PRIVILEGED AND CONFIDENTIAL ATTORNEY-CLIENT COMMUNICATION — ATTORNEY WORK PRODUCT
MEMORANDUM
TO: Patricia Dunmore, Founder & Chairperson, Dunmore Energy Holdings Ltd. / Billing Partner, Calderwood & Harkness LLP; James K. Winfield, CEO & President, Ridgeline Midstream Services LLC
FROM: George Trujillo, Responsible Partner, Energy & Infrastructure, Calderwood & Harkness LLP; Brett Callahan, Lead Associate, Energy & Infrastructure, Calderwood & Harkness LLP; David Stanton, Working Associate, Energy & Infrastructure, Calderwood & Harkness LLP
DATE: October 18, 2024
RE: Settlement Strategy and Analysis — FERC Docket Nos. RP22-847-000 (Rate Case) and RP22-847-001 (Interconnection); Ridgeline Midstream Services LLC
C&H Matter No.: 1016-00005
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I. Executive Summary
The purpose of this memorandum is to provide a comprehensive analysis of all party positions on the three key sticking points in the ongoing settlement negotiations in FERC Docket Nos. RP22-847-000 and RP22-847-001, to identify the Zone of Possible Agreement ("ZOPA") across each contested issue, and to recommend a settlement strategy for Ridgeline Midstream Services LLC ("Ridgeline" or the "Company") to pursue in advance of the February 21, 2025 filing deadline imposed by Administrative Law Judge ("ALJ") Whitfield.
By way of context, this proceeding has been effectively dormant since September 8, 2023, when the parties last filed substantive materials. ALJ Whitfield granted a third extension of the Track II hearing schedule on March 4, 2024, subject to conditions including the filing of quarterly status reports. Those status reports have been timely filed. Meanwhile, the tariff redesign being undertaken with the assistance of Braswell Energy Consulting Group LLC ("Braswell") under engagement BEC-2023-0041 is nearing completion, with a fourth and near-final draft of the revised FERC Gas Tariff completed in November 2024.
To date, four settlement conferences have been convened before Settlement Judge Howard Margolis: November 30, 2022; March 8, 2023; July 12, 2023; and January 18, 2024. No settlement has been reached. The rate gap between the parties remains approximately $0.058 per dekatherm ("Dth"), representing the distance between Ridgeline's current floor position of $0.3140/Dth (the revised recourse rate under the redesigned tariff) and the ceiling proposed by the Appalachian Trunk Pipeline Company, LLC ("ATPC") and the Mountainside Gas Producers Coalition ("MGPC") of approximately $0.2560/Dth.
The three key sticking points that must be resolved for any settlement to be reached are: (1) the appropriate Return on Equity ("ROE") for Ridgeline's pipeline system; (2) the allocation of interconnection costs between Ridgeline and ATPC; and (3) the load factor assumption used to derive billing determinants for the recourse rate calculation.
Based on the analysis set forth in detail below, Calderwood & Harkness LLP ("C&H") recommends that Ridgeline consider targeted concessions across all three issues as part of a comprehensive package settlement proposal. We believe that a package settlement may be achievable at an all-in recourse rate of approximately $0.2800–$0.2900/Dth if Ridgeline is prepared to make coordinated moves on ROE and load factor simultaneously, while also offering a modest concession on interconnection cost allocation that carries relatively low financial impact but signals good faith to ATPC and the Clearwater Municipal Gas Authority ("CMGA"). The specific parameters of the recommended settlement authority, negotiation tactics, and timeline are discussed in Sections V and VI of this memorandum.
II. Background and Procedural Status
A. Proceeding Overview
Ridgeline Midstream Services LLC, a Delaware limited liability company whose sole member is Dunmore Energy Holdings Ltd. ("DEH"), filed its application with the Federal Energy Regulatory Commission ("FERC" or the "Commission") on May 12, 2022, seeking authorization for an initial tariff rate and interconnection authorization under Sections 4 and 7 of the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717c, 717f, and the Commission's regulations at 18 C.F.R. Parts 154, 157, and 284. The application was assigned FERC Docket Nos. RP22-847-000 (rate case) and RP22-847-001 (interconnection).
The Ridgeline Pipeline System (the "System") is 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 has a design capacity of 1.2 billion cubic feet per day ("Bcf/d"). Current throughput is approximately 680 million cubic feet per day ("MMcf/d"), representing a utilization rate of approximately 56.67% of design capacity. The System includes three compressor stations with an aggregate installed horsepower of 45,000 HP. The pipeline was placed in service on October 1, 2021, at an original construction cost of $587.2 million.
A central component of Ridgeline's application is its proposed interconnection with the Appalachian Trunk Pipeline Company, LLC ("ATPC"). ATPC operates a 640-mile interstate natural gas pipeline system with a capacity of 3.8 Bcf/d, providing service across a broad footprint in the northeastern United States. ATPC's parent company is Tidewater Infrastructure Partners LP, which is controlled by the Alderman family and has an estimated enterprise value of approximately $6.1 billion. The proposed interconnection would link the Ridgeline System to ATPC's system at ATPC Milepost 412.6, thereby enabling Ridgeline to access ATPC's established market reach while providing ATPC with new supply from the Marcellus and Utica shale basins.
B. Parties and Their Counsel
The following is a summary of the parties to this proceeding and their respective legal counsel and key representatives:
Ridgeline Midstream Services LLC / Dunmore Energy Holdings Ltd. — Ridgeline is represented by Calderwood & Harkness LLP. The responsible partner is George Trujillo of the Energy & Infrastructure practice group. The lead associate is Brett Callahan, and the working associate is David Stanton. Patricia Dunmore serves as both the Founder and Chairperson of DEH and as the billing partner at C&H for this engagement. The conflict arising from Ms. Dunmore's dual role was reviewed and waived in accordance with C&H's internal conflict clearance procedures and with the informed written consent of all necessary parties. James K. Winfield serves as CEO and President of Ridgeline and is the principal client contact for day-to-day case management.
Appalachian Trunk Pipeline Company, LLC ("ATPC") — ATPC is represented by Kellner, Royce & Dillard LLP, a Washington, D.C.-based energy regulatory firm. The senior partner leading the engagement is William Pratt, a veteran FERC litigator with extensive experience in rate and infrastructure proceedings. ATPC's Vice President of Regulatory Affairs, Sandra K. Fenton, has served as the company's lead negotiator on interconnection terms and has been the primary point of contact at each of the four settlement conferences. Marcus R. Alderman, CEO of ATPC, has participated in certain settlement discussions in a more limited capacity. ATPC's parent entity, Tidewater Infrastructure Partners LP, has an estimated enterprise value of approximately $6.1 billion and controls a diversified portfolio of midstream and pipeline assets across the eastern United States.
Mountainside Gas Producers Coalition ("MGPC") — MGPC is a coalition of fourteen independent natural gas producers operating in the Marcellus and Utica shale formations. MGPC is represented by Whitmore & Sable LLP. The lead partner is Rebekah Montague. Calvin Dreyer serves as Executive Director of the coalition. MGPC's rate expert is Dr. Eleanor Vasquez, a well-credentialed energy economist whose testimony has been cited by the Commission in several prior proceedings. The fourteen MGPC members collectively represent a substantial portion of the production base in the Appalachian Basin and are either current or prospective shippers on the Ridgeline System.
Clearwater Municipal Gas Authority ("CMGA") — CMGA is a municipal utility that receives natural gas service through ATPC's system. CMGA is represented by Fordham Municipal Law Group PC. Stephen Greer, Principal, is lead counsel. Dennis Ott serves as General Manager of CMGA. CMGA's interests are primarily aligned with those of ATPC, particularly on issues where the interconnection cost allocation may be passed through to ATPC's ratepayers, including CMGA's municipal customers.
FERC Trial Staff — The Commission's Trial Staff is participating in this proceeding pursuant to 18 C.F.R. § 385.102. The Lead Trial Attorney is Jonathan Briggs. The Lead Economic Analyst is Dr. Miriam Okafor, who has been conducting an independent analysis of the ROE and cost-of-service issues.
C. Settlement Process to Date
Settlement Judge Howard Margolis was appointed by the Chief Administrative Law Judge on September 22, 2022, to oversee settlement discussions in this proceeding. Judge Margolis has extensive experience in FERC pipeline rate proceedings and has facilitated settlements in several analogous cases over the past decade.
Four settlement conferences have been held to date. Each is summarized below.
First Settlement Conference (November 30, 2022). At this initial conference, Ridgeline circulated Settlement Offer v1.0, which was based on the original filing parameters. Ridgeline's initial position was to maintain its originally proposed recourse rate of $0.2265/Dth, which assumed a 14.00% ROE and a 100% load factor. ATPC and MGPC each staked out their initial positions, urging a substantial reduction in the proposed rate. The parties were far apart on all three key issues, and the conference concluded without material progress. Settlement Judge Margolis encouraged the parties to continue informal discussions and to be prepared to present more detailed analyses at the next conference.
Second Settlement Conference (March 8, 2023). This conference was held shortly before Ridgeline filed its partial response to the Commission's Deficiency Letter on March 15, 2023. The settlement discussions were complicated by the emerging tariff redesign process, as Ridgeline's outside consultants at Braswell had only recently been engaged (April 15, 2023 is the formal engagement date, but preliminary scoping discussions had begun earlier). The parties exchanged preliminary views on each sticking point, but the lack of a revised cost-of-service model made substantive progress difficult. MGPC expressed frustration with the pace of the redesign effort and pressed Ridgeline for a concrete timeline for updated filings.
Third Settlement Conference (July 12, 2023). Ridgeline circulated Settlement Offer v2.0 in advance of this conference. Settlement Offer v2.0, which was formally transmitted to the parties in October 2023 following the conference, included an ROE concession from 14.00% to 13.00%. While this represented a meaningful initial move, the parties remained far apart. ATPC maintained its 10.75% ROE position and pressed for 50/50 cost allocation on the interconnection facilities. MGPC reiterated its support for a load factor of 85% or higher and its own ROE position of 11.25%. The rate gap at this stage was still substantial, and Settlement Judge Margolis encouraged the parties to use the intervening months to narrow their positions and to present more refined analyses at the next conference.
Fourth Settlement Conference (January 18, 2024). This was the most comprehensive negotiation session to date, covering all three key sticking points in a single day-long meeting at FERC headquarters. Ridgeline circulated Settlement Offer v3.0 in September 2024 (following the conference and incorporating the Q3 2024 proxy group update). Settlement Offer v3.0 reflected Ridgeline's revised position of 12.50% ROE and 75% load factor, yielding a revised recourse rate of $0.3140/Dth. While Ridgeline had reduced its ROE proposal by 150 basis points from the original filing, the rate had actually increased from the original $0.2265/Dth to $0.3140/Dth due to the combined effects of the lower load factor assumption and other cost-of-service revisions identified in the tariff redesign process. The intervenors focused on this apparent paradox and argued that the revised rate represented a significant increase above Ridgeline's original proposal. The gap between Ridgeline's floor and the ATPC/MGPC ceiling remains approximately $0.058/Dth.
No further settlement conferences are currently scheduled. Settlement Judge Margolis remains available and has indicated willingness to convene additional sessions on reasonable notice.
D. Tariff Redesign Status
On April 15, 2023, Ridgeline engaged Braswell Energy Consulting Group LLC to undertake a comprehensive redesign of the FERC Gas Tariff. The engagement is led by Dr. Raymond Braswell, the principal of the firm and a former FERC economist who served for twelve years in the Commission's Office of Energy Market Regulation. The engagement letter (BEC-2023-0041) encompasses a complete review and revision of Ridgeline's cost-of-service, rate design, and tariff provisions to address the fourteen deficiency items identified in the Commission's January 19, 2023 Deficiency Letter.
The fourth draft of the revised FERC Gas Tariff — which Braswell and C&H consider to be near-final — was completed in November 2024. This draft addresses all fourteen deficiency items, including the matters most directly relevant to the settlement negotiations. The key parameters of the redesigned tariff are as follows:
• Rate Methodology: Modified fixed-variable rate methodology, allocating fixed costs to the reservation charge and variable costs to the usage charge.
• Load Factor: 75%, revised from the 100% load factor originally proposed in the May 2022 filing. The 75% load factor was adopted based on Braswell's analysis of expected utilization over the 25-year levelization period, taking into account contractual commitments, projected demand growth in the Appalachian Basin, and the current throughput of approximately 680 MMcf/d.
• Return on Equity: 12.50%, revised from the 14.00% ROE in the original filing. This revision reflects the Q3 2024 DCF proxy group update and is intended to bring Ridgeline's ROE into alignment with current market conditions and recent FERC precedent.
• Total Cost of Service: $103.15 million per year.
• Revised Recourse Rate: $0.3140/Dth, consisting of a reservation component of $0.3102/Dth and a usage component of $0.0038/Dth.
Supplemental testimony is currently in preparation to support the revised tariff filing. Dr. Natasha Orlov, Ridgeline's cost-of-service witness, is preparing updated testimony addressing the revised cost-of-service and rate design. Angela Moretti, Ridgeline's markets witness, is preparing updated testimony on throughput projections, shipper demand, and load factor support. Both witnesses are expected to be available for testimony in support of the February 21, 2025 filing deadline.
III. Analysis of Party Positions on Key Sticking Points
The remainder of this memorandum analyzes in detail the positions of all parties on each of the three key sticking points, identifies the Zone of Possible Agreement for each issue, and assesses the financial impact of various settlement scenarios. The three sticking points are addressed in turn below.
A. Sticking Point 1: Return on Equity (ROE)
The ROE is the single most significant driver of the rate gap between the parties. It determines the equity component of the pipeline's return on rate base, which in turn constitutes the largest individual cost element in the cost-of-service computation. The parties' positions on ROE are summarized below, followed by an analysis of the ZOPA.
1. Ridgeline's Position
Ridgeline's original filing in May 2022 proposed an ROE of 14.00%, based on a discounted cash flow ("DCF") proxy group analysis that relied on pre-2021 market data. This was identified as Deficiency Item 1 in the Commission's January 19, 2023 Deficiency Letter, which noted that the original analysis failed to account for post-2021 market conditions, including changes in interest rates, equity risk premiums, and the financial performance of comparable pipeline companies.
In response to the deficiency and as part of the tariff redesign, Braswell prepared an updated DCF proxy group analysis using data through Q3 2024. The proxy group consists of comparable FERC-jurisdictional natural gas pipelines, and the analysis employs the Commission's standard two-step DCF methodology, incorporating dividend yields and projected growth rates as of the end of Q3 2024. Based on this updated analysis, Ridgeline's current revised ROE position is 12.50%.
The evolution of Ridgeline's ROE position is worth noting. Settlement Offer v2.0 (circulated in October 2023) proposed an interim concession from 14.00% to 13.00%. Settlement Offer v3.0 (circulated in September 2024) further reduced the ROE proposal to 12.50%, consistent with the redesigned tariff. Each reduction has been supported by updated market data and proxy group analysis. Ridgeline has thus demonstrated meaningful downward movement from its original position.
With respect to FERC precedent, recent pipeline initial rate proceedings before the Commission have yielded ROE determinations in the range of 10.50% to 13.50%. Ridgeline's current position of 12.50% falls within the upper-middle portion of this range. While the position is defensible, it is above the median of recent Commission outcomes and would likely face scrutiny if litigated.
From a financial perspective, the ROE has a material impact on the recourse rate. Each 25 basis point reduction in ROE reduces the annual return on rate base by approximately $0.84 million, calculated as follows: $612.40 million (rate base) × 0.55 (equity ratio) × 0.0025 (25 bps) = approximately $0.84 million. At billing determinants of 328,500,000 Dth/yr (based on the current 75% load factor assumption), this translates to a reduction in the recourse rate of approximately $0.0026/Dth per 25 basis points of ROE reduction.
2. ATPC's Position
ATPC has proposed an ROE of 10.75%, as set forth in its answering testimony filed on January 9, 2023. ATPC's counsel, William Pratt of Kellner, Royce & Dillard LLP, has argued this position consistently across all four settlement conferences.
ATPC's rationale for a 10.75% ROE rests on several grounds. First, ATPC contends that Ridgeline's pipeline faces limited market risk given the robust and growing demand for natural gas transportation capacity in the Appalachian Basin. ATPC characterizes the Marcellus and Utica shale formations as among the most prolific natural gas producing regions in North America, with long-term demand profiles that reduce the risk of insufficient throughput on the Ridgeline System. Second, ATPC points to its own FERC-approved ROE as a benchmark, arguing that Ridgeline should not receive a materially higher return for a system that serves a similar geographic market and shipper base. Third, ATPC can point to recent FERC decisions in which initial pipeline ROEs were set at or below 11.00%, supporting the proposition that the Commission has been trending toward lower equity returns for pipeline investments.
From a strategic standpoint, C&H notes that ATPC's motivation for suppressing Ridgeline's ROE may not be purely rooted in cost-of-service principles. A lower ROE for Ridgeline would limit the valuation of the interconnection facilities, reduce the overall competitiveness of the Ridgeline System relative to ATPC's own capacity, and potentially diminish Ridgeline's ability to attract new shippers. ATPC is, in effect, both a counterparty to the interconnection and a competitor in the Appalachian Basin transportation market. This dual role should be kept in mind when evaluating the strength and credibility of ATPC's ROE advocacy.
Despite these strategic considerations, ATPC's position has certain strengths. The 10.75% figure is within the range of recent FERC outcomes, and ATPC's arguments regarding Ridgeline's limited market risk have some factual support given the Basin's production profile. However, the position also has notable weaknesses. An ROE of 10.75% is below the median of recent FERC pipeline ROE determinations and may not adequately compensate Ridgeline for the construction and operational risks inherent in a newly built pipeline system — particularly one that has yet to achieve its design throughput capacity. The Commission has historically recognized a risk premium for new pipeline construction, and 10.75% may not reflect that premium.
3. MGPC's Position
MGPC has proposed an ROE of 11.25%, as presented in the answering testimony of Dr. Eleanor Vasquez filed on January 9, 2023. Dr. Vasquez performed an independent DCF analysis using a proxy group of comparable pipeline companies and concluded that a risk premium above typical master limited partnership ("MLP") yields is appropriate for a new pipeline system, but not to the extent claimed by Ridgeline in its original or revised filings. Dr. Vasquez's analysis suggests a reasonable range of 10.75% to 11.75%, with 11.25% as the midpoint and her recommended outcome.
MGPC's position reflects the coalition's dual interests. On the one hand, MGPC's fourteen member companies generally support the proposed interconnection, which would increase producer access to downstream markets and enhance the value of production in the Marcellus and Utica formations. On the other hand, MGPC opposes an excessive recourse rate that would burden shippers and reduce the netback value of production. MGPC's proposed rate ceiling of approximately $0.2560/Dth assumes an ROE of approximately 11.25% combined with a higher load factor assumption (discussed in Section III.C below).
MGPC's position carries particular weight in settlement discussions because its members are prospective shippers on the Ridgeline System who have a direct economic interest in the proceeding's outcome. A settlement that is acceptable to MGPC would signal broad shipper support and would be viewed favorably by the Commission.
4. CMGA's Position
CMGA has aligned its position with ATPC's on the ROE issue, supporting an ROE of 10.75% or lower. CMGA's primary concern is the potential for rate increases on ATPC's system that could result from the interconnection. To the extent that a lower Ridgeline ROE reduces the rate impact on ATPC's system (through lower interconnection facility costs included in Ridgeline's rate base), CMGA benefits. As a municipal end-user, CMGA has limited financial capacity to absorb cost increases and is particularly sensitive to any rate adjustments that flow through to its residential and commercial customers.
CMGA's position on ROE is derivative of ATPC's and is unlikely to diverge from ATPC in any material respect. In settlement negotiations, CMGA can be expected to follow ATPC's lead on this issue.
5. FERC Trial Staff Position
FERC Trial Staff has not formally proposed an ROE in testimony or in any filed pleading. However, Lead Economic Analyst Dr. Miriam Okafor indicated in informal discussions during a May 2023 staff meeting that Staff's analysis is likely to yield an ROE in the range of 11.00% to 12.00%. This is consistent with Staff's historical approach of supporting a narrower DCF range and tending to favor median or lower-quartile proxy group results rather than upper-quartile outcomes.
While Staff's informal indication is not binding and may evolve as Staff completes its analysis, it provides a useful indication of the analytical range within which the Commission's economists are likely to operate. Staff's support for a settlement is often a critical factor in the Commission's decision whether to approve a negotiated resolution, and any settlement in the 11.00%–12.00% ROE range would likely receive favorable treatment from Staff.
6. ZOPA on ROE
Based on the foregoing analysis, the range of positions on ROE extends from 10.75% (ATPC's floor) to 12.50% (Ridgeline's ceiling). The estimated Zone of Possible Agreement on ROE is 11.25% to 12.00%.
To illustrate the impact of a potential compromise, consider a settlement ROE of 11.75%. This would represent a concession of 75 basis points below Ridgeline's current position of 12.50%, while remaining above both ATPC's proposal of 10.75% and MGPC's proposal of 11.25%. At 11.75%, the weighted average cost of capital ("WACC") would be calculated as follows:
WACC = (0.55 × 11.75%) + (0.45 × 5.25%) = 6.4625% + 2.3625% = 8.825%
The return on rate base at this WACC would be:
Return on Rate Base = $612.40M × 8.825% = approximately $54.04 million
This compares to the current return on rate base of $56.57 million at Ridgeline's 12.50% ROE (WACC of 9.2375%). The reduction of approximately $2.53 million in annual return would translate to a reduction in the recourse rate of approximately $0.0077/Dth at billing determinants of 328,500,000 Dth/yr (75% load factor). The rate impact would be greater if combined with a higher load factor, as discussed in Section III.C below.
An ROE settlement at 11.75% would fall within the range informally indicated by FERC Trial Staff and would be broadly consistent with recent Commission precedent. It would also represent a meaningful concession by Ridgeline that could provide the basis for a compromise on other issues.
B. Sticking Point 2: Interconnection Cost Allocation
1. Ridgeline's Position
The total estimated cost of the interconnection facilities at the ATPC Milepost 412.6 interconnection point is $22.3 million. This includes the meter station, pig launcher and receiver facilities, SCADA integration systems, associated piping and valves, site work, and engineering and construction management costs.
Ridgeline has proposed an allocation of these costs such that Ridgeline would bear 34.1% ($7.6 million) and ATPC would bear 65.9% ($14.7 million). Ridgeline's proposed allocation is based on cost-causation principles, which are the foundational standard under the Commission's policies for allocating interconnection costs between pipeline systems. Ridgeline's argument rests on several factual predicates:
First, the interconnection primarily benefits ATPC's system by providing access to new Marcellus and Utica shale supply that will flow through ATPC's established 640-mile network to serve downstream markets in Pennsylvania, Ohio, and New York. The incremental capacity available at the interconnection directly enhances the value and utilization of ATPC's existing infrastructure.
Second, the meter station and pig launcher/receiver facilities are physically located on ATPC's right-of-way at ATPC Milepost 412.6. ATPC controls the land on which these facilities will be constructed, and ATPC's operational requirements drive much of the design specification for the metering and measurement equipment.
Third, ATPC's shippers derive greater benefit from the incremental capacity available at the interconnection than Ridgeline's shippers do, because the interconnection opens access to a 640-mile system with 3.8 Bcf/d of capacity, whereas Ridgeline's 187-mile system already provides the transportation service needed by its existing shipper base.
Ridgeline's position is supported by FERC precedent under Order No. 2004 and the Commission's longstanding cost-causation analysis framework, which supports a proportional allocation of interconnection costs based on relative benefits derived by each system from the interconnection.
The interconnection is designed with a capacity of 800 MMcf/d bidirectional flow, expandable to 1.2 Bcf/d. Metering equipment includes ultrasonic flow meters (three runs, 12-inch diameter), gas chromatographs for gas quality measurement, and full SCADA integration with both pipeline systems' control centers.
2. ATPC's Position
ATPC has proposed a 50/50 split of interconnection costs, with each party bearing $11.15 million. ATPC's position is based on the argument that the interconnection equally benefits both pipeline systems. ATPC contends that Ridgeline derives substantial benefit from access to ATPC's established 640-mile network, which serves markets across three states and provides transportation pathways that Ridgeline could not access independently. ATPC characterizes the proposed interconnection as a mutually beneficial infrastructure improvement that should be funded equally by the two systems.
In addition, ATPC has raised concerns about Ridgeline's proposed metering station design. Specifically, ATPC VP Sandra K. Fenton has argued that certain elements of Ridgeline's proposed metering equipment are inadequate for ATPC's operational requirements and would need to be upgraded at additional cost. ATPC contends that it should not bear the cost of these upgrades under Ridgeline's proposed 65.9% allocation. This argument has been a consistent theme in ATPC's advocacy across all four settlement conferences, with Ms. Fenton serving as ATPC's lead negotiator on interconnection terms.
ATPC filed a formal protest on August 15, 2022, arguing that Ridgeline's proposed $14.7 million share improperly shifts interconnection facilities costs to ATPC's shippers, including municipal end-users such as CMGA. The protest was accepted for filing and has been referred to the hearing process along with the other contested issues.
3. CMGA's Position
CMGA supports ATPC's 50/50 cost allocation position. CMGA's concern is that the 65.9% allocation to ATPC proposed by Ridgeline would ultimately be passed through to ATPC's ratepayers, including CMGA's municipal customers. As a municipal utility serving residential and commercial customers in its service territory, CMGA is particularly sensitive to cost increases that could flow through ATPC's system rates. Stephen Greer of Fordham Municipal Law Group PC has been vocal at each settlement conference about the potential downstream impact on CMGA's ratepayers.
4. MGPC's Position
MGPC has taken a generally neutral position on the interconnection cost allocation as between Ridgeline and ATPC. MGPC's primary concern is the recourse rate on Ridgeline's system, not the allocation of interconnection costs between the two pipeline operators. However, MGPC has acknowledged that to the extent interconnection costs flow into Ridgeline's rate base and thereby increase the recourse rate, MGPC would prefer a higher ATPC share allocation. This is a secondary concern for MGPC, and Calvin Dreyer has indicated at the settlement conferences that the coalition would not condition a settlement on any particular cost allocation outcome.
5. Financial Impact Analysis
The financial impact to Ridgeline of conceding from its 34.1/65.9 position to ATPC's 50/50 position is relatively modest in per-unit rate terms, though it involves a meaningful shift in capital commitment.
If Ridgeline were to accept the 50/50 split, Ridgeline's share of interconnection costs would increase from $7.6 million to $11.15 million — a net increase of $3.55 million. Conversely, ATPC's share would decrease from $14.7 million to $11.15 million, a savings of $3.55 million for ATPC and its ratepayers.
If the additional $3.55 million in interconnection costs is added to Ridgeline's rate base, the rate base would increase from $612.40 million to approximately $615.95 million (net of any offsetting adjustments such as accumulated depreciation on the interconnection facilities). The impact on the annual revenue requirement at a WACC of 9.2375% (Ridgeline's current capital structure and cost assumptions) would be approximately $0.33 million per year. At billing determinants of 328,500,000 Dth/yr, this would translate to a recourse rate increase of approximately $0.0010/Dth — a relatively modest impact.
This finding has important strategic implications. The interconnection cost allocation, while a matter of principle for ATPC and CMGA, has a comparatively small financial impact on Ridgeline's recourse rate. A concession on this issue may therefore be a low-cost mechanism for generating goodwill with ATPC and CMGA while preserving Ridgeline's negotiating capital for the more financially significant ROE and load factor issues.
6. ZOPA on Interconnection Cost Allocation
The range of positions on interconnection cost allocation extends from a 50/50 split (ATPC's position) to a 34.1/65.9 split (Ridgeline's position). The ZOPA likely encompasses several intermediate positions.
A compromise at 40% Ridgeline / 60% ATPC would result in Ridgeline's share increasing to approximately $8.92 million and ATPC's share decreasing to $13.38 million. An alternative compromise at 45% Ridgeline / 55% ATPC would place Ridgeline's share at approximately $10.035 million and ATPC's share at $12.265 million.
We recommend that Ridgeline offer to move to 45/55 or 40/60 as part of a package settlement proposal. The financial impact to Ridgeline is manageable, in the range of approximately $0.0005 to $0.0010/Dth, while the concession demonstrates flexibility and good faith. There is no rigid formulaic requirement under FERC precedent for any particular allocation ratio; the Commission's approach has historically given ALJs discretion to approve a wide range of outcomes based on cost-causation analysis and the specific facts of each case. A negotiated allocation within the 40/60 to 45/55 range would be well within the range of supportable outcomes.
C. Sticking Point 3: Load Factor for Billing Determinants
1. Ridgeline's Position
Ridgeline's original filing in May 2022 assumed a 100% load factor, resulting in billing determinants of 438,000,000 Dth/yr (calculated as 1,200,000 Dth/d × 365 days × 100%). This assumption was identified as Deficiency Item 4 in the Commission's January 19, 2023 Deficiency Letter, which found that Ridgeline had provided insufficient support for a 100% utilization assumption.
Ridgeline's revised position, as reflected in the redesigned tariff, assumes a 75% load factor. This yields billing determinants of 328,500,000 Dth/yr (1,200,000 Dth/d × 365 days × 75%). The 75% assumption is based on the Braswell analysis, which concluded that 75% reasonably reflects expected pipeline utilization over the 25-year levelization period. The analysis takes into account Ridgeline's existing contractual commitments with shippers, projected demand growth in the Appalachian Basin, and the pipeline's operational history since its October 2021 in-service date.
Critically, Ridgeline's current throughput of approximately 680 MMcf/d represents only 56.67% of design capacity. While the Company expects throughput to grow over time as additional shipper commitments are secured and the interconnection with ATPC comes online, the current utilization rate is well below both the 75% assumption and the 100% assumption originally proposed. Any assumed load factor above actual utilization necessarily involves a forecasting element and a corresponding degree of uncertainty.
The impact of the load factor on the recourse rate is intuitive but bears emphasis: a lower load factor produces fewer billing determinants, which increases the per-unit rate required to recover the same total cost of service. This is precisely why Ridgeline's revised recourse rate of $0.3140/Dth is significantly higher than the original proposed rate of $0.2265/Dth, even though the revised ROE (12.50%) is materially lower than the original (14.00%). The load factor reduction from 100% to 75% is the primary driver of the rate increase.
2. ATPC's Position
ATPC advocates for a load factor of 85% or higher. ATPC's argument is that Ridgeline's pipeline will achieve substantially higher utilization as Marcellus and Utica production increases and the interconnection between the two systems comes online. ATPC points to historical load factors for comparable Appalachian Basin pipelines, which generally range from 80% to 95%, as evidence that 75% is excessively conservative.
A higher load factor increases billing determinants and reduces the per-unit recourse rate. From ATPC's perspective, advocating for a higher load factor is consistent with its overall strategy of reducing Ridgeline's recourse rate. Combined with ATPC's 10.75% ROE proposal, an 85% load factor produces the approximately $0.2560/Dth rate ceiling that ATPC and MGPC have identified as their target.
3. MGPC's Position
MGPC also advocates for a load factor of 85% or higher, consistent with ATPC's position on this issue. Dr. Eleanor Vasquez testified in MGPC's answering testimony that an 85% load factor is a conservative assumption based on producer commitments and projected growth in Appalachian Basin production. Dr. Vasquez noted that MGPC's fourteen member companies collectively have existing or anticipated capacity needs on the Ridgeline System that, combined with other shipper demand, would support utilization well above 75%.
MGPC's proposed rate ceiling of approximately $0.2560/Dth is calculated assuming an 85% load factor combined with an ROE of 11.25%. MGPC views the load factor issue as complementary to the ROE issue — both must be resolved in the intervenors' favor to achieve their target rate.
4. Impact Analysis
The load factor assumption has the largest per-unit rate impact of the three sticking points. The following calculations illustrate the rate impact at various load factor assumptions, holding all other cost-of-service parameters at Ridgeline's current revised levels (total COS of $103.15 million):
• At 85% load factor: Billing determinants = 1,200,000 Dth/d × 365 × 0.85 = 372,300,000 Dth/yr. Recourse rate = $103.15M ÷ 372,300,000 = approximately $0.2771/Dth.
• At 80% load factor: Billing determinants = 1,200,000 Dth/d × 365 × 0.80 = 350,400,000 Dth/yr. Recourse rate = $103.15M ÷ 350,400,000 = approximately $0.2944/Dth.
• At 75% load factor (Ridgeline's current position): Billing determinants = 328,500,000 Dth/yr. Recourse rate = $0.3140/Dth.
The rate reductions relative to Ridgeline's current 75% position are striking. Moving from 75% to 80% reduces the recourse rate by approximately $0.0196/Dth. Moving from 75% to 85% reduces the rate by approximately $0.0369/Dth. These are the largest single-issue rate movements available in the negotiation.
However, the load factor issue also carries the greatest risk for Ridgeline. Under the filed rate doctrine, the recourse rate approved by the Commission becomes the ceiling rate that Ridgeline may charge. Ridgeline can only recover revenue through actual throughput multiplied by the filed rate. If the pipeline fails to achieve the assumed load factor — that is, if actual throughput falls short of the billing determinants used to derive the rate — Ridgeline bears the volume risk. A higher assumed load factor produces a lower filed rate, which means that each dekatherm of shortfall below the assumed throughput level results in unrecovered costs. With current throughput at only 56.67% of design capacity, the gap between assumed and actual utilization is already substantial, and any increase in the assumed load factor widens that gap further.
The strategic consideration for Ridgeline is therefore clear: any concession on load factor must be weighed against the increased volume risk that Ridgeline would bear over the life of the tariff. This risk can be partially mitigated if throughput grows toward design capacity, but throughput growth is not guaranteed and depends on factors outside Ridgeline's control, including production levels in the Basin, competing pipeline capacity, and the timing of the interconnection with ATPC.
5. ZOPA on Load Factor
The range of positions on load factor extends from 75% (Ridgeline) to 85% or higher (ATPC and MGPC). The estimated Zone of Possible Agreement on load factor is 78% to 82%.
The rate implications of various compromise positions on load factor, when combined with a compromise on ROE, illustrate the potential for a package settlement:
• At 80% load factor with 12.50% ROE (Ridgeline's current ROE): Rate ≈ $0.2944/Dth.
• At 80% load factor with 11.75% ROE: Rate ≈ approximately $0.2910/Dth, reflecting the combined effect of both load factor and ROE compromise.
We recommend that Ridgeline be prepared to move to a load factor in the range of 78% to 80% as part of a package settlement, but that this concession be conditioned on extracting meaningful concessions from the intervenors on ROE. Ridgeline's volume risk increases with each percentage point increase in the assumed load factor, and this risk should be compensated through a higher ROE or offset through other favorable settlement terms. The load factor concession should not be offered in isolation; rather, it should be part of a coordinated package that provides Ridgeline with adequate consideration across all three sticking points.
IV. Composite ZOPA and Package Settlement Analysis
A. Scenario Modeling
To facilitate the Board's evaluation of settlement options, we have modeled five scenarios that span the range of possible outcomes from Ridgeline's current position through the intervenors' position, including three compromise scenarios at various points within the ZOPA. Each scenario adjusts the three key settlement parameters (ROE, load factor, and interconnection cost allocation) and derives the resulting estimated recourse rate.
Scenario A — Ridgeline's Current Position: ROE of 12.50%, load factor of 75%, interconnection cost allocation of 34.1% Ridgeline / 65.9% ATPC. This scenario corresponds to Ridgeline's revised tariff filing and produces a recourse rate of $0.3140/Dth. This is Ridgeline's floor position in negotiations.
Scenario B — ATPC/MGPC Position: ROE of approximately 10.75% to 11.25%, load factor of 85% or higher, interconnection cost allocation of 50/50. This scenario corresponds to the intervenors' combined position and produces a recourse rate of approximately $0.2560/Dth or lower. This is the intervenors' ceiling position.
Scenario C — Midpoint Package: ROE of 11.75%, load factor of 80%, interconnection cost allocation of 45% Ridgeline / 55% ATPC. This scenario represents a balanced compromise across all three sticking points and produces an estimated recourse rate of approximately $0.2880/Dth.
Scenario D — Ridgeline-Favorable Compromise: ROE of 12.00%, load factor of 78%, interconnection cost allocation of 42% Ridgeline / 58% ATPC. This scenario tilts the compromise modestly in Ridgeline's favor and produces an estimated recourse rate of approximately $0.2980/Dth.
Scenario E — Intervenor-Favorable Compromise: ROE of 11.50%, load factor of 82%, interconnection cost allocation of 48% Ridgeline / 52% ATPC. This scenario tilts the compromise modestly in the intervenors' favor and produces an estimated recourse rate of approximately $0.2790/Dth.
B. Detailed Calculation for Scenario C (Illustrative)
To provide a more detailed illustration of how the package settlement analysis operates, we set forth below the key steps in calculating the estimated recourse rate under Scenario C.
Step 1: WACC Calculation. At an ROE of 11.75% and a cost of debt of 5.25%, with a capital structure of 55% equity / 45% debt:
WACC = (0.55 × 11.75%) + (0.45 × 5.25%) = 6.4625% + 2.3625% = 8.825%
Step 2: Return on Rate Base. Using the current rate base of $612.40 million:
Return on Rate Base = $612.40M × 8.825% = approximately $54.04 million
Step 3: Adjusted Cost of Service. The total cost of service under Scenario C is estimated by combining the return on rate base with the other cost-of-service components. Using the baseline figures from the redesigned tariff:
• Return on rate base: $54.04 million
• Depreciation expense: $14.68 million
• Operations and maintenance expense: $13.92 million
• Administrative and general expense: $5.14 million
• Taxes other than income tax: $3.80 million
• Income tax: recalculated at the 26.13% effective rate to reflect the lower equity return under Scenario C (the reduction in taxable income associated with the lower ROE reduces the income tax component accordingly)
• Less revenue credits: ($6.00 million)
The income tax recalculation is necessary because the income tax component of cost of service is a function of the equity return, and a lower ROE reduces the taxable equity return and thus the associated income tax. The precise recalculation depends on Ridgeline's tax posture as a flow-through entity and the applicable statutory and effective tax rates, which are addressed in the Braswell workpapers.
Taking these components together, the estimated total cost of service under Scenario C is approximately $100.3 million. This is directionally lower than Ridgeline's current revised COS of $103.15 million, reflecting primarily the reduced equity return and associated income tax savings.
Step 4: Billing Determinants. At an 80% load factor:
Billing Determinants = 1,200,000 Dth/d × 365 days × 0.80 = 350,400,000 Dth/yr
Step 5: Estimated Recourse Rate.
Recourse Rate = $100.3M ÷ 350,400,000 Dth/yr ≈ $0.2863/Dth (reservation + usage combined)
This falls within the range of approximately $0.2800 to $0.2900/Dth that we have identified as the target zone for a package settlement.
Step 6: Gap Analysis. Under Scenario C, the rate gap narrows from the current $0.058/Dth (the distance between Ridgeline's $0.3140/Dth floor and the intervenors' $0.2560/Dth ceiling) to approximately $0.024 to $0.034/Dth relative to the intervenors' $0.2560/Dth ceiling. In other words, Ridgeline would be conceding approximately $0.026/Dth from its current position, and the intervenors would need to move upward approximately $0.024 to $0.032/Dth from their stated ceiling to reach agreement. This represents a roughly symmetrical movement by both sides, which is typically a favorable indicator for settlement achievability.
C. Assessment of Achievability
Scenario C (the midpoint package at approximately $0.2880/Dth) requires meaningful movement from both sides. Ridgeline would concede approximately $0.026/Dth from its floor position, while the intervenors would need to concede approximately $0.032/Dth from their stated ceiling.
The willingness of each party to make the necessary concessions depends on their respective motivations and constraints:
MGPC's Willingness to Compromise. MGPC's fourteen member companies are prospective shippers who benefit directly from the Ridgeline pipeline being in active service and from the interconnection with ATPC increasing market access. Delay has real economic costs for MGPC's members: continued uncertainty about transportation rates impedes production planning, and the absence of the interconnection limits market diversification. MGPC may therefore be more willing to compromise than ATPC, particularly if a settlement provides rate certainty that allows producers to finalize their transportation arrangements. We assess MGPC's willingness to move upward from the $0.2560/Dth ceiling as moderate to high.
ATPC's Willingness to Compromise. ATPC's opposition to Ridgeline's rate proposals may be partly strategic. A lower recourse rate on the Ridgeline system limits the competitiveness of Ridgeline as a transportation alternative and potentially constrains Ridgeline's ability to attract shippers away from ATPC's own system. ATPC may therefore have less incentive to facilitate a settlement than the other parties. However, ATPC also has a strong interest in completing the interconnection, which would bring new supply onto ATPC's system and increase utilization of ATPC's existing capacity. The interconnection benefits are significant for ATPC's bottom line, and this may provide leverage in negotiations. We assess ATPC's willingness to move upward as moderate, conditioned on favorable interconnection cost allocation terms.
CMGA's Willingness to Compromise. CMGA's position is largely derivative of ATPC's. As a municipal authority with limited resources and limited capacity for independent analysis, CMGA is likely to accept any settlement that ATPC accepts. CMGA's incremental impact on the negotiation dynamic is limited.
FERC Trial Staff's Position. Staff's informal indication that its ROE analysis is likely to fall in the 11.00% to 12.00% range suggests that Staff would likely support a settlement in the Scenario C or Scenario D range. Staff support is an important factor in the Commission's review of any proposed settlement, and a settlement that falls within Staff's analytical range has a significantly higher probability of approval.
V. Strategic Considerations
A. Timing and the February 21, 2025 Deadline
The February 21, 2025 filing deadline established by ALJ Whitfield creates a hard deadline that shapes the settlement dynamics. If no settlement is reached before that date, Ridgeline will be required to file the redesigned tariff and supplemental testimony, and the Track II hearing will resume before ALJ Whitfield. The filing deadline thus converts the settlement window from an open-ended process into a defined 125-day negotiating period (from the date of this memorandum).
A litigated outcome carries material risk for Ridgeline. As discussed in Section V.E below, FERC ALJs have in recent proceedings adopted ROEs closer to Staff's recommendations, which tend to be in the 11.00% to 12.00% range. Load factor determinations are fact-intensive and uncertain, and the intervenors' 85% proposal has some factual support from comparable pipeline experience. Cost allocation determinations are similarly uncertain, with mixed FERC precedent that could support a range of outcomes. The net effect is that a litigated outcome could produce a rate determination at or below the Scenario C–D range, without the certainty, speed, or cost savings of a negotiated resolution.
The filing deadline also serves as a natural forcing mechanism. As the deadline approaches, the parties' incentive to settle increases, because the alternative to settlement — a resumed hearing — involves substantial time and expense. This dynamic typically accelerates settlement discussions in the final weeks before a filing deadline, and we expect the same pattern here.
We recommend scheduling a fifth settlement conference in early January 2025, or in late December 2024 at the earliest, to present a comprehensive package settlement proposal. This timing allows sufficient lead time for the parties to evaluate the proposal and negotiate revisions before the February 21, 2025 deadline, while also creating a sense of urgency that may motivate concessions.
B. Lender Considerations
Ridgeline's financing structure introduces additional considerations that favor a negotiated settlement over a litigated outcome.
Pinnacle National Bank, N.A. serves as agent bank for Ridgeline's Senior Secured Credit Facility, dated September 15, 2021. The outstanding term loan balance is $362.8 million as of December 31, 2024, with a maturity date of October 1, 2028. Pinnacle has been receiving covenant compliance updates throughout the proceeding; the most recent compliance letter was delivered in June 2024.
FERC tariff approval is a condition precedent to certain covenant calculations under the Credit Facility. Specifically, certain financial covenants tied to projected revenue and debt service coverage ratios are calculated using the approved tariff rate as a baseline assumption. Until the tariff is approved — whether through settlement or litigation — these covenant calculations involve an element of uncertainty that the lenders have tolerated to date but that may become less acceptable as the term loan approaches maturity.
The second lien noteholders also have an interest in the proceeding's resolution. Harborview Capital Management LLC (contact: Samantha Hu) and Sentinel Ridge Fund LP (contact: Peter Nowicki) collectively hold second lien notes on the Ridgeline System. Both were notified of the current proceeding status via letter in December 2024. While neither has taken a formal position on the settlement negotiations, both have expressed a preference for timely resolution.
A settlement that provides rate certainty is strongly preferable to the lenders over a litigated outcome with an uncertain timeline. The hearing process, followed by an initial decision by the ALJ, Commission review, and potential rehearing and appeal, could extend the resolution timeline by 18 to 36 months. During that period, Ridgeline would continue operating under interim rate authority, with the attendant uncertainty in revenue projections and covenant calculations.
Additionally, Ridgeline's revolving credit facility of $75 million may be needed for liquidity purposes during the interconnection construction period and ongoing operations. Covenant compliance should be monitored closely throughout the settlement process, and any settlement proposal should be evaluated not only for its rate impact but also for its implications for debt service coverage and covenant compliance.
DEH's equity contribution to the pipeline construction was $37.2 million, calculated as the difference between the total construction cost of $587.2 million and the combined debt financing of $550 million (comprising the $400 million term loan, the $150 million in second lien notes, and other funded amounts). Any rate outcome that materially threatens the economics of the project could affect DEH's ability to service its debt obligations and maintain covenant compliance, with potential cascading effects on the broader DEH portfolio.
C. Interconnection Timeline
The original target in-service date for the interconnection facilities was Q4 2023. This date has now passed, and the interconnection construction has been delayed pending resolution of this proceeding. The delay introduces several concerns.
First, construction cost escalation risk is increasing. The $22.3 million estimate for the interconnection facilities was prepared in 2022 and has not been formally updated. Construction material and labor costs in the Appalachian Basin have increased since 2022, and a prolonged delay could result in a higher actual construction cost. Any increase in construction costs would need to be allocated between the parties under whatever cost-sharing arrangement is ultimately agreed upon or ordered by the Commission.
Second, the delay in interconnection construction delays the realization of throughput growth that Ridgeline expects from the interconnection. Until the interconnection is completed and placed in service, Ridgeline's throughput will remain constrained to the current levels achievable through its existing delivery points. This constraint limits Ridgeline's revenue and makes the volume risk associated with any assumed load factor more acute.
A settlement that resolves both the rate case (Docket No. RP22-847-000) and the interconnection authorization (Docket No. RP22-847-001) simultaneously would allow construction to commence promptly. This dual resolution is a key advantage of the package settlement approach, as it addresses both the financial and operational dimensions of the proceeding in a single negotiated outcome.
D. Client's Business Considerations
The settlement analysis must be considered in the context of DEH's broader business portfolio and Patricia Dunmore's strategic priorities.
DEH is a Cayman Islands exempted limited company (registration number CR-381204) with an estimated enterprise value of approximately $2.8 billion based on an internal valuation as of December 31, 2023. DEH's annual consolidated revenue was approximately $485 million in 2023. The DEH portfolio includes approximately 1,200 miles of midstream pipelines across the Appalachian and Mid-Atlantic regions, two cryogenic gas processing plants, and a 250 MW wind energy portfolio currently under development.
The Ridgeline System is a significant component of the DEH portfolio, both in terms of asset value and strategic importance. The System's current utilization of 56.67% represents substantial untapped revenue potential. As throughput grows toward the design capacity of 1.2 Bcf/d — particularly with the incremental volumes expected from the ATPC interconnection — Ridgeline's total revenue will increase significantly even at a lower per-unit rate. In other words, a slightly lower recourse rate combined with higher throughput volumes may produce superior total revenue outcomes compared to a higher rate with limited throughput growth.
This dynamic has important implications for the settlement strategy. A settlement that accepts a modestly lower recourse rate but facilitates the timely completion of the interconnection (and thereby accelerates throughput growth) may be more valuable to DEH and Ridgeline in present-value terms than a protracted litigation that preserves a higher rate filing but delays throughput growth and interconnection completion.
Patricia Dunmore's strategic perspective, as discussed in our most recent engagement review meeting, favors a resolution that preserves long-term shipper relationships and supports the broader midstream portfolio. Ms. Dunmore has emphasized the importance of maintaining constructive relationships with MGPC's member producers, who are not only shippers on the Ridgeline System but also supply gas to DEH's processing facilities. A contentious litigation outcome that alienates producers could have negative implications for DEH's relationships across its midstream portfolio.
Ms. Dunmore's dual role as both the controlling shareholder and Chairperson of DEH and the billing partner at C&H for this engagement has been previously disclosed and subject to an appropriate conflict waiver. We note this dual role here only to confirm that the settlement recommendations in this memorandum have been developed independently by the engagement team and reflect our best professional judgment as to Ridgeline's optimal settlement strategy, without regard to billing considerations.
E. Litigation Risk Assessment
In assessing the relative merits of settlement versus litigation, we have evaluated the litigation risk on each of the three sticking points. Our assessment is based on a review of recent FERC precedent, the strength of each party's evidence and arguments, and the likely analytical framework that ALJ Whitfield would apply under Track II hearing procedures.
ROE Litigation Risk: Moderate to High. The trend in recent FERC proceedings has been toward lower pipeline ROEs, driven in part by declining capital costs and compressed equity risk premiums relative to historical levels. FERC ALJs have in several recent proceedings adopted ROEs closer to Staff's recommendations, which tend to fall in the 11.00% to 12.00% range. While Ridgeline's 12.50% position is defensible, there is a meaningful probability that the ALJ would adopt a lower figure, potentially in the 11.00% to 11.75% range. An adverse ROE determination at or below 11.00% would have a significant impact on Ridgeline's return on investment and would be difficult to reverse on rehearing or appeal absent clear legal error.
Load Factor Litigation Risk: Moderate. The load factor determination is fact-intensive and depends on the ALJ's assessment of projected throughput, contractual commitments, and comparable pipeline experience. Ridgeline's current 75% assumption faces criticism because the actual utilization of 56.67% is well below the assumed level, which could lead the ALJ to question the basis for any load factor above actual utilization. However, the intervenors' 85% or higher proposal is also aggressive, as it assumes throughput growth that has not yet materialized and depends on the completion of the interconnection, which is itself at issue in this proceeding. The ALJ could reasonably adopt a load factor anywhere in the 75% to 85% range, creating significant uncertainty for both sides.
Cost Allocation Litigation R