PRIVILEGED & CONFIDENTIAL ATTORNEY-CLIENT PRIVILEGE / ATTORNEY WORK PRODUCT DOCTRINE
MEMORANDUM
FROM: George Trujillo, Responsible Partner, Energy & Infrastructure, Calderwood & Harkness LLP Brett Callahan, Lead Associate, Energy & Infrastructure, Calderwood & Harkness LLP
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
DATE: October 18, 2024
RE: Revised Cost-of-Service Model and Rate Derivation — Ridgeline Midstream Services LLC, FERC Docket Nos. RP22-847-000 and RP22-847-001
C&H MATTER NO.: 1016-00005
This memorandum constitutes attorney work product prepared in anticipation of litigation and is protected by the attorney-client privilege and the attorney work product doctrine. It is intended solely for the use of the named recipients. This memorandum and any attachments hereto should not be disclosed to any third party without the prior written consent of Calderwood & Harkness LLP. Disclosure to any third party may constitute a waiver of applicable privileges.
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I. Executive Summary
The purpose of this memorandum is to present Calderwood & Harkness LLP's ("C&H") independent analysis and comprehensive review of the revised cost-of-service model and rate derivation prepared by Braswell Energy Consulting Group LLC ("Braswell" or "BEC"), Engagement No. BEC-2023-0041, under the direction of Dr. Raymond Braswell, former Senior Economist with the Federal Energy Regulatory Commission's Office of Energy Market Regulation. Braswell was engaged by Dunmore Energy Holdings Ltd. ("DEH") on April 15, 2023, following the issuance of the FERC Deficiency Letter, to perform a comprehensive tariff redesign for Ridgeline Midstream Services LLC ("Ridgeline" or "RMS"), a wholly owned subsidiary of DEH.
Ridgeline filed its initial application for an initial tariff rate and interconnection authorization on May 12, 2022, in FERC Docket Nos. RP22-847-000 (the rate case proceeding) and RP22-847-001 (the interconnection proceeding). The initial filing proposed a recourse rate of $0.2265/Dth predicated on a total cost of service of $97.36 million, a return on equity of 14.00%, and billing determinants calculated at a 100% load factor. The filing was met with substantial intervenor opposition and, on January 19, 2023, the Commission's Office of Energy Market Regulation issued a Deficiency Letter identifying fourteen specific deficiency items requiring a comprehensive tariff redesign.
Since September 8, 2023, the proceeding has been classified as dormant by the Commission's Office of the Secretary. Administrative Law Judge Clara Whitfield, who has been assigned to the proceeding since its inception, issued an order on March 4, 2024, granting Ridgeline's third motion for an extension of time to respond to the Deficiency Letter, subject to the condition that Ridgeline file quarterly status reports with the presiding ALJ and all parties of record. The current deadline for filing the redesigned tariff, supplemental testimony, and all supporting workpapers is February 21, 2025.
This memorandum presents the revised cost-of-service model as developed by Braswell and independently verified by C&H. The key revised parameters are summarized as follows:
• Revised Return on Equity: 12.50%, reduced from the original proposed ROE of 14.00%, based on an updated discounted Cash Flow ("DCF") proxy group analysis as of Q3 2024.
• Revised Weighted Average Cost of Capital: 9.2375%, reduced from the original WACC of 10.0625%, reflecting the lower ROE applied to the unchanged 55% equity / 45% debt capital structure.
• Revised Total Cost of Service: $103.15 million, increased from the original $97.36 million. Although the lower ROE reduces the return component, the total cost of service has increased due to updated operating costs, materially lower revenue credits, and modified billing determinants.
• Revised Billing Determinants: 328,500,000 Dth/yr, calculated at a 75% load factor, reduced from the original 438,000,000 Dth/yr calculated at a 100% load factor. This change was made to address Deficiency Item 4, which cited insufficient support for the 100% load factor assumption.
• Revised Proposed Recourse Rate: $0.3140/Dth, comprised of a reservation rate of $0.3102/Dth and a usage rate of $0.0038/Dth, compared to the original proposed rate of $0.2265/Dth ($0.2223 reservation + $0.0042 usage).
It is important to note that the higher per-unit recourse rate results primarily from the shift to the 75% load factor billing determinant denominator, even though the ROE has been reduced by 150 basis points. The reduction in billing determinants — from 438,000,000 Dth/yr to 328,500,000 Dth/yr — more than offsets the benefit of the lower return on rate base. In effect, the same pool of fixed costs (and indeed a somewhat larger pool, given the operating cost increases and revenue credit reductions) is being recovered from a smaller volume of throughput, resulting in a materially higher per-unit charge.
With respect to the settlement posture, the parties remain approximately $0.058/Dth apart. Ridgeline's current floor is the revised proposed rate of $0.3140/Dth, while Appalachian Trunk Pipeline Company ("ATPC") and the Mountainside Gas Producers Coalition ("MGPC") have jointly advocated for a rate ceiling of approximately $0.2560/Dth. The analysis presented in Section XIV of this memorandum explores the settlement zone of possible agreement ("ZOPA") and the sensitivity of the rate to various combinations of concessions on ROE and load factor, among other parameters.
II. Background and Procedural Context
A. The Ridgeline Pipeline System
Ridgeline Midstream Services LLC owns and operates the Ridgeline Pipeline System, a 187-mile, 24-inch-diameter high-pressure natural gas transmission pipeline located in the Appalachian Basin. The system originates at the Wetzel County Interconnect in Wetzel County, West Virginia (approximately 39.6120° N, 80.7540° W), and terminates at the Waynesburg Compressor Station in Greene County, Pennsylvania (approximately 39.8965° N, 80.1810° W). The pipeline traverses a north-northeast corridor through the heart of the Marcellus and Utica shale production areas in northern West Virginia and southwestern Pennsylvania.
The system includes three compressor stations: the Wetzel Station (located near the receipt point), the Mannington Station (at approximately system milepost 72), and the Waynesburg Station (located at the delivery point terminal). The aggregate installed compression across the three stations is 45,000 horsepower, consisting of a combination of reciprocating and centrifugal compressor units. Together, these facilities provide the system with a design capacity of 1.2 billion cubic feet per day ("Bcf/d"), equivalent to 1,200,000 dekatherms per day ("Dth/d") at an assumed BTU content of 1,000 BTU per cubic foot.
As of the date of this memorandum, current throughput on the Ridgeline system is approximately 680 million cubic feet per day ("MMcf/d"), representing a utilization rate of approximately 56.67% (680,000 Dth/d ÷ 1,200,000 Dth/d). The system was placed in service on October 1, 2021, following completion of construction at an original construction cost of $587.2 million.
Ridgeline is a limited liability company organized under the laws of the State of Delaware. Its sole member is Dunmore Energy Holdings Ltd. ("DEH"), which holds a 100% membership interest. DEH is in turn controlled by Patricia Dunmore, who holds a 72% equity interest in DEH. Ridgeline's principal office is located at 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301. The company's employer identification number is 87-4231956, and its FERC Code is 960442. Ridgeline holds a FERC Gas Tariff, Original Volume No. 1, and provides open-access transportation services pursuant to Part 284, Subpart G of the Commission's regulations.
B. Original Filing Parameters (May 12, 2022)
On May 12, 2022, Ridgeline filed its initial application with the Federal Energy Regulatory Commission seeking approval of an initial tariff rate for firm and interruptible transportation service and authorization for the construction and operation of interconnection facilities at the Wetzel County Interconnect. The filing was docketed as RP22-847-000 (the rate case) and RP22-847-001 (the interconnection authorization).
The original filing proposed the following cost-of-service parameters:
• Total Rate Base: $612.40 million
• Total Cost of Service: $97.36 million
• Proposed Recourse Rate: $0.2265/Dth, consisting of a reservation component of $0.2223/Dth and a usage component of $0.0042/Dth
• Return on Equity: 14.00%
• Capital Structure: 55% equity / 45% debt
• Cost of Debt: 5.25% (weighted average)
• Weighted Average Cost of Capital: 10.0625%, computed as (0.55 × 14.00%) + (0.45 × 5.25%) = 7.70% + 2.3625%
• Billing Determinants: 438,000,000 Dth/yr, calculated as 1,200,000 Dth/d × 365 days × 100% load factor
The filing was supported by the direct testimony of Angela Moretti, VP of Finance & Treasurer; Dr. Natasha Orlov, Director of Rates & Regulatory; and two outside witnesses retained by DEH. The filing included Ridgeline's FERC Form 2, audited financial statements prepared by Ashford & McBride LLP, and an appraisal of the pipeline system performed by Ridgepoint Appraisal & Valuation Inc.
C. FERC Deficiency Letter and Tariff Redesign
On January 19, 2023, the FERC's Office of Energy Market Regulation issued a Deficiency Letter (the "Deficiency Letter") with respect to Ridgeline's initial filing. The Deficiency Letter was prepared under the supervision of Dr. Miriam Okafor, Lead Economic Analyst, and identified fourteen specific deficiency items requiring substantive correction or amplification. The deficiency items collectively required what amounted to a comprehensive redesign of the proposed tariff.
On February 6, 2023, ALJ Whitfield issued an order staying the proceeding pending Ridgeline's response to the Deficiency Letter. On March 15, 2023, Ridgeline filed a partial response addressing eight of the fourteen deficiency items. The remaining six items — including the most significant issues relating to cost of capital support, load factor assumptions, fuel-use tracking, and interruptible transportation rate derivation — required more extensive analysis.
DEH engaged Braswell Energy Consulting Group LLC on April 15, 2023, pursuant to Engagement No. BEC-2023-0041, to perform the comprehensive tariff redesign. Dr. Raymond Braswell, the firm's founder and principal, personally leads the engagement. Dr. Braswell previously served as a Senior Economist at FERC for nineteen years and has extensive experience with natural gas pipeline cost-of-service proceedings.
Since the filing of the partial response, Ridgeline has obtained three extensions of time to complete its response. The proceeding's status was changed to "dormant" on September 8, 2023. The current filing deadline of February 21, 2025, was established by ALJ Whitfield's order of March 4, 2024, which granted Ridgeline's third motion for extension subject to the condition that Ridgeline file quarterly status reports. The first quarterly status report was filed on June 15, 2024; the second was filed on September 14, 2024; and the third is due December 13, 2024.
D. Intervenor and Counterparty Positions
The proceeding involves several active intervenors and counterparties whose positions are directly relevant to the revised cost-of-service model and rate derivation:
Appalachian Trunk Pipeline Company ("ATPC"). ATPC is represented by Kellner, Royce & Dillard LLP, with William Pratt serving as lead counsel. ATPC is the interconnecting pipeline at the Wetzel County Interconnect and is a direct counterparty in the interconnection authorization proceeding (Docket No. RP22-847-001). ATPC has taken the following substantive positions: (i) a proposed ROE of 10.75%; (ii) a proposed interconnection cost allocation of 50/50 between Ridgeline and ATPC, which would allocate $11.15 million of the total $22.3 million interconnection cost to each party, as compared to Ridgeline's proposed allocation of $7.6 million to Ridgeline and $14.7 million to ATPC; and (iii) opposition to Ridgeline's proposed interconnection configuration and metering station design. ATPC operates a 640-mile pipeline system with an aggregate capacity of 3.8 Bcf/d and is a subsidiary of Tidewater Infrastructure Partners LP, which has an enterprise value of approximately $6.1 billion.
Mountainside Gas Producers Coalition ("MGPC"). MGPC is represented by Whitmore & Sable LLP, with Rebekah Montague serving as lead counsel. MGPC is a coalition of fourteen independent natural gas producers operating in the Marcellus and Utica shale formations who are prospective shippers on the Ridgeline system. MGPC proposes an ROE of 11.25% and a rate ceiling of approximately $0.2560/Dth. MGPC's rate expert, Dr. Eleanor Vasquez, filed answering testimony on January 9, 2023, presenting an alternative cost-of-service analysis supporting MGPC's rate position.
Coalition of Municipal Gas Authorities ("CMGA"). CMGA is represented by Fordham Municipal Law Group PC, with Stephen Greer serving as lead counsel. CMGA generally supports ATPC's position on interconnection cost allocation and has expressed concern about the potential pass-through of increased transportation costs to ratepayers on ATPC's downstream system. CMGA has not filed independent rate testimony.
FERC Trial Staff. The Commission's Trial Staff is an active participant in the proceeding. The Lead Trial Attorney is Jonathan Briggs, and the Lead Economic Analyst is Dr. Miriam Okafor, who also supervised the preparation of the Deficiency Letter. Trial Staff has not yet filed testimony in response to the revised cost-of-service model, as the supplemental filing has not yet been made.
III. Scope of Review and Methodology
Calderwood & Harkness has independently reviewed the complete set of workpapers produced by Braswell Energy Consulting Group in connection with Engagement No. BEC-2023-0041, including the revised cost-of-service model, the updated DCF proxy group analysis (which is the subject of a separate C&H memorandum — DCF Proxy Group Analysis — Updated Q3 2024), the rate design calculations and allocation worksheets, and all supporting documentation and data sources referenced therein. C&H reconstructed the cost-of-service model in its entirety using an independent spreadsheet platform to verify mathematical accuracy, internal consistency, and conformity with applicable FERC regulatory standards.
This memorandum synthesizes the Braswell analysis with C&H's independent legal and regulatory assessment. Its purpose is to present the revised cost-of-service model for client review and discussion prior to the finalization of supplemental testimony and the redesigned tariff filing that must be made on or before February 21, 2025. The memorandum is structured to provide the management team and Board of DEH and Ridgeline with a comprehensive understanding of each component of the revised model, the rationale for the changes from the original filing, and the implications for the pending proceeding and ongoing settlement discussions.
The key methodology changes from the original May 2022 filing that are reflected in the revised cost-of-service model are as follows:
1. Modified Fixed-Variable Rate Methodology. The original filing employed a straight fixed-variable ("SFV") rate design under which all fixed costs were allocated to the reservation component. The revised model employs a modified fixed-variable ("MFV") approach, which shifts certain cost elements between the reservation and usage components. This change was made to address concerns raised in the Deficiency Letter regarding the cost classification methodology and is consistent with prevailing FERC precedent for new pipeline tariffs.
2. 75% Load Factor. The original filing calculated billing determinants using a 100% load factor assumption, which FERC identified as deficient (Deficiency Item 4). The revised model uses a 75% load factor, resulting in billing determinants of 328,500,000 Dth/yr, compared to 438,000,000 Dth/yr under the original assumption. This change is addressed in detail in Section IX.
3. Updated DCF Proxy Group Analysis. The original filing proposed an ROE of 14.00% based on a DCF proxy group analysis using market data through 2021. Deficiency Item 1 identified inadequate support for this proposed ROE. The revised model incorporates an updated DCF proxy group analysis as of Q3 2024, yielding a revised proposed ROE of 12.50%. The detailed DCF analysis is presented in a separate C&H memorandum.
4. Updated Operating Cost Data. The revised model reflects updated operations and maintenance and administrative and general expenses based on current-period cost data, as discussed in Sections VI.B and VI.C.
The applicable regulatory authority for the proceeding includes Sections 4, 5, and 7 of the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717c, 717d, 717f, and the Commission's implementing regulations at 18 C.F.R. Parts 154 (Rate Schedules and Tariffs), 157 (Applications for Certificates of Public Convenience and Necessity), and 284 (Certain Sales and Transportation of Natural Gas Under the Natural Gas Policy Act of 1978 and Related Authorities).
IV. Rate Base — Detailed Derivation
This section presents the detailed derivation of Ridgeline's rate base, the foundational building block of the cost-of-service model. As discussed below, the total rate base of $612.40 million is unchanged from the original May 2022 filing. This reflects a deliberate decision, recommended by Braswell and in which C&H concurs, to maintain the original test-year rate base rather than undertake a recomputation that could trigger procedural complications related to the establishment of a new test year.
A. Gross Plant in Service
The gross plant in service represents the original construction cost of the Ridgeline Pipeline System, which is $587.2 million. This amount is recorded at historical cost on Ridgeline's books and records, as reported on Ridgeline's filed FERC Form 2 for the fiscal year ended March 31, 2022 (the test year). The construction cost encompasses the full spectrum of facilities comprising the 187-mile pipeline system, including the pipeline itself, the three compressor stations (Wetzel, Mannington, and Waynesburg), associated rights-of-way, measurement facilities, and SCADA infrastructure.
No changes to the gross plant in service figure have been made from the original filing. The construction cost of $587.2 million was independently verified by Ridgepoint Appraisal & Valuation Inc. through a detailed cost audit and appraisal performed in connection with the original filing, and the financial records supporting this amount were audited by Ashford & McBride LLP. No party has challenged the gross plant figure in answering testimony, and C&H considers this figure to be well-supported and not subject to material dispute.
B. Accumulated Depreciation
Accumulated depreciation reflects the recovery of the original cost of the pipeline system over its useful life. Ridgeline employs a straight-line depreciation method at a rate of 2.5% per annum, which corresponds to an assumed useful life of 40 years for the pipeline and associated facilities. This depreciation rate is consistent with the rates commonly approved by FERC for natural gas transmission pipelines and is addressed in greater detail in a separate C&H memorandum on Depreciation Rates and Negative Salvage.
The test year for purposes of the rate case is the fiscal year ended March 31, 2022. The Ridgeline Pipeline System was placed in service on October 1, 2021. Accordingly, the in-service period during the test year extends from October 1, 2021, through March 31, 2022 — a period of six months, representing one-half of a full depreciation year.
The annual depreciation expense, based on the 2.5% rate applied to the gross plant of $587.2 million, is $14.68 million. The six-month partial-year depreciation component attributable to the October 2021 through March 2022 period is approximately $7.34 million. In the original filing, however, accumulated depreciation was stated at $23.49 million as of the end of the test year, reflecting the partial-year component plus prior-period adjustments as reported in the filing. Net accumulated depreciation as of the test year remains at $23.49 million, unchanged from the original filing.
C. Net Plant in Service
Net plant in service is calculated as gross plant in service less accumulated depreciation:
$587.20 million − $23.49 million = $563.71 million
This amount is unchanged from the original filing.
D. Working Capital Allowance
Working capital represents the funds that a pipeline must maintain on hand to finance its ongoing operating activities. Under FERC's general approach, the working capital allowance is calculated as one-eighth of the sum of operations and maintenance ("O&M") expenses and administrative and general ("A&G") expenses.
In the original filing, the basic formula calculation yields:
1/8 × ($12.44 million O&M + $4.82 million A&G) = 1/8 × $17.26 million = approximately $2.16 million
However, the working capital allowance as filed was $18.64 million, which is materially higher than the 1/8 formula result. The difference reflects additional working capital components identified in Braswell's detailed workpapers, including the results of a cash working capital study, gas imbalance receivables, and prepaid items properly allocated to working capital under FERC accounting standards.
The revised model retains the working capital allowance at $18.64 million. Braswell's analysis concluded that while a recomputation using the updated O&M ($13.92 million) and A&G ($5.14 million) figures would yield a marginally different result under the 1/8 formula component, maintaining the original test-year working capital figure is appropriate for consistency and avoids the risk of re-opening the test-year issue. The additional working capital components (cash working capital study results, gas imbalances, and prepaid items) have not materially changed from the test-year amounts. C&H concurs with this approach.
E. Accumulated Deferred Income Taxes (ADIT)
Accumulated deferred income taxes ("ADIT") represent the tax timing differences arising from the use of accelerated depreciation methods for tax purposes (Modified Accelerated Cost Recovery System, or "MACRS") while employing straight-line depreciation at 2.5% per annum for book and regulatory purposes. The ADIT balance, which is a negative amount that reduces the rate base, reflects the fact that Ridgeline has claimed larger depreciation deductions for tax purposes than it has recorded as book depreciation, resulting in a deferred tax liability.
The ADIT as of the test year is ($12.45 million). This amount is unchanged from the original filing and is deducted from the rate base in accordance with FERC's normalization requirements.
F. Other Rate Base Items
Other rate base items consist of gas stored underground, prepayments, materials and supplies, and other miscellaneous items properly includable in the rate base under FERC accounting standards. The aggregate amount of other rate base items is $42.50 million, unchanged from the original filing.
G. Total Rate Base Summary
The following table summarizes the components of Ridgeline's total rate base:
The total rate base of $612.40 million is unchanged from the original May 2022 filing. As noted above, this is a deliberate strategic and procedural decision. Braswell recommended, and C&H independently concurs, that maintaining the original test-year rate base avoids triggering the requirement to establish a new test year, which would entail substantial additional filing requirements, extend the proceeding timeline, and create opportunities for intervenors to challenge new rate base components. Importantly, the parties' answering testimony filed in January 2023 did not materially challenge the rate base computation. Any reopening of the rate base would introduce new variables into a proceeding that is already complex, and neither Ridgeline's interests nor the efficient resolution of the case would be served by doing so.
V. Capital Structure and Cost of Capital
A. Capital Structure
The proposed capital structure for cost-of-service purposes is 55% equity and 45% debt. This capital structure is unchanged from the original filing.
The hypothetical capital structure is supported by Ridgeline's actual financing arrangements, which consist of the following:
Senior Secured Credit Facility. Ridgeline maintains a Senior Secured Credit Facility consisting of a $400 million term loan and a $75 million revolving credit facility. The administrative agent for the facility is Pinnacle National Bank, N.A. The lending syndicate comprises Pinnacle National Bank, N.A. (40% participation), Granite Trust Company (30% participation), and Lakeshore Capital Bank (30% participation). The Credit Facility Agreement was executed on September 15, 2021, and the facility matures on October 1, 2028. Interest on the term loan accrues at a rate of SOFR plus 325 basis points. The outstanding balance on the term loan as of December 31, 2024, is $362.8 million, reflecting scheduled principal amortization from the original $400 million draw.
Second Lien Notes. Ridgeline issued $150 million in aggregate principal amount of 7.875% Second Lien Senior Secured Notes due 2030 in a private placement to Harborview Capital Management LLC and Sentinel Ridge Fund LP. The notes were issued on September 22, 2021, and are secured by a second-priority lien on substantially all of Ridgeline's assets, subordinate to the first-priority lien of the Senior Secured Credit Facility.
DEH Equity Contribution. DEH contributed $37.2 million in equity to capitalize Ridgeline, representing the difference between the total construction cost of $587.2 million and the total debt financing of $550 million ($400 million term loan + $150 million second lien notes). This equity contribution, combined with Ridgeline's retained earnings and accumulated equity since inception, forms the equity component of the capital structure.
It bears noting that a discussion of the hypothetical versus actual capital structure is relevant to FERC's evaluation. FERC policy generally permits the use of a hypothetical capital structure for rate-making purposes when the hypothetical structure falls within a zone of reasonableness as measured against comparable FERC-jurisdictional pipelines. The proposed 55% equity / 45% debt structure is well within the range observed for comparable interstate natural gas pipelines, and is in fact modestly conservative relative to Ridgeline's actual leverage (which, given the $550 million of total debt against $587.2 million of total capitalization, implies an actual debt ratio closer to 94% at inception, although this has shifted as equity has accrued). The intervenors have not challenged the proposed capital structure in their answering testimony, and we do not anticipate that it will be a contested issue.
B. Cost of Debt
The weighted average cost of debt used in the cost-of-service model is 5.25%. This figure represents a blended rate calculated from the two debt instruments in Ridgeline's capital structure:
• Term Loan: The term loan bears interest at a floating rate of SOFR plus 325 basis points. For cost-of-service purposes, the applicable SOFR rate is the average rate during the relevant measurement period. Based on the SOFR rates prevailing during the test year and as updated through Q3 2024, the effective interest rate on the term loan has been in the range of approximately 3.5% to 4.5% (inclusive of the 325 basis point spread), depending on the measurement period.
• Second Lien Notes: The second lien notes bear a fixed interest rate of 7.875%.
The weighting of these two tranches reflects their proportional contribution to total debt outstanding. The resulting weighted average cost of debt of 5.25% is unchanged from the original filing. Braswell confirmed in its analysis that this weighted average remains appropriate as of Q3 2024, taking into account the decline in the term loan balance due to scheduled amortization and the relatively stable SOFR environment. C&H independently verified this calculation and concurs.
C. Return on Equity (Revised)
The original proposed return on equity was 14.00%, based on a DCF proxy group analysis using market data through 2021. Deficiency Item 1 of the January 19, 2023 Deficiency Letter identified this proposed ROE as insufficiently supported, noting that the filing lacked an updated proxy group analysis using post-2021 market data and that the proposed level was at the upper end of the range observed in recent FERC proceedings.
The revised proposed ROE is 12.50%, reflecting the results of an updated DCF proxy group analysis as of Q3 2024 prepared by Braswell and independently reviewed by C&H. The detailed analysis supporting this revised ROE is presented in a separate C&H memorandum, DCF Proxy Group Analysis — Updated Q3 2024, and is summarized here.
The key factors contributing to the 150-basis-point reduction from the original 14.00% proposal are as follows:
• Updated dividend yields and growth rates. The proxy group of comparable publicly traded natural gas pipeline companies exhibited lower dividend yields and moderated growth rate expectations as of Q3 2024 compared to the elevated levels observed in the 2021 data set that supported the original filing.
• Moderation in expected growth rates. The natural gas pipeline sector experienced a period of elevated growth expectations in 2020-2021, driven in part by post-pandemic recovery dynamics, commodity price surges, and aggressive expansion plans across the industry. By Q3 2024, growth rate expectations had moderated to levels more consistent with long-term historical norms.
• Recent FERC precedent. Several recent FERC orders in analogous pipeline rate proceedings have indicated downward pressure on allowed pipeline ROEs, with approved ROEs generally falling in the range of 10.5% to 12.5%. The revised proposed ROE of 12.50% is at the upper bound of this recent range, reflecting the incremental risk profile associated with Ridgeline's status as a relatively new, single-asset pipeline system with below-design utilization.
By way of comparison to the intervenor positions: ATPC proposes an ROE of 10.75%, as set forth in ATPC's answering testimony filed on January 9, 2023, by Kellner, Royce & Dillard LLP. MGPC proposes an ROE of 11.25%, as set forth in the testimony of Dr. Eleanor Vasquez, MGPC's rate expert, filed on January 9, 2023, by Whitmore & Sable LLP.
It is C&H's assessment that the revised proposed ROE of 12.50% is defensible as the midpoint of the reasonable range that FERC is likely to find supportable on the record in this proceeding. The reduction from 14.00% to 12.50% represents a meaningful and substantial concession that directly addresses the substance of Deficiency Item 1, while remaining above the intervenor proposals and compensating Ridgeline's equity investors for the risks inherent in the Ridgeline system, including construction-era financing risk, below-design utilization, and the single-asset nature of the enterprise. The gap between Ridgeline's revised ROE of 12.50% and the intervenors' proposals of 10.75% (ATPC) and 11.25% (MGPC) represents one of the key contested issues in the proceeding and will be a central focus of the supplemental testimony and any settlement negotiations.
D. Weighted Average Cost of Capital (Revised)
The weighted average cost of capital ("WACC") is computed by applying the equity and debt weightings to the respective costs of equity and debt:
Original WACC:
(0.55 × 14.00%) + (0.45 × 5.25%) = 7.70% + 2.3625% = 10.0625%
Revised WACC:
(0.55 × 12.50%) + (0.45 × 5.25%) = 6.875% + 2.3625% = 9.2375%
The revised WACC of 9.2375% represents a reduction of approximately 82.5 basis points from the original WACC of 10.0625%. The entirety of this reduction is attributable to the 150-basis-point decrease in the ROE, as neither the capital structure weights nor the cost of debt has changed.
E. Return on Rate Base (Revised)
The return on rate base is the product of the WACC and the total rate base:
Original Return on Rate Base:
$612.40 million × 10.0625% = $61.62 million (rounded)
Revised Return on Rate Base:
$612.40 million × 9.2375% = $56.57 million
The reduction in the return on rate base is $5.05 million, attributable entirely to the 150-basis-point reduction in the proposed ROE. This is a significant dollar reduction that represents a meaningful concession in the overall cost-of-service model.
VI. Operating Expenses — Detailed Line Items
A. Depreciation Expense
As discussed in Section IV.B above, Ridgeline employs a straight-line depreciation method at an annual rate of 2.5%, applied to the gross plant in service of $587.2 million. The resulting annual depreciation expense is:
$587.2 million × 2.5% = $14.68 million
This amount is unchanged from the original filing and is treated as a fixed cost in the modified fixed-variable rate design methodology. The depreciation rate and methodology are addressed in detail in a separate C&H memorandum on Depreciation Rates and Negative Salvage, which analyzes the appropriateness of the 2.5% rate, the treatment of negative salvage value, and comparisons to depreciation rates approved for comparable FERC-jurisdictional pipelines.
B. Operations and Maintenance (O&M) Expense (Revised)
The original test-year O&M expense was $12.44 million, as reported on Ridgeline's filed FERC Form 2 for the test year ended March 31, 2022. The revised O&M expense is $13.92 million, representing an increase of $1.48 million, or 11.9%, from the original test-year figure.
The increase in O&M expense is driven by the following factors:
• Higher compressor station maintenance costs. The three compressor stations (Wetzel, Mannington, and Waynesburg) have experienced higher maintenance costs than originally projected due to extended operating hours needed to move the current throughput of approximately 680 MMcf/d through the system. While the system is operating below its design capacity, the compression requirements at lower throughput levels have resulted in operating patterns that differ from the original design assumptions, leading to increased wear on certain compressor components and more frequent maintenance intervals.
• Increased pipeline integrity testing and in-line inspection costs. Federal pipeline safety regulations and Ridgeline's integrity management program require periodic in-line inspection ("smart pig") runs and other integrity assessments. The costs of these activities have increased since the test year due to both the natural progression of the inspection schedule and rising costs for third-party inspection services.
• Higher labor costs for field operations personnel. Competitive labor market conditions in the Appalachian Basin have resulted in wage and salary increases for field operations personnel, including pipeline technicians, compressor station operators, and measurement technicians.
• Updated chemical treatment and corrosion prevention costs. The costs of chemicals used for pipeline corrosion prevention, including cathodic protection and internal pipeline treatment programs, have increased with commodity input prices.
Braswell's workpapers include detailed cross-references for each line item within the O&M expense category, with supporting documentation from Ridgeline's accounting records and third-party invoices. C&H has reviewed the updated amounts and found them to be reasonable, supportable, and consistent with cost trends observed across comparable pipeline operations.
C. Administrative and General (A&G) Expense (Revised)
The original test-year A&G expense was $4.82 million, as reported on Ridgeline's filed FERC Form 2 for the test year ended March 31, 2022. The revised A&G expense is $5.14 million, representing an increase of $0.32 million, or 6.6%, from the original test-year figure.
The increase in A&G expense reflects the following factors:
• General inflationary pressures on administrative salaries and benefits. Compensation costs for administrative and support staff have increased in line with general wage inflation.
• Insurance premium increases. Both general liability and property insurance premiums applicable to the Ridgeline system have increased, reflecting broader insurance market dynamics and the insured value of the pipeline assets.
• Regulatory compliance costs. The ongoing FERC proceeding itself has contributed to higher compliance costs, including the costs of preparing regulatory filings, monitoring compliance with FERC reporting requirements, and maintaining the specialized systems necessary for tariff administration.
• SCADA system maintenance and upgrades. Ridgeline's Supervisory Control and Data Acquisition ("SCADA") system, which is essential to the safe and efficient operation of the pipeline, has required software upgrades and maintenance that were not fully reflected in the original test-year expense levels.
With respect to the allocation methodology, A&G expenses are allocated to Ridgeline from DEH's corporate overhead on the basis of an intercompany services agreement. The allocation methodology has been reviewed by Ashford & McBride LLP as part of its audit engagement and was found to be consistent with FERC's affiliate transaction standards. C&H has reviewed the allocation factors and supporting documentation and finds the revised A&G expense to be reasonable and supportable.
D. Taxes Other Than Income
Property and franchise taxes assessed against the Ridgeline Pipeline System total $3.80 million. This figure encompasses West Virginia property tax assessments on the pipeline right-of-way and facilities located within the state, as well as Pennsylvania franchise tax assessments on the facilities and operations located in Greene County, Pennsylvania.
This amount is unchanged from the original filing. C&H has reviewed the underlying county assessment records and state filings and confirmed that the tax assessments applicable to the Ridgeline system have remained stable from the test year through the current period.
E. Income Tax Allowance (Revised)
The income tax allowance in the cost-of-service model reflects the income taxes that Ridgeline must collect through its rates to compensate its equity investors for the taxes imposed on the equity return. The applicable tax rates are the federal corporate income tax rate of 21% and the West Virginia state corporate net income tax rate of 6.5%, yielding an effective combined rate of approximately 26.13% on a grossed-up basis.
The original income tax allowance was $16.10 million, based on the original 14.00% ROE. The revised income tax allowance is $15.04 million, based on the revised 12.50% ROE. The reduction of $1.06 million is attributable to the lower taxable equity return resulting from the 150-basis-point ROE decrease.
A discussion of the income tax allowance methodology is warranted given Ridgeline's corporate structure. Ridgeline is organized as a Delaware limited liability company and is treated as a disregarded entity for federal income tax purposes, with its sole member being DEH. Income and losses of Ridgeline flow through to DEH for tax purposes. The income tax allowance is computed under the methodology approved by FERC for pass-through entities where the ultimate owner is subject to income tax.
An additional consideration relates to DEH's domicile. DEH is a Cayman Islands-domiciled entity. FERC precedent on the availability of an income tax allowance for entities with foreign parent companies has evolved in recent years, and this issue requires careful treatment in the supplemental testimony. The full analysis of this issue is presented in a separate C&H memorandum, Income Tax Allowance Calculation, which addresses the applicable FERC policy statements and case law, the treatment of foreign-parented entities, and the specific factual circumstances of DEH's tax position.
VII. Revenue Credits
A. Original Revenue Credits
The original filing included revenue credits of ($16.10 million). Revenue credits represent non-firm and miscellaneous revenue streams that reduce the cost of service to be recovered from firm transportation shippers. The original revenue credit figure included projected interruptible transportation revenues, penalty revenues, and miscellaneous service revenues.
B. Revised Revenue Credits
The revised revenue credits are ($6.00 million), representing a reduction of $10.10 million from the original filing. This is a significant change that has a material impact on the total cost of service.
The reduction in revenue credits is driven by the following factors:
• Lower projected interruptible transportation revenues. The original filing projected a relatively robust level of interruptible transportation ("IT") revenues based on assumptions regarding available interruptible capacity and shipper demand. However, Ridgeline's current throughput of approximately 680 MMcf/d represents only 56.67% utilization of the system's 1,200,000 Dth/d design capacity. While this might suggest substantial available capacity for interruptible service, the market demand for interruptible transportation on the Ridgeline system has proven to be lower than originally projected, reflecting competitive dynamics in the Appalachian Basin and the availability of alternative transportation paths. Updated demand forecasts prepared by Braswell indicate materially lower IT revenue projections over the relevant period.
• Updated penalty revenue projections. Penalty revenue projections have been revised downward to reflect the actual penalty revenue experience since the system's October 2021 in-service date.
• Removal of speculative revenue credit items. Braswell's review of the original filing identified certain revenue credit items that were, in Braswell's professional judgment, speculative in nature and not supportable under FERC standards for revenue crediting. Specifically, certain contingent revenue streams that had been included in the original credits were removed because they did not meet the threshold of reasonable certainty required for inclusion as revenue credits in a cost-of-service filing. C&H concurs with this assessment.
This reduction in revenue credits is one of the most significant drivers of the increase in the net cost of service from $97.36 million to $103.15 million. As discussed in Section VIII below, absent the revenue credit reduction, the revised total cost of service would have been approximately $93.05 million — actually lower than the original filing.
It should also be noted that the revised tariff includes a new penalty revenue crediting mechanism that addresses Deficiency Item 10 of the Deficiency Letter. Under this mechanism, penalty revenues collected by Ridgeline are explicitly credited to firm shippers on an annual basis. The quantum of projected penalty revenue credits under this new mechanism is reflected in the $6.00 million revised revenue credit figure.
VIII. Total Cost of Service — Summary and Reconciliation
A. Revised Cost-of-Service Summary Table
The following table presents a side-by-side comparison of the original and revised cost-of-service components:
B. Reconciliation of Change
The net increase of $5.79 million in the total cost of service is the product of offsetting changes in the various cost-of-service components. The reconciliation is as follows:
Decreases (favorable to shippers):
• Lower return on rate base: ($5.05 million), attributable to the 150-basis-point reduction in ROE from 14.00% to 12.50%.
• Lower income tax allowance: ($1.06 million), attributable to the lower taxable equity return.
• Total decreases: ($6.11 million)
Increases (unfavorable to shippers):
• Higher O&M expense: +$1.48 million, reflecting current-period cost increases as discussed in Section VI.B.
• Higher A&G expense: +$0.32 million, reflecting current-period cost increases as discussed in Section VI.C.
• Reduced revenue credits: +$10.10 million (net impact on COS), reflecting the reduction in projected interruptible and other revenues as discussed in Section VII.B.
• Total increases: +$11.90 million
Net change: +$11.90 million − $6.11 million = +$5.79 million
The dominant driver of the net increase is the $10.10 million reduction in revenue credits. This single line item accounts for more than the entirety of the net COS increase. Absent the revenue credit reduction — that is, if revenue credits had remained at ($16.10 million) — the revised total cost of service would have been approximately $93.05 million ($103.15 million − $10.10 million), which is actually $4.31 million lower than the original COS of $97.36 million. In other words, the ROE concession, combined with the unchanged rate base, would have produced a lower total cost of service were it not for the revenue credit adjustment and the operating cost increases.
This observation is important for both the supplemental testimony strategy and settlement discussions. Ridgeline will need to address the revenue credit reduction proactively in its supplemental testimony, as it is virtually certain to be a focal point for intervenor challenge. Intervenors may argue that the original revenue credit level was appropriate, or that the revised level is too conservative, and may seek to restore some or all of the $10.10 million reduction.
IX. Billing Determinants — Load Factor Analysis
A. Original Billing Determinants
The original filing calculated billing determinants based on the full design capacity of the Ridgeline Pipeline System and a 100% load factor assumption:
• Design capacity: 1,200,000 Dth/d (equivalent to 1.2 Bcf/d at 1,000 BTU/cf)
• Load factor: 100%
• Billing determinants: 1,200,000 Dth/d × 365 days × 100% = 438,000,000 Dth/yr
FERC Deficiency Item 4 specifically cited the 100% load factor assumption as insufficiently supported. The Deficiency Letter stated that the filing lacked adequate market analysis and shipper commitment data to justify the assumption that the pipeline's full design capacity would be subscribed on a firm basis for the entirety of each year.
B. Revised Billing Determinants
The revised cost-of-service model employs a 75% load factor, yielding billing determinants of:
1,200,000 Dth/d × 365 days × 75% = 328,500,000 Dth/yr
This represents a reduction of 109,500,000 Dth/yr, or 25%, from the original billing determinants.
The rationale for the 75% load factor is as follows:
• Current utilization. The system's current throughput of approximately 680 MMcf/d represents only 56.67% utilization. While this level reflects the system's ramp-up phase and the absence of certain interconnection facilities that remain under construction, it underscores the impracticality of assuming 100% subscription.
• Deficiency Item 4 response. The 100% load factor assumption was identified as a deficiency specifically because it presupposes that no capacity would go unsubscribed at any point during the year. This is an unrealistic assumption for a new pipeline system that is still in the process of building its subscription base and has not yet completed the interconnection facilities necessary to receive gas from all prospective supply sources.
• FERC benchmark. A 75% load factor is a recognized benchmark at FERC and is within the range that the Commission has approved for comparable new-build pipeline systems. It reflects the expectation that, over the levelized cost recovery period, a portion of the system's design capacity will remain unsubscribed or will not be utilized on a firm, year-round basis.
• Market support. Braswell's analysis of market projections, existing shipper contracts, precedent agreements, and planned interconnection volumes supports a realistic throughput scenario that approaches, but does not exceed, 75% of design capacity on an annualized basis over the relevant recovery period. The analysis considered the production growth trajectories for the Marcellus and Utica formations in the pipeline's service area, the competitive transportation alternatives available to prospective shippers, and the expected timeline for completion of the Wetzel County Interconnect.
The revised billing determinants of 328,500,000 Dth/yr represent a 25% decrease from the original filing. This reduction has a profound impact on the per-unit rate, as the fixed costs in the cost-of-service model are spread over a smaller volume denominator.
Intervenor positions on load factor. ATPC, MGPC, and CMGA all advocate for a load factor of 85% or higher. An 85% load factor would yield billing determinants of:
1,200,000 Dth/d × 365 days × 85% = 372,300,000 Dth/yr
At an 85% load factor with the revised COS of $103.15 million, the resulting recourse rate would be approximately $0.2771/Dth ($103.15 million ÷ 372,300,000 Dth). Notably, this rate would still exceed the intervenors' stated rate ceiling of $0.2560/Dth, meaning that even if the intervenors prevailed on the load factor issue, they would not achieve their target rate without additional concessions on other parameters (such as ROE).
C. Sensitivity Analysis — Load Factor Impact on Unit Rate