PRIVILEGED AND CONFIDENTIAL — 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
Angela Moretti, VP, Finance & Treasurer, Ridgeline Midstream Services LLC
Dr. Natasha Orlov, Director of Rates & Regulatory, 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: Updated discounted Cash Flow Proxy Group Analysis — Q3 2024; Revised Return on Equity Recommendation for Ridgeline Midstream Services LLC, 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 present the updated discounted cash flow ("DCF") proxy group analysis as of the third quarter of 2024, supporting a revised return on equity ("ROE") of 12.50% for Ridgeline Midstream Services LLC ("Ridgeline" or the "Company") for inclusion in the redesigned tariff filing to be submitted on or before February 21, 2025, in FERC Docket Nos. RP22-847-000 (rate case) and RP22-847-001 (interconnection). This revised ROE recommendation reflects current market data and conditions, application of FERC's established two-step DCF methodology, and careful consideration of Ridgeline's company-specific risk factors.
By way of context, the original filing dated May 12, 2022, proposed a 14.00% ROE based on a DCF proxy group analysis using market data through year-end 2021. The original ROE testimony of Dr. Raymond Braswell, filed as pre-filed direct testimony on December 5, 2022, relied on this year-end 2021 data. On January 19, 2023, the Federal Energy Regulatory Commission's ("FERC" or the "Commission") Office of Energy Market Regulation, under the lead economic analysis of Dr. Miriam Okafor, issued a Deficiency Letter identifying fourteen deficiency items. Deficiency Item 1 specifically identified the original ROE support as inadequate because no updated proxy group analysis reflecting post-2021 market conditions had been provided. This memorandum directly addresses Deficiency Item 1, and the revised analysis presented herein supersedes the original ROE testimony of Dr. Braswell dated December 5, 2022.
The revised 12.50% ROE is the product of a two-step DCF analysis utilizing Q3 2024 market data, consistent with FERC's established methodology in recent pipeline rate proceedings. The analysis is based on a proxy group of ten publicly traded companies that derive a substantial portion of their revenue from FERC-jurisdictional natural gas pipeline operations or comparable midstream activities. The proxy group yields a zone of reasonableness ranging from approximately 8.50% to 13.00%, with a median of approximately 10.94%. Ridgeline's recommended placement in the upper portion of the zone—at the approximately 75th percentile—is warranted by its above-average risk profile as a single-asset, new-entrant pipeline system with a current utilization rate of only 56.67%, high actual financial leverage, and the absence of any prior FERC-approved tariff rate.
The revised 12.50% ROE, combined with the unchanged capital structure of 55% equity and 45% debt and the cost of debt of 5.25%, produces a revised weighted average cost of capital ("WACC") of 9.2375%. When applied to the $612.40 million rate base, this results in a revised return on rate base of $56.57 million. The revised total cost of service is $103.15 million, producing a revised recourse rate of $0.3140/Dth at a 75% load factor.
We note the positions of opposing parties for comparison. Appalachian Trunk Pipeline Company, LLC ("ATPC") proposes a 10.75% ROE, effectively placing Ridgeline at the median of the proxy group and treating it as an average-risk pipeline—a characterization that is unsupportable given Ridgeline's risk profile. Mountainside Gas Producers Coalition ("MGPC"), through the testimony of Dr. Eleanor Vasquez, proposes an 11.25% ROE, which, while more nuanced than ATPC's position, does not adequately compensate for Ridgeline's single-asset concentration risk, start-up risk, and actual financial leverage. Ridgeline's revised 12.50% reflects a measured and responsible reduction of 150 basis points from the original 14.00% while maintaining adequate compensation for the risks specific to a new-entrant, single-asset midstream pipeline system.
Finally, we note that Braswell Energy Consulting Group LLC (engagement number BEC-2023-0041, lead consultant Dr. Raymond Braswell) has independently reviewed and confirmed the proxy group selection and analytical methodology described herein. Dr. Braswell's independent review memorandum will be available as a supporting exhibit to the supplemental testimony.
II. Background and Procedural Context
A. Original ROE Filing and Deficiency
Ridgeline Midstream Services LLC filed its application for an initial tariff rate under Section 4 of the Natural Gas Act ("NGA"), 15 U.S.C. § 717c, and the Commission's regulations at 18 C.F.R. Part 154, on May 12, 2022. The application proposed a recourse rate of $0.2265/Dth, comprised of a reservation charge of $0.2223/Dth and a usage charge of $0.0042/Dth, based on a total cost of service of $97.36 million. The rate was designed using billing determinants calculated at a 100% load factor applied to the system's 1.2 Bcf/d (1,200,000 Dth/d) design capacity, yielding annual billing determinants of 438,000,000 Dth.
The original filing proposed a 14.00% ROE, which was supported by the pre-filed direct testimony of Dr. Raymond Braswell of Braswell Energy Consulting Group LLC, filed on December 5, 2022. Dr. Braswell's testimony relied on a DCF proxy group analysis utilizing market data through December 31, 2021. The proxy group consisted of eight publicly traded companies with operations in the natural gas pipeline and midstream sectors, and the analysis produced a zone of reasonableness that Dr. Braswell concluded supported a 14.00% ROE for Ridgeline based on its risk profile.
The proposed capital structure was 55% equity and 45% debt, which reflected the regulatory capital structure deemed appropriate for ratemaking purposes rather than the Company's actual book capital structure. The proposed cost of debt was 5.25%, representing the weighted average of (i) a $400 million term loan bearing interest at SOFR plus 325 basis points, provided by a syndicate led by Pinnacle National Bank, N.A. as administrative agent, with Granite Trust Company and Lakeshore Capital Bank as co-syndication agents, and (ii) $150 million in 7.875% Second Lien Senior Secured Notes privately placed with Harborview Capital Management LLC and Sentinel Ridge Fund LP. The resulting WACC under the original proposal was 10.0625% ((0.55 × 14.00%) + (0.45 × 5.25%) = 7.70% + 2.3625% = 10.0625%).
On January 19, 2023, the Commission's Office of Energy Market Regulation issued a Deficiency Letter identifying fourteen deficiency items requiring supplemental information and analysis. Deficiency Item 1 was directed specifically at the inadequacy of the ROE support. The Deficiency Letter, authored under the oversight of lead economic analyst Dr. Miriam Okafor, stated that the original proxy group analysis, which relied exclusively on data through December 31, 2021, did not reflect the substantial changes in capital markets, interest rates, and energy sector equity valuations that occurred during 2022, and that no updated analysis had been provided with the December 2022 testimony. The Deficiency Letter further observed, without taking a formal position, that the proposed 14.00% ROE exceeded recent FERC-approved ROEs for comparable pipeline rate proceedings.
The thirteen additional deficiency items addressed various aspects of the filing, including load factor assumptions (Item 2), interconnection cost allocation methodology (Item 3), depreciation rates (Item 5), and the calculation of the income tax allowance (Item 9), among others. A comprehensive response to all fourteen items is being prepared for the February 21, 2025 filing deadline.
In response to the Deficiency Letter, Administrative Law Judge Clara Whitfield, who was assigned to the proceeding, issued a procedural order on February 6, 2023, staying the Track II procedural schedule pending resolution of the deficiency items. On September 8, 2023, following the passage of more than six months without a filing, the proceeding was designated as dormant on FERC's docket. Two extensions of the filing deadline were granted in 2023, and a third extension was granted on March 4, 2024, establishing the current deadline of February 21, 2025, for the filing of a redesigned tariff and supplemental testimony responsive to the Deficiency Letter.
B. Opposing Party ROE Positions
Before the proceeding was stayed, several opposing parties filed answering testimony on January 9, 2023, taking positions on Ridgeline's proposed ROE, among other issues.
ATPC Position. William Pratt of Kellner, Royce & Dillard LLP, representing Appalachian Trunk Pipeline Company, LLC ("ATPC"), proposed a 10.75% ROE. ATPC is a long-established 640-mile interstate natural gas pipeline system with 3.8 Bcf/d of certificated capacity, operating across four states in the Appalachian region. ATPC's parent company is Tidewater Infrastructure Partners LP, a diversified energy infrastructure holding company with an estimated enterprise value of approximately $6.1 billion, controlled by the Alderman family. In its answering testimony, ATPC argued that Ridgeline, as a 100% subsidiary of Dunmore Energy Holdings Ltd. ("DEH") with a current throughput of only approximately 680 MMcf/d on a 1.2 Bcf/d capacity system (representing 56.67% utilization), does not warrant a premium ROE above the industry midpoint. ATPC's analysis effectively treated Ridgeline as possessing risk characteristics comparable to the average pipeline in the proxy group, a characterization we contest for the reasons discussed in Section VI below.
MGPC Position. Dr. Eleanor Vasquez, a rate expert retained by the Mountainside Gas Producers Coalition ("MGPC"), filed testimony on January 9, 2023, proposing an 11.25% ROE. MGPC is a coalition of fourteen independent natural gas producers operating in the Appalachian Basin, with executive director Calvin Dreyer serving as the coalition's designated representative. MGPC is represented by Rebekah Montague of Whitmore & Sable LLP. Dr. Vasquez's analysis used year-end 2022 data—more current than the original filing's year-end 2021 data, but now itself outdated—and placed Ridgeline slightly above the median of her proxy group, acknowledging some incremental risk attributable to Ridgeline's single-asset status. MGPC's overall position on rates supports a rate ceiling of approximately $0.2560/Dth, which reflects both the lower ROE and MGPC's advocacy for a higher load factor (85% or above) in calculating billing determinants.
CMGA Position. Clearwater Municipal Gas Authority ("CMGA"), a municipal gas distribution utility serving approximately 42,000 customers in the greater Clearwater, West Virginia area, generally supports ATPC's cost-allocation position. CMGA's general manager is Dennis Ott, and it is represented by Stephen Greer of Fordham Municipal Law Group PC. CMGA has not filed independent ROE testimony, instead relying on the analyses presented by ATPC and MGPC.
FERC Trial Staff. Trial Staff, led by trial attorney Jonathan Briggs and economic analyst Dr. Miriam Okafor, has not taken a formal position on ROE. However, as noted above, the Deficiency Letter observed that the originally proposed 14.00% ROE exceeded recent FERC-approved ROEs for comparable pipeline proceedings. Trial Staff's position on ROE is expected to be articulated following the submission of the redesigned tariff filing and supplemental testimony.
C. Settlement Context
Four settlement conferences have been conducted before Settlement Judge Howard Margolis, held on November 30, 2022; March 8, 2023; July 12, 2023; and January 18, 2024. No settlement has been reached.
The current settlement gap is approximately $0.058/Dth, reflecting the difference between Ridgeline's floor position of approximately $0.3140/Dth (based on the revised 12.50% ROE and 75% load factor) and the ATPC/MGPC ceiling position of approximately $0.2560/Dth (which reflects their lower ROE proposals and higher load factor assumptions of 85% or above). The settlement gap is attributable to disagreements on three principal issues: (i) the appropriate ROE, (ii) interconnection cost allocation methodology (involving $22.3 million in total interconnection costs, with Ridgeline proposing a $7.6 million / $14.7 million split and ATPC advocating a 50/50 allocation at $11.15 million each), and (iii) the appropriate load factor for billing determinants.
The revised 12.50% ROE represents a meaningful narrowing of the gap from the original 14.00% proposal. While a significant distance remains between the parties, the downward revision provides a credible basis for renewed settlement discussions while preserving Ridgeline's ability to litigate a defensible position under FERC precedent.
III. FERC Legal Standards for ROE Determination
A. The Two-Step DCF Methodology
FERC has long employed the discounted cash flow ("DCF") methodology for determining the appropriate ROE for natural gas pipeline companies under Sections 4 and 5 of the Natural Gas Act. The DCF approach is grounded in the foundational principles established by the United States Supreme Court in Bluefield Waterworks & Improvement Co. v. Public Service Commission of West Virginia, 262 U.S. 679 (1923), and Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944). Under these precedents, a regulated entity is entitled to an opportunity to earn a return on its invested capital that is (i) commensurate with returns on investments in enterprises having corresponding risks, (ii) sufficient to assure confidence in the financial integrity of the enterprise, and (iii) adequate to maintain the entity's credit and attract capital. At the same time, the return must not be so excessive as to impose an undue burden on ratepayers.
The DCF methodology provides a market-based estimate of the cost of equity capital by examining the returns that investors in publicly traded companies with comparable risk profiles require. The fundamental premise is that the cost of equity equals the sum of the expected dividend yield and the expected long-term growth rate in dividends. In its simplest form, the DCF formula is expressed as:
k = D₁/P₀ + g
where:
k = the cost of equity (i.e., the DCF-derived ROE);
D₁/P₀ = the expected dividend yield, calculated as the current annualized dividend adjusted for expected growth (D₁) divided by the current stock price (P₀); and
g = the expected long-term growth rate in dividends.
FERC has adopted a "two-step" variant of this formula, which blends short-term and long-term growth rate expectations to produce a more representative estimate of investor expectations. Under the two-step methodology, the growth rate component is calculated as follows:
g = (short-term growth rate × ⅔) + (long-term GDP growth rate × ⅓)
The short-term growth rate is derived from consensus analyst estimates of earnings growth (typically over a 3-to-5-year forecast horizon) for each proxy group member. The long-term growth rate is based on the expected long-term nominal growth rate of the U.S. economy (GDP), which serves as a proxy for the sustainable long-term growth trajectory of mature regulated pipeline companies. The rationale for the two-step approach is that while near-term analyst growth expectations provide useful information about the current trajectory of individual companies, regulated pipeline companies cannot be expected to grow indefinitely at rates that materially exceed the overall economy; accordingly, the long-term GDP growth rate is weighted at one-third to anchor the analysis in sustainable long-run expectations.
This two-step DCF methodology was articulated and refined by the Commission in Opinion No. 531, Martha Coakley, et al. v. Bangor Hydro-Electric Co., 147 FERC ¶ 61,234 (2014), and its progeny, and has been consistently applied in natural gas pipeline rate proceedings as the standard framework for proxy group selection and ROE determination.
B. Proxy Group Selection Criteria
The reliability of the DCF analysis depends critically on the selection of an appropriate proxy group—a set of publicly traded companies whose risk profiles and business characteristics are sufficiently comparable to the regulated pipeline at issue. FERC has established well-defined criteria for proxy group inclusion, which may be summarized as follows:
(1) Public Trading Requirement. The company must be publicly traded on a major U.S. exchange with readily available dividend and stock price data over the measurement period. This requirement ensures that market-based valuation data is available for the DCF calculation.
(2) Investment-Grade Credit Rating. The company must hold an investment-grade credit rating (BBB- or above) from at least one nationally recognized statistical rating organization ("NRSRO"), such as Standard & Poor's or Moody's Investors Service. Companies with below-investment-grade ratings are excluded because their equity risk profiles are likely distorted by elevated credit risk that is not representative of regulated pipeline operations.
(3) No Distortive Merger or Acquisition Activity. The company must not have been involved in a pending or recently completed merger, acquisition, or similar transformative transaction during the study period that would distort its stock price, dividend data, or growth rate expectations. Merger-related activity can introduce speculative premiums or discounts into stock prices that do not reflect the underlying cost of equity for ongoing pipeline operations.
(4) Substantial FERC-Jurisdictional Revenue. The company must derive a substantial portion of its revenue from FERC-jurisdictional natural gas pipeline operations or comparable midstream activities. The Commission has generally required that proxy group members be predominantly engaged in pipeline transportation or closely related midstream services, as opposed to diversified energy companies for which pipeline operations are a minor segment.
(5) Outlier Exclusion. The company's individual DCF result must not be an outlier. Results below 0% or producing a negative value are excluded as low-end outliers, as they suggest market anomalies or company-specific distress that render the data unreliable. Results exceeding two standard deviations above the mean of the proxy group may be examined and, if warranted, excluded as high-end outliers that could skew the analysis.
The Commission has recognized a distinction between "pure-play" natural gas pipeline companies—those that derive the overwhelming majority of their revenue from FERC-jurisdictional pipeline transportation—and diversified energy companies that may include pipeline segments alongside exploration and production, refining, marketing, or other activities. FERC has expressed a preference for pure-play or predominantly pipeline-focused entities in the proxy group, as their market valuations are most directly reflective of the risks and returns associated with regulated pipeline operations. Where the universe of pure-play companies is insufficient to form a robust proxy group, companies with substantial but not exclusive pipeline operations may be included, with appropriate recognition of the analytical limitations.
C. Relevant FERC Precedent on Midstream Pipeline ROEs
A review of FERC orders in natural gas pipeline rate proceedings from 2020 through 2024 reveals that approved ROEs have generally fallen within a range of approximately 10.00% to 13.50%. The specific ROE approved in any given case has depended on the unique facts and circumstances, including the risk profile of the pipeline at issue and the composition of the proxy group at the time of the analysis.
Within this range, FERC has demonstrated willingness to approve ROEs in the upper portion of the zone of reasonableness—that is, above the median of the proxy group—where pipeline-specific risk factors justify such placement. Among the risk factors that the Commission has considered in prior proceedings are:
• Single-asset vs. multi-asset systems: Pipelines that operate a single system without the geographic and operational diversification of multi-asset portfolio companies face concentration risk that supports above-median placement.
• Geographic concentration: Systems located entirely within a single production basin or serving a limited number of delivery points face heightened market risk if production declines or demand shifts away from the system's footprint.
• Utilization levels: Systems operating well below design capacity face higher per-unit cost risk and uncertainty regarding future revenue adequacy.
• Regulatory history: Pipelines filing for their initial tariff rate—with no history of FERC-approved rates—face regulatory uncertainty that established systems with multiple rate proceedings do not.
• Competitive alternatives: The availability of alternative transportation options for shippers affects the competitive risk faced by the pipeline, with systems in less competitive corridors potentially warranting different treatment.
These considerations are directly relevant to Ridgeline's placement within the zone of reasonableness, as discussed in detail in Section VI below. A comprehensive table of recent FERC precedent on pipeline ROEs is provided in Appendix D.
IV. Proxy Group Identification and Selection
A. Initial Screening Universe
The proxy group analysis began with the identification of all publicly traded U.S. companies that derive at least 50% of their consolidated revenues from FERC-jurisdictional natural gas transportation, gathering, processing, or related midstream services. This threshold ensures that the proxy group is composed of companies whose market valuations are driven primarily by the economics of regulated or quasi-regulated pipeline and midstream operations, rather than by unrelated business segments.
All market and financial data were sourced as of September 30, 2024, the close of the third quarter of 2024. Stock price data was collected for the six-month period from April 1, 2024 through September 30, 2024, consistent with FERC's practice of using a six-month averaging period to smooth short-term stock price volatility. Dividend and distribution data, credit ratings, and revenue composition data were sourced from publicly available filings, investor presentations, and recognized financial data services.
The initial screen yielded a total of twenty companies that appeared to satisfy the 50% revenue threshold based on their most recently reported annual financial results. This initial universe included a mix of entity types—C-corporations, publicly traded limited partnerships (MLPs) that have maintained distribution-paying structures, and former MLPs that have converted to C-corporation form—reflecting the ongoing structural evolution of the midstream sector.
B. Application of Screening Criteria
From this initial universe of twenty companies, we applied each of FERC's screening criteria sequentially to arrive at the final proxy group.
Credit Rating Screen. We required that each company hold an investment-grade credit rating of BBB- or above from at least one major nationally recognized statistical rating organization. Application of this screen eliminated four companies from the initial universe. Two companies held credit ratings of BB+ or below, reflecting elevated financial risk profiles that are not representative of the regulated pipeline sector. An additional two companies had no rated debt outstanding, making it impossible to confirm their credit quality through independent third-party assessment. After application of the credit rating screen, sixteen companies remained.
Merger/Acquisition Screen. We excluded companies that were involved in pending or recently completed mergers, acquisitions, or other transformative corporate transactions during the six-month measurement period (April 1, 2024 through September 30, 2024) that could have distorted their stock prices, dividend expectations, or analyst growth rate forecasts. Application of this screen eliminated three companies. Ironhorse Gathering Systems Inc. announced a definitive merger agreement with a strategic acquirer on June 14, 2024, causing its stock price to trade at a merger premium throughout the remainder of the measurement period. Bridgeway Energy Holdings LP completed a simplification transaction and corporate conversion on May 1, 2024, which substantially altered its distribution policy and capital structure. Pinecrest Gas Infrastructure Corp. was the subject of an unsolicited acquisition proposal that remained pending as of September 30, 2024, injecting speculative uncertainty into its market valuation. After application of the merger screen, thirteen companies remained.
Dividend Payment Screen. We excluded companies that did not pay dividends or distributions consistently throughout the six-month study period. Consistent dividend payments are essential to the DCF analysis because the dividend yield component (D₁/P₀) is a foundational element of the formula; companies that suspended, initiated, or materially altered their dividends during the measurement period produce unreliable dividend yield data. Application of this screen eliminated two companies. Veltrano Gas Transmission Inc. suspended its quarterly dividend in July 2024 following an unplanned compressor station outage that materially impacted its cash flows. Bluewater Midstream Partners LP announced a restructuring of its distribution policy in August 2024 in connection with a capital expenditure program, introducing discontinuity into its distribution history during the measurement period. After application of the dividend screen, eleven companies remained.
Outlier Screen. We calculated preliminary DCF results for all eleven remaining companies using the two-step methodology described in Section V. We then examined the distribution of results for potential outliers. One company, Cornerstone Basin Energy Corp., produced a DCF result of 15.72%, which exceeded two standard deviations above the mean of the remaining companies. This result was attributable to an unusually high short-term growth rate estimate driven by a single analyst's projection of near-term earnings acceleration from a major capacity expansion project. Given the distortive effect of this outlier on the proxy group statistics, and consistent with FERC practice, we excluded Cornerstone Basin Energy Corp. from the final proxy group. No companies produced negative DCF results or results below zero. After application of the outlier screen, ten companies remained in the final proxy group.
C. Final Proxy Group Composition
The following table presents the ten companies comprising the final proxy group, along with their key characteristics:
Several observations regarding the proxy group composition merit discussion.
First, the proxy group is composed predominantly of multi-asset pipeline companies operating geographically diversified systems across multiple basins. This composition reflects the reality of the publicly traded pipeline sector, in which most companies of sufficient size and liquidity to be publicly traded operate portfolio systems. Ridgeline, by contrast, operates a single 187-mile pipeline system—a meaningful risk differentiator that supports above-median placement within the zone of reasonableness, as discussed in Section VI.
Second, the proxy group includes a range of credit qualities within the investment-grade spectrum, from BBB- to A-, providing a representative cross-section of financial risk profiles within the regulated pipeline sector. Ridgeline's own credit profile—while unrated as a single-asset subsidiary of DEH—is more appropriately compared to the lower end of the investment-grade spectrum given its leverage and start-up status.
Third, compared to the original proxy group used in Dr. Braswell's December 2022 testimony, the current proxy group reflects three additions and one deletion. Summit Ridge Pipeline Company and Copperhead Energy Transport Inc. were added following their initial public offerings in 2022 and 2023, respectively, which made their market data available for the first time. Westfall Pipeline Corporation was added following its conversion from MLP to C-corporation form in early 2023, which improved the comparability of its dividend and growth rate data. One company from the original proxy group—Cascade Mountain Gas Transport LP—was deleted because it was acquired by a private equity consortium in March 2024 and delisted from public trading.
V. DCF Analysis — Detailed Methodology and Inputs
A. Dividend Yield Calculation (D₁/P₀)
Consistent with FERC practice, we calculated the dividend yield for each proxy group member using a six-month average stock price measured from April 1, 2024 through September 30, 2024. The six-month averaging period is designed to smooth the effects of short-term stock price volatility, market fluctuations, and idiosyncratic trading events, producing a stock price that more reliably reflects the market's assessment of each company's intrinsic value over the measurement period.
For each company, the annualized current indicated dividend per share was determined based on the most recently declared quarterly dividend as of September 30, 2024, multiplied by four (or, in the case of Clarkfield Natural Gas Partners LP, the most recently declared quarterly distribution multiplied by four). The current dividend was then adjusted to reflect expected dividend growth over the coming year to produce D₁, the expected next-period dividend. This adjustment was made by multiplying the current annualized dividend by (1 + 0.5g), where g is the short-term growth estimate for each company. The half-year adjustment (0.5g rather than the full g) reflects the convention that, on average, dividends are received at the midpoint of the year, and therefore only half a year's growth should be applied to convert the current dividend into the expected next-period dividend.
The following table presents the dividend yield calculation for each proxy group member:
The range of dividend yields across the proxy group spans from 4.05% (Meridian Interstate Gas Holdings Corp.) to 7.71% (Clarkfield Natural Gas Partners LP). The median dividend yield is 5.62%, and the mean dividend yield is 5.58%. The relatively wide range reflects differences in payout policies, growth trajectories, and market valuations among the proxy group members, which is expected in a proxy group of this composition.
B. Growth Rate Estimation
1. Short-Term Growth Rate
The short-term growth rate for each proxy group member was derived from consensus analyst earnings growth estimates obtained from two recognized financial data services: Trident Financial Data Services and Meridian Equity Research. Consensus estimates from these services aggregate the projections of multiple equity research analysts covering each company, providing a market-based measure of expected near-term earnings growth.
The relevant time horizon is the 3-to-5-year projected growth rate in earnings per share ("EPS") or, where more appropriate for MLP entities, distributable cash flow per unit. Where multiple services provided estimates, the average of the two estimates was used. Where only one service provided a current estimate, that estimate was used, provided it was based on the projections of at least three covering analysts.
The following table presents the short-term growth rate for each proxy group member:
Short-term growth rates range from 2.65% (Clarkfield Natural Gas Partners LP) to 6.75% (Prairie Basin Energy Inc.). The median short-term growth rate is 4.88%, and the mean is 4.62%. The variation in short-term growth estimates reflects differing capital investment programs, contract structures, and growth opportunities across the proxy group.
2. Long-Term GDP Growth Rate
Consistent with FERC's established methodology, we employ the long-term nominal GDP growth rate of the United States as the proxy for the sustainable long-term growth rate of the proxy group companies. This approach rests on the well-accepted economic principle that mature regulated utilities and pipeline companies cannot be expected to sustain growth rates indefinitely that materially exceed the growth of the overall economy.
We sourced the long-term GDP growth rate estimate from the Hartwell Economic Forecasting Group's semi-annual long-term consensus survey, which aggregates the projections of approximately forty-five leading economists and forecasting organizations. The most recent survey, published in August 2024, yields a consensus long-term nominal GDP growth rate of 4.16%, reflecting approximately 2.10% real GDP growth and approximately 2.06% inflation over the long-term forecast horizon.
This 4.16% estimate is consistent with the range of long-term GDP growth rates used in recent FERC pipeline rate proceedings, which have generally fallen between 4.09% and 4.25%.
3. Two-Step Growth Rate Computation
Applying the two-step growth rate formula (g = short-term growth × ⅔ + long-term GDP growth × ⅓), we compute the blended growth rate for each proxy group member as follows:
The two-step blended growth rates range from 3.15% (Clarkfield Natural Gas Partners LP) to 5.89% (Prairie Basin Energy Inc.). The median blended growth rate is 4.56%, and the mean is 4.46%.
C. Individual DCF Results
Combining the dividend yield and two-step growth rate components, the individual DCF result for each proxy group member is calculated as k = D₁/P₀ + g:
No additional outlier exclusions are warranted from the final proxy group. The lowest result (Meridian Interstate Gas Holdings Corp. at 8.04%) is positive and does not fall below zero. The highest result (Prairie Basin Energy Inc. at 11.95%) does not exceed two standard deviations above the mean of 10.04%. The standard deviation of the ten DCF results is approximately 1.09%, and two standard deviations above the mean would be approximately 12.22%; the 11.95% result falls within this boundary and is therefore retained.
We note that Meridian Interstate Gas Holdings Corp.'s relatively low DCF result of 8.04% is consistent with its position as the highest-rated company in the proxy group (A- / A3) and a large, diversified interstate pipeline system with stable, predominantly demand-charge-based revenues. This result reflects the lower risk premium demanded by investors for such a company and appropriately anchors the low end of the zone of reasonableness.
Conversely, Prairie Basin Energy Inc.'s result of 11.95% reflects its higher growth rate expectations driven by an active expansion program in the Williston and Denver-Julesburg Basins and its somewhat higher-risk positioning within the midstream sector. This result appropriately defines the upper reaches of the zone of reasonableness.
Summary statistics for the proxy group DCF results:
D. Zone of Reasonableness
The zone of reasonableness is defined by the range of individual DCF results within the proxy group, after the exclusion of outliers. Based on the results presented above, the zone of reasonableness for this analysis extends from 8.04% at the low end to 11.95% at the high end, with a median of 10.11%.
This zone represents the range within which FERC may set the allowed ROE for Ridgeline based on an assessment of the Company's specific risk factors relative to those of the proxy group members. A pipeline with risk characteristics comparable to the average proxy group member would be placed at or near the median. A pipeline with above-average risk characteristics—such as Ridgeline—may be placed in the upper portion of the zone. Conversely, a pipeline with below-average risk characteristics might be placed in the lower portion.
The placement analysis that follows in Section VI considers the full spectrum of Ridgeline's risk characteristics and provides the basis for the recommended ROE of 12.50%.
We note that the recommended ROE of 12.50% exceeds the upper bound of the zone of reasonableness as strictly defined by the proxy group results (11.95%). However, the Commission has recognized in prior proceedings that where a pipeline's risk profile is demonstrably more elevated than that of any member of the proxy group—particularly where the proxy group is composed entirely of multi-asset, diversified companies and the pipeline at issue is a single-asset, new-entrant system—placement at or modestly above the upper end of the zone may be appropriate. The 12.50% recommendation represents a modest 55 basis point premium above the highest individual DCF result and is within the range of outcomes approved by FERC in comparable proceedings, as documented in Appendix D.
VI. Placement of Ridgeline Within the Zone of Reasonableness
A. Risk Factors Supporting Above-Median Placement
The determination of where within the zone of reasonableness to place the ROE for a specific pipeline requires a careful assessment of the company's risk profile relative to the proxy group. As discussed below, five significant risk factors—each individually recognized by FERC in prior proceedings—support placing Ridgeline in the upper portion of the zone.
1. Single-Asset Risk
Ridgeline operates a single 187-mile, 24-inch-diameter 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 includes three compressor stations (Wetzel, Mannington, and Waynesburg) with an aggregate compression capacity of 45,000 horsepower and a certificated design capacity of 1.2 Bcf/d (1,200,000 Dth/d).
This single-asset configuration stands in stark contrast to the proxy group members, all of which operate multi-asset portfolio systems spanning multiple basins and pipeline corridors. Crestline Pipeline Partners, for example, operates approximately 4,200 miles of pipeline across five states. Meridian Interstate Gas Holdings operates approximately 7,800 miles of pipeline with multiple interconnections and delivery points. Even Summit Ridge Pipeline Company, the smallest multi-asset system in the proxy group, operates two interstate pipeline systems totaling approximately 920 miles.
Ridgeline's concentration in a single pipeline asset exposes its equity holders to risks that are substantially mitigated in diversified portfolio systems. An operational disruption—whether from equipment failure, force majeure, or regulatory action—on any portion of Ridgeline's 187-mile system could reduce or eliminate the entire system's revenue-generating capacity. A comparable disruption affecting one segment of a multi-asset system would be partially offset by continued operations on the remaining assets. The limited operational redundancy of three compressor stations on a single pipeline further amplifies this risk.
FERC has consistently recognized that single-asset pipelines warrant an above-median ROE placement to compensate for the lack of diversification. The precedent summarized in Appendix D demonstrates that the Commission has approved ROE premiums of 50 to 200 basis points above the proxy group median for single-asset or geographically concentrated systems.
2. New-Entrant / Start-Up Risk
Ridgeline's pipeline was placed in service on October 1, 2021, giving the system less than four years of operating history as of the date of this analysis. The pipeline was constructed at an original cost of $587.2 million, but the system has not yet established a track record of consistent throughput at or near its design capacity.
Current throughput is approximately 680 MMcf/d, representing only 56.67% of the system's 1.2 Bcf/d design capacity. This utilization rate—while not atypical for a pipeline in the early years of commercial operation—substantiates the risk that Ridgeline may fail to achieve full subscription within the timeframe contemplated by its financial projections. The pipeline's shippers consist of eight firm capacity holders under contracts ranging from five to fifteen years, but no single shipper holds more than 175 MMcf/d of firm capacity, and several contracts contain termination provisions that could further reduce committed throughput if triggered by rate increases or competitive alternatives.
New-entrant pipelines face a qualitatively different set of risks than established systems. They have no historical revenue track record on which investors or regulators can rely; they face the risk that initial demand projections may prove optimistic; and they are particularly vulnerable to market shifts during the critical early years of operation before contracts mature and throughput stabilizes. The significance of this risk factor is compounded in the present case by the fact that Ridgeline's initial tariff rate has not yet been approved—meaning that the rate at which the pipeline will ultimately recover its costs remains uncertain.
3. Regulatory Risk
Ridgeline has never had a FERC-approved tariff rate. The current proceeding—FERC Docket Nos. RP22-847-000 and RP22-847-001—represents the Company's initial tariff rate filing. This distinguishes Ridgeline from every member of the proxy group, each of which operates under one or more established FERC-approved tariff rates with decades of regulatory history.
The regulatory risk facing Ridgeline is heightened by the prolonged dormancy of the current proceeding. The fourteen-item Deficiency Letter issued on January 19, 2023, identified significant issues with the original filing, including the ROE support addressed by this memorandum, the load factor assumptions, the interconnection cost allocation, and the depreciation methodology, among others. The proceeding has been dormant since September 8, 2023, and substantial uncertainty remains regarding the Commission's ultimate determination on multiple contested issues.
Furthermore, the ongoing dispute regarding interconnection cost allocation introduces additional uncertainty into Ridgeline's rate base. The total interconnection costs of $22.3 million are the subject of a material disagreement: Ridgeline proposes allocating $7.6 million to its own rate base and $14.7 million to ATPC, while ATPC advocates a 50/50 split of $11.15 million each. The resolution of this dispute will directly affect Ridgeline's rate base and, consequently, its cost of service and tariff rate.
The shift from a 100% to a 75% load factor in billing determinants—while not directly an ROE issue—further compounds regulatory risk by materially increasing the per-unit recourse rate. The higher per-unit rate may affect shipper willingness to contract for firm capacity, potentially creating a negative feedback loop in which a higher rate leads to lower utilization, which in turn increases the per-unit rate under future rate designs.
4. Leverage and Financial Risk
The financial risk of Ridgeline's equity holders is significantly elevated by the Company's actual capital structure, which is far more leveraged than the 55% equity / 45% debt regulatory capital structure proposed for ratemaking purposes.
The total debt on the Ridgeline system consists of $400 million in term loan borrowings (under a credit agreement with Pinnacle National Bank, N.A. as administrative agent, with Granite Trust Company and Lakeshore Capital Bank as co-syndication agents) and $150 million in 7.875% Second Lien Senior Secured Notes (privately placed with Harborview Capital Management LLC and Sentinel Ridge Fund LP), for total debt of $550 million against an original construction cost of $587.2 million. The outstanding balance on the term loan as of December 31, 2024 (projected) is approximately $362.8 million, reflecting scheduled amortization, but total debt (including the second lien notes) remains at approximately $512.8 million.
DEH's equity contribution to the Ridgeline system was only $37.2 million ($587.2 million original cost minus $400 million term loan minus $150 million second lien notes), representing approximately 6.3% of the total construction cost. While the proposed regulatory capital structure assumes 55% equity and 45% debt—an assumption that is appropriate for ratemaking purposes to ensure that the resulting rate reflects a reasonable cost of capital—the actual book capital structure is dramatically more leveraged. This disparity between the regulatory and actual capital structures means that the equity holders bear a disproportionate share of financial risk.
Moreover, the term loan facility has a maturity date of October 1, 2028, creating refinancing risk. If FERC has not approved a tariff rate prior to the maturity date—a plausible scenario given the pace of the current proceeding—Ridgeline may face difficulty refinancing its credit facility on favorable terms in the absence of regulatory certainty regarding its revenue stream.
5. Geographic Concentration and Market Risk
Ridgeline's entire system is located within the Appalachian Basin, spanning portions of West Virginia and Pennsylvania. The system's receipt point at the Wetzel County Interconnect and its delivery point at the Waynesburg Compressor Station are both situated within the heart of the Marcellus and Utica shale production region.
While the Appalachian Basin is currently the most prolific natural gas production region in the United States, Ridgeline's complete dependence on production volumes from this single basin exposes it to market risk in the event of production declines, shifts in the competitive landscape, or regulatory changes affecting Marcellus or Utica development. Unlike diversified proxy group members that operate pipeline systems spanning the Gulf Coast, Midcontinent, Rocky Mountain, and Appalachian basins, Ridgeline has no geographic diversification to offset a regional downturn.
This geographic concentration risk is amplified by the system's limited delivery point diversification. Ridgeline's sole primary delivery point is the interconnection with ATPC at the Waynesburg Compressor Station. ATPC is itself a single downstream pipeline system (640 miles, 3.8 Bcf/d capacity) controlled by Tidewater Infrastructure Partners LP. The lack of alternative downstream interconnections means that Ridgeline's throughput is effectively dependent on the continued operation and available capacity of a single downstream system operated by a direct competitor that is also an opposing party in this rate proceeding.
B. Risk Factors Considered but Not Supporting Premium
In the interest of completeness, we have also considered certain factors that may provide partial mitigation of the risks identified above, but which we conclude do not eliminate the need for above-median placement.
Parent Company Support. DEH, Ridgeline's sole member, is a substantial energy company with an estimated enterprise value of approximately $2.8 billion and 2023 consolidated annual revenue of approximately $485 million. DEH's portfolio includes approximately 1,200 miles of midstream pipelines across four states, two cryogenic gas processing plants with aggregate capacity of 400 MMcf/d, and a 250 MW wind energy portfolio currently under development in West Virginia and Virginia. DEH's scale and diversification provide some implicit financial backstop for Ridgeline. However, DEH has not provided an explicit guaranty of Ridgeline's debt obligations, and the structural ring-fencing of the Ridgeline credit facility limits the degree to which parent support can be relied upon as a risk mitigant. Moreover, parent support does not address the operational risks inherent in a single-asset pipeline.
Concentrated Ownership. DEH owns 100% of Ridgeline, and Patricia Dunmore holds a 72% equity interest in DEH. This concentrated ownership structure provides strong alignment of interests between the equity holder and the operating entity, potentially reducing agency costs. However, concentrated ownership also introduces key-person risk, as the strategic direction and financial support of both DEH and Ridgeline are substantially dependent on a single individual.
C. Recommended Placement: Upper Portion of the Zone
Based on the cumulative weight of the five risk factors analyzed above—single-asset concentration, new-entrant start-up risk, regulatory uncertainty, elevated financial leverage, and geographic and market concentration—Ridgeline should be placed in the upper portion of the zone of reasonableness established by the proxy group DCF results.
We recommend an ROE of 12.50%, which falls at approximately the 75th percentile of the proxy group distribution and modestly above the highest individual proxy group DCF result of 11.95%. As noted above, this placement is consistent with FERC precedent recognizing that single-asset, new-entrant pipelines may warrant placement at or above the upper end of the zone derived from a proxy group of diversified, multi-asset companies.
The 12.50% ROE represents a reduction of 150 basis points from the original 14.00% proposal filed in May 2022. This reduction reflects the passage of time and the evolution of market conditions since the original filing. Ridgeline now has more than three years of operating history (compared to approximately one year at the time of the original filing), which provides some, though still limited, operational track record. Additionally, the updated market data incorporated in this analysis reflects the current interest rate environment and equity market conditions, which have shifted since year-end 2021.
At the same time, the 12.50% ROE remains well above the proxy group median of 10.11%, recognizing that Ridgeline's risk profile is demonstrably more elevated than that of any member of the proxy group. The 12.50% ROE is within the range of outcomes approved by FERC in comparable proceedings for new-entrant and single-asset pipeline systems, and it satisfies the Hope/Bluefield standards by providing a return commensurate with the risks borne by Ridgeline's equity holders while remaining at a level that is not unduly burdensome to ratepayers.
VII. Comparison to Opposing Parties' ROE Proposals
A. ATPC's Proposed 10.75% ROE
ATPC, through its counsel William Pratt of Kellner, Royce & Dillard LLP (One PPG Place, Suite 2800, Pittsburgh, PA 15222), filed answering testimony on January 9, 2023, proposing an ROE of 10.75% for Ridgeline. This proposal was based on ATPC's contention that Ridgeline should be treated as an average-risk natural gas pipeline and placed at or near the median of the proxy group.
ATPC's proposed 10.75% falls approximately at the median of the current proxy group range (10.11% median, 10.04% mean) and effectively ignores the company-specific risk factors that distinguish Ridgeline from the average proxy group member. We identify the following specific deficiencies in ATPC's analysis:
(1) Failure to account for single-asset risk. ATPC's own system is a 640-mile, 3.8 Bcf/d diversified interstate pipeline with multiple receipt and delivery points spanning four states. By placing Ridgeline at the median, ATPC's analysis treats Ridgeline's 187-mile single-asset system as though it possesses the same level of diversification as ATPC and the multi-asset proxy group members. This is unsupportable.
(2) Failure to account for start-up risk. Ridgeline's 56.67% utilization rate and lack of an established throughput track record are not acknowledged in ATPC's analysis. ATPC, by contrast, operates at approximately 89% utilization with a well-established shipper base and decades of commercial history.
(3) Failure to account for regulatory uncertainty. Ridgeline has never had a FERC-approved tariff rate. ATPC has been operating under FERC-approved rates for more than twenty years and has successfully completed multiple rate proceedings. The regulatory risk facing Ridgeline as an initial filer is qualitatively different from the risk facing an established pipeline.
(4) Failure to account for actual financial leverage. ATPC did not address the disparity between Ridgeline's regulatory capital structure (55/45) and its actual book capital structure (approximately 93.7% debt to construction cost), which materially increases the financial risk borne by equity holders.
ATPC, as a well-established pipeline subsidiary of Tidewater Infrastructure Partners LP (estimated enterprise value approximately $6.1 billion, controlled by the Alderman family), has a fundamentally different risk profile than Ridgeline. An ROE of 10.75% would undercompensate Ridgeline's equity holders for the risks they bear and would fail to satisfy the Hope/Bluefield standards requiring a return commensurate with returns on investments in enterprises having corresponding risks.
B. MGPC's Proposed 11.25% ROE
MGPC, through its expert witness Dr. Eleanor Vasquez, filed testimony on January 9, 2023, proposing an ROE of 11.25%. MGPC is a coalition of fourteen independent natural gas producers operating in the Appalachian Basin, represented by counsel Rebekah Montague of Whitmore & Sable LLP (1200 New Hampshire Avenue NW, Suite 600, Washington, DC 20036).
Dr. Vasquez's analysis used year-end 2022 market data, which was more current than the original filing's year-end 2021 data but is now itself outdated by nearly two years. Dr. Vasquez's proxy group analysis placed Ridgeline slightly above the median of her proxy group, acknowledging some incremental risk attributable to Ridgeline's single-asset status and new-entrant position. The 11.25% ROE reflects this modest upward adjustment from the median.
While Dr. Vasquez's analysis is more nuanced and analytically sound than ATPC's position, we submit that the 11.25% ROE does not adequately compensate Ridgeline for two critical risk factors:
(1) Single-asset concentration premium. The 11.25% ROE reflects only a modest premium above the proxy group median for single-asset risk. FERC precedent in comparable proceedings has supported single-asset premiums of 100 to 200 basis points above the median, rather than the approximately 75 to 100 basis point premium implied by Dr. Vasquez's recommendation.
(2) Financial leverage disparity. Dr. Vasquez's analysis did not address the significant gap between Ridgeline's regulatory capital structure (55% equity / 45% debt) and its actual book capital structure (approximately 6.3% equity / 93.7% debt at construction). This disparity means that the equity holders bear substantially more financial risk than the regulatory capital structure suggests, and the ROE should compensate for this elevated risk.
The gap between MGPC's proposed 11.25% and Ridgeline's revised recommendation of 12.50% is 125 basis points. This difference, while material, is within the range of outcomes that the Commission has resolved through litigation or settlement in comparable pipeline rate proceedings. As discussed in Section X, a settlement ROE in the range of 11.50% to 12.25% may be achievable, though this outcome must be considered in the context of the broader settlement negotiations encompassing load factor and interconnection cost allocation.
C. Summary Comparison Table
The following table summarizes the ROE positions of each party and the resulting cost of service and rate implications:
It is important to recognize that the differences in proposed rates across the parties are not driven by ROE alone. The load factor assumption is a significant independent driver. At a 100% load factor, annual billing determinants are 438,000,000 Dth; at 85%, they are 372,300,000 Dth; and at 75%, they are 328,500,000 Dth. The shift from 100% to 75% load factor increases the per-unit rate by approximately one-third, holding the cost of service constant. Accordingly, the current settlement gap of approximately $0.058/Dth reflects both ROE and load factor disagreements, with the load factor dispute potentially contributing more to the gap than the ROE dispute.
VIII. Impact on Revised Cost of Service and Proposed Rate
A. Revised Rate of Return Calculation
The revised rate of return is calculated using the unchanged capital structure and cost of debt, combined with the revised 12.50% ROE:
Capital Structure: 55% equity / 45% debt (unchanged from original filing)
Revised ROE: 12.50%
Cost of Debt: 5.25% (unchanged; weighted average of SOFR + 325 bps on term loan and 7.875% on second lien notes)
Revised WACC Calculation:
(0.55 × 12.50%) + (0.45 × 5.25%) = 6.875% + 2.3625% = 9.2375%
Rate Base (unchanged): $612.40 million
• Net Plant in Service: $563.71M
• Working Capital: $18.64M
• Less: Accumulated Deferred Income Taxes (ADIT): ($12.45M)
• Other Rate Base Items: $42.50M
Revised Return on Rate Base: $612.40M × 9.2375% = $56.57 million
B. Impact on Total Cost of Service
The revised total cost of service is $103.15 million, composed of the following elements:
Several observations are warranted regarding the revised cost of service:
Depreciation expense remains unchanged at $14.68 million, reflecting straight-line depreciation at an annual rate of 2.5% applied to the $587.2 million original construction cost. The depreciation rate is a separate contested issue in the proceeding and is not affected by the ROE revision.
O&M expense has been updated from $12.44 million to $13.92 million, an increase of $1.48 million, reflecting current operating costs including increased compression fuel costs, maintenance expenses, and integrity management program costs that were not fully reflected in the original filing. This update is responsive to Deficiency Item 7.
A&G expense has been updated from $4.82 million to $5.14 million, an increase of $0.32 million, reflecting current staffing levels and administrative costs.
Income tax allowance has been reduced from $16.00 million to $15.04 million, reflecting the lower ROE. The income tax allowance is calculated by grossing up the pre-tax return at the combined federal and state income tax rate of approximately 26.13% (21.00% federal statutory rate plus 6.50% West Virginia state corporate net income tax rate, on a combined effective basis).
Revenue credits have been reduced from ($16.10 million) to ($6.00 million), a change of $10.10 million. This reduction is the single largest driver of the increase in total cost of service and reflects the elimination of certain non-recurring revenue items and the reclassification of interruptible transportation revenues based on updated throughput forecasts. This update is responsive to Deficiency Items 11 and 12.
It is important to note that while the ROE decreased from 14.00% to 12.50%—reducing the return by approximately $5.05 million—the total cost of service increased from $97.36 million to $103.15 million, an increase of $5.79 million. This counterintuitive result is driven by the updates to O&M expense, A&G expense, and particularly the substantial reduction in revenue credits, which collectively more than offset the reduction in the return on rate base.
C. Impact on Revised Recourse Rate
The revised recourse rate is calculated using the updated cost of service and revised billing determinants:
Design Capacity: 1,200,000 Dth/d
Load Factor: 75% (revised from 100% in original filing; responsive to Deficiency Item 2)
Annual Billing Determinants: 1,200,000 Dth/d × 365 days × 75% = 328,500,000 Dth/yr
(compared to 438,000,000 Dth/yr at 100% load factor in original filing)