24 months after FERC grants the requisite authorization, reflecting the time required for final engineering, procurement of long-lead equipment (which has already been substantially completed), construction, testing, and commissioning. On this basis, the earliest realistic in-service date is Q4 2026 to Q2 2027, assuming FERC authorization is obtained by approximately mid-2025 to late 2025.
Construction Risk. The construction risk for the interconnection is assessed as manageable. The necessary permits, rights-of-way, and environmental clearances are largely in hand, and key long-lead equipment (including the ultrasonic flow meters and gas chromatographs) has been ordered or is available for delivery on a timeline consistent with the projected construction schedule. The construction schedule is contingent primarily on the regulatory timeline rather than on physical or logistical constraints.
V. Settlement Prospects
A. Current Positions
The following table summarizes the current settlement positions of the principal parties:
The settlement gap between Ridgeline's floor and the intervenors' ceiling is approximately $0.058/Dth ($0.3140 minus $0.2560). Settlement Judge Howard Margolis has overseen four settlement conferences over the course of the proceeding, and while the conferences have facilitated constructive dialogue and the exchange of settlement proposals, no agreement has been reached. The gap has narrowed from the initial spread — when MGPC was advocating for a rate of no more than $0.1740/Dth — but the remaining $0.058/Dth gap is substantial and reflects fundamental disagreements on ROE, load factor, and cost allocation methodology.
B. Zone of Possible Agreement (ZOPA) Analysis
C&H has conducted a zone of possible agreement analysis to assess the potential for bridging the settlement gap. The analysis proceeds from the premise that each party has internal flexibility beyond its stated positions, and examines the rate implications of plausible movement by both sides:
Ridgeline Movement. If Ridgeline were to move to an ROE of approximately 11.75% and a load factor of 80%, the resulting rate would be approximately $0.2900/Dth. This would represent a significant concession from Ridgeline's current floor of $0.3140/Dth — a reduction of $0.024/Dth — but would still yield a commercially acceptable rate given Ridgeline's debt service requirements and operating cost structure.
Intervenor Movement. If the intervenors were to move to an ROE of approximately 11.50% and a load factor of 80%, their ceiling might increase to approximately $0.2750/Dth. This would represent a meaningful increase from the current ceiling of approximately $0.2560/Dth and reflects a recognition that the 85%+ load factor position may be difficult to sustain at hearing given the Commission's general acceptance of 75%–80% load factors for design-day rate design.
Narrowed Gap. Under these assumptions, the settlement gap narrows from $0.058/Dth to approximately $0.015/Dth ($0.2900 minus $0.2750) — a gap that is potentially bridgeable through negotiation on collateral terms, including:
• Interconnection cost allocation (moving from 34.1%/65.9% to a 40/60 or 45/55 split could provide value to ATPC that facilitates rate concessions);
• Revenue credit adjustments (agreeing to a higher revenue credit could reduce the recourse rate);
• Inclusion of certain tariff enhancements requested by the intervenors, such as expanded capacity release provisions or more favorable creditworthiness terms for shipper-intervenors; and
• A moratorium on future rate increases for a defined period (e.g., three to five years), providing rate certainty to intervenors.
C&H Recommendation. C&H recommends that the Board authorize Ridgeline to offer a settlement rate in the range of $0.2800–$0.2950/Dth as part of a comprehensive settlement package that also addresses interconnection cost allocation (e.g., a 40/60 or 45/55 split), tariff provision enhancements, and revenue credit levels. A settlement in this range would represent a commercially sound outcome for Ridgeline and DEH, particularly when weighed against the litigation risks and costs discussed in this memorandum.
C. Settlement vs. Litigation Trade-offs
The decision whether to pursue settlement or proceed to a litigated hearing involves a careful assessment of the risks, benefits, and costs of each path. C&H's analysis of the principal trade-offs is as follows:
Settlement Advantages:
• Certainty of outcome. A settlement eliminates the risk that FERC sets an ROE at or below 11.00% and a load factor at 85% or above, which could produce a rate below $0.27/Dth.
• Avoidance of extended litigation. The full litigation track — hearing, initial decision, Commission order, and rehearing — could extend the proceeding through late 2026 or beyond. A settlement could be achieved within months of the February 2025 filing, allowing the proceeding to be concluded as early as mid-2025.
• Reduced legal costs. The cost differential between a settlement-track resolution and a full litigation-track resolution is estimated at $1.8–$3.2 million in legal fees and consulting costs (see Section VIII below).
• Earlier in-service of interconnection. A settlement would allow construction of the interconnection to proceed on an accelerated timeline, potentially advancing the in-service date by six to twelve months.
• Favorable signal to lenders. The Pinnacle National Bank syndicate and the Harborview/Sentinel Ridge noteholders have expressed concern about the protracted timeline of the proceeding. A settlement would demonstrate regulatory progress and reduce lender uncertainty regarding Ridgeline's revenue outlook.
Settlement Risks:
• A settlement may lock in a rate below what Ridgeline could achieve at hearing if the ALJ and Commission adopt ROE and load factor parameters favorable to Ridgeline.
• The terms of a settlement may have precedential implications for Ridgeline's future rate cases, though this risk is mitigated by the principle that settlements are not precedential as to any party's position.
Litigation Advantages:
• If FERC approves an ROE of 12.00% or higher and a load factor of 75%, the resulting rate exceeds any likely settlement range and maximizes Ridgeline's revenues.
• A litigated outcome on the novel GHG cost tracker and Order No. 2222 issues could establish favorable precedent for the broader pipeline industry.
Litigation Risks:
• If FERC sets the ROE at 11.00% or below and the load factor at 85% or higher, the resulting rate could fall below the intervenors' current settlement position of approximately $0.2560/Dth — a result worse than any likely settlement.
• Extended timeline: the full litigation track is estimated to take 18–24 months following the February 2025 filing, with the possibility of further delay if the case proceeds to judicial review.
• Continuing accrual of legal and consulting costs throughout the litigation, estimated at $4.2–$6.8 million total through potential rehearing (see Section VIII).
• Lender covenant implications: continued dormant or litigated status of the FERC proceeding creates ongoing compliance risk under the Senior Secured Credit Facility (discussed in Section VI).
C&H Assessment. On balance, C&H concludes that settlement in the range of $0.2800–$0.2950/Dth is preferable to continued litigation, given the risk-adjusted expected outcome of the proceeding. The expected value of a litigated outcome — taking into account the probability-weighted range of ROE and load factor determinations — falls approximately in the $0.2700–$0.3000/Dth range, which overlaps significantly with the proposed settlement range. When the additional costs, time, and lender risk associated with litigation are factored in, the settlement path offers a superior risk-adjusted outcome.
However, C&H emphasizes that the filing of the redesigned tariff and supplemental testimony on February 21, 2025, is a necessary predicate to any settlement. Ridgeline must demonstrate the strength and completeness of its case in order to maximize its leverage in settlement negotiations. Accordingly, C&H recommends that the Board authorize both the filing and the resumption of active settlement negotiations, to proceed in parallel.
VI. Lender and Noteholder Considerations
A. Senior Secured Credit Facility
Ridgeline's construction and operations are financed in part through a Senior Secured Credit Facility consisting of a $400 million term loan and a $75 million revolving credit facility, dated September 15, 2021. The key terms of the facility are as follows:
The Credit Agreement includes regulatory covenants that are directly relevant to the FERC proceeding. Specifically, FERC tariff approval is a condition precedent to the calculation of certain financial covenants — including the debt service coverage ratio and the leverage ratio — using projected tariff revenues rather than actual revenues. So long as the proceeding remains in a dormant or pending status, these financial covenants must be calculated using actual revenues only, which — at current throughput of 680 MMcf/d and in the absence of an approved tariff rate — creates compliance risk. While Ridgeline has remained in compliance with all financial covenants through the date of this memorandum, C&H notes that the margin of compliance has narrowed in recent quarters as operating costs have increased.
C&H sent a status update letter to Richard Calvert, Managing Director at Pinnacle National Bank, on June 15, 2024, following the first quarterly status report filing. The quarterly reporting regime established by ALJ Whitfield's March 4, 2024, order has facilitated regular communication with the lender syndicate, and Pinnacle has expressed appreciation for the proactive approach. Angela Moretti is currently preparing a draft officer's certificate under Section 6.02(c) of the Credit Agreement for delivery in connection with the quarterly reporting obligations.
Recommendation. C&H recommends that Ridgeline deliver a comprehensive lender update letter to Pinnacle (attention: Richard Calvert) immediately following the February 21, 2025, filing. The letter should describe the filing, the anticipated procedural timeline, and the expected timeline to a final Commission order or settlement. Proactive communication is essential to maintain lender confidence and reduce the risk of covenant waiver requests, acceleration demands, or other adverse lender actions. C&H will prepare a draft of the lender update letter for Ridgeline management's review.
B. Second Lien Notes
Ridgeline's capital structure also includes $150 million in 7.875% Second Lien Senior Secured Notes due 2030, issued through a private placement on September 22, 2021, to two institutional investors: Harborview Capital Management LLC (Samantha Hu, Portfolio Manager) and Sentinel Ridge Fund LP (Peter Nowicki, Managing Partner).
C&H sent status update letters to both noteholders in December 2024, coinciding with the filing of the third quarterly status report. Both noteholders have expressed concerns regarding Ridgeline's ability to generate sufficient revenue under the approved tariff rate to service both the senior secured debt and the second lien notes. Specifically, the noteholders have indicated that a tariff rate below approximately $0.24/Dth at current throughput levels of 680 MMcf/d could create cash flow stress, as the resulting annual revenue would be approximately $59.6 million — insufficient to cover the combined annual debt service of the term loan and the second lien notes after operating expenses.
C&H notes that even at the low end of the projected rate range ($0.2700/Dth), annual revenue at current throughput would be approximately $67.0 million, which provides adequate coverage. However, the noteholders' concerns underscore the importance of achieving a tariff rate at or above $0.27/Dth and, ideally, in the $0.28–$0.31/Dth range, to provide a comfortable margin above the cash flow stress threshold.
C. Equity Contribution and DEH Financial Position
DEH's equity contribution to the construction of the Ridgeline Pipeline System was $37.2 million, representing the balance of the $587.2 million construction cost after the $400 million term loan and $150 million in second lien notes. DEH's overall financial position provides meaningful support for Ridgeline as the FERC proceeding progresses:
• DEH consolidated annual revenue (2023): approximately $485 million
• Estimated enterprise value (internal valuation, December 31, 2023): approximately $2.8 billion
• DEH portfolio: approximately 1,200 miles of midstream gathering and transportation pipelines, two cryogenic gas processing plants (combined capacity approximately 400 MMcf/d), and a 250 MW wind portfolio under development in West Virginia and Pennsylvania
• Patricia Dunmore (Founder & Chairperson) holds 72% equity in DEH
While the FERC proceeding relates to Ridgeline's operations as a separate entity, DEH's consolidated financial strength is relevant to lender and noteholder confidence and to the creditworthiness analysis that may be required in connection with the tariff provisions.
VII. Anticipated Procedural Timeline Following February 21, 2025 Filing
A. Immediate Post-Filing Steps
The following steps are anticipated immediately following the February 21, 2025, filing:
1. February 21, 2025: Ridgeline files the redesigned FERC Gas Tariff, Original Volume No. 1, together with the supplemental testimony of Dr. Natasha Orlov and Angela Moretti, and a transmittal letter to the Secretary of the Federal Energy Regulatory Commission. The filing will be accompanied by supporting workpapers and electronic copies of all tariff sheets in the Commission's eTariff format.
2. Within 30 days of filing (approximately March 21, 2025): FERC is expected to issue a notice of filing and establish a new intervention and comment period. Although the existing intervenors' participation status should carry over from the original proceeding, the notice will provide an opportunity for new parties to seek late intervention. C&H does not anticipate significant new intervention at this stage, though it is possible that one or more additional parties — such as downstream local distribution companies or other pipeline operators — may seek to participate.
3. Within 60 days of filing (approximately April 21, 2025): FERC or ALJ Whitfield is expected to lift the stay of the procedural schedule and establish a revised procedural schedule for the resumption of the Track II hearing. C&H submitted a letter to ALJ Whitfield in November 2024 proposing a procedural schedule for the resumption of proceedings, which envisions answering testimony in the spring of 2025, rebuttal testimony in the summer of 2025, and an evidentiary hearing in the fall of 2025.
B. Revised Track II Schedule (Estimated)
Based on C&H's proposed procedural schedule and the typical pace of FERC pipeline rate proceedings, the estimated timeline for the remaining phases of the proceeding is as follows:
Settlement discussions may continue in parallel with the litigation track at any point. Settlement Judge Howard Margolis remains assigned to the case and is available to convene additional settlement conferences as warranted. C&H anticipates that the filing of the redesigned tariff and the resumption of active proceedings will create renewed momentum for settlement negotiations, as the parties will be forced to engage substantively with the revised rate design and tariff provis