MEMORANDUM

MEMORANDUM
PRIVILEGED AND CONFIDENTIAL — ATTORNEY WORK PRODUCT
TO: Patricia Dunmore, Founder & Chairperson, Dunmore Energy Holdings Ltd. James K. Winfield, CEO & President, Ridgeline Midstream Services LLC Angela Moretti, VP, Finance & Treasurer, Ridgeline Midstream Services LLC
FROM: George Trujillo, Responsible Partner, Energy & Infrastructure, Calderwood & Harkness LLP Brett Callahan, Lead Associate, Energy & Infrastructure, Calderwood & Harkness LLP
DATE: October 28, 2024
RE: Depreciation Rates and Negative Salvage — Ridgeline Pipeline System; 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 memorialize the analytical basis supporting the 2.5% annual straight-line depreciation rate proposed for the Ridgeline Pipeline System in both the original May 12, 2022 filing and the ongoing tariff redesign, and to address negative salvage considerations that bear on the depreciation component of the cost of service. This memorandum is intended to serve as a comprehensive internal reference document for the Ridgeline management team and outside counsel as the parties prepare for the February 21, 2025 supplemental filing deadline.
The Ridgeline Pipeline System — a 187-mile, 24-inch-diameter high-pressure natural gas pipeline extending from the Wetzel County Interconnect in Wetzel County, West Virginia, to the Waynesburg Compressor Station in Greene County, Pennsylvania — was placed in service on October 1, 2021, at an original construction cost of $587.2 million. The system was designed and constructed to serve the rapidly growing Marcellus and Utica shale production basins and provides critical takeaway capacity for a significant number of upstream producers in the Appalachian region.
The proposed 2.5% straight-line depreciation rate implies a 40-year depreciable life, which is consistent with longstanding FERC depreciation policy for interstate natural gas transmission pipeline facilities. The 40-year life is supported by engineering and metallurgical analysis, industry comparables, the absence of near-term obsolescence risk, and the expectation of continued strong demand for natural gas transportation in the Appalachian Basin over the multi-decade planning horizon.
The resulting annual depreciation expense is $14.68 million ($587.2 million × 2.5%), which constitutes a component of both the original cost of service ($97.36 million) and the revised cost of service ($103.15 million) in the tariff redesign. The depreciation expense figure remains unchanged between the two cost-of-service calculations because neither the depreciation rate nor the gross plant in service figure has changed. As a cost-of-service component, the $14.68 million annual depreciation expense represents the second-largest single expense item after the return on rate base, and accordingly its proper calculation is foundational to the overall integrity of the rate filing.
This memorandum also addresses the concept and quantification of negative salvage — the estimated net cost of retirement, removal, and site restoration at end of asset life. Based on the analysis performed by Ridgepoint Appraisal & Valuation Inc. of Houston, Texas, the estimated negative salvage for the Ridgeline Pipeline System has a midpoint of approximately $48 million, representing approximately 8.2% of original cost. We recommend, for the reasons set forth herein, inclusion of a negative salvage accrual component in the redesigned tariff as a separately stated cost-of-service line item, consistent with FERC precedent. However, as a strategic matter, we further recommend deferring the actual inclusion of this accrual in the current filing to avoid widening the rate gap with intervenors during active settlement negotiations.
It is worth noting that the FERC Deficiency Letter of January 19, 2023, did not specifically identify depreciation as one of the 14 enumerated deficiency items. Moreover, no intervenor — including the Appalachian Transmission Pipeline Company ("ATPC"), the Mountainside Gas Producers Coalition ("MGPC"), or the Clearwater Municipal Gas Authority ("CMGA") — has challenged the 2.5% depreciation rate in testimony filed to date. Nonetheless, the depreciation rate is a foundational element of the cost-of-service computation that underpins the revised recourse rate of $0.3140/Dth and must be capable of withstanding scrutiny from intervenors, FERC Trial Staff, and the presiding Administrative Law Judge should the matter proceed to hearing.
II. Background
A. The Ridgeline Pipeline System
Ridgeline Midstream Services LLC ("Ridgeline" or the "Company") is a Delaware limited liability company organized on March 14, 2019, for the purpose of developing, constructing, owning, and operating the Ridgeline Pipeline System. Ridgeline's sole member is Dunmore Energy Holdings Ltd. ("DEH"), a Cayman Islands exempted limited company registered with the Cayman Islands Registry under Registration No. CR-381204. DEH is the controlling entity of a broader portfolio of energy infrastructure assets and is chaired by Patricia Dunmore, who serves as Founder and Chairperson of the DEH board.
Ridgeline's employer identification number is 87-4231956, and the Company is registered with the Federal Energy Regulatory Commission ("FERC" or the "Commission") under FERC Code 960442. The Company's principal office is located at 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301. Ridgeline's registered agent in the State of Delaware is Capitol Filings Inc., located at 1209 Orange Street, Wilmington, Delaware 19801.
The Ridgeline Pipeline System (the "System") consists of approximately 187 miles of 24-inch-diameter, high-pressure, carbon steel natural gas transmission pipeline. The System's receipt point is located at the Wetzel County Interconnect in Wetzel County, West Virginia, at approximate coordinates 39.6120° N, 80.7540° W, where the pipeline interconnects with upstream gathering facilities. The System's primary delivery point is the Waynesburg Compressor Station in Greene County, Pennsylvania, at approximate coordinates 39.8965° N, 80.1810° W, where the pipeline connects to downstream interstate and intrastate pipeline systems for further transportation and distribution.
The System includes three compressor stations providing the motive force necessary to maintain throughput at designed pressures across the 187-mile pipeline route:
(i) Wetzel Station — located at the receipt point in Wetzel County, West Virginia, providing initial compression for gas entering the system;
(ii) Mannington Station — an intermediate compressor station located along the pipeline route in Marion County, West Virginia, providing mid-pipeline recompression; and
(iii) Waynesburg Station — located at the delivery point in Greene County, Pennsylvania, providing terminal compression and pressure regulation for downstream delivery.
The three compressor stations have an aggregate installed compression capacity of 45,000 horsepower ("HP"), utilizing a combination of gas turbine-driven and electric motor-driven centrifugal compressor units.
The System was designed to a maximum certificated capacity of 1.2 billion cubic feet per day ("Bcf/d"), equivalent to 1,200,000 dekatherms per day ("Dth/d") at an assumed heat content of 1,000 British Thermal Units per cubic foot ("BTU/cf"). Current throughput is approximately 680 million cubic feet per day ("MMcf/d"), representing approximately 56.67% utilization of design capacity. While this utilization level is below design capacity, it reflects the relatively early stage of the System's commercial operations and the ongoing ramp-up of producer commitments in the vicinity of the receipt point. Management projects increasing utilization as additional production wells in the Marcellus and Utica formations are connected to upstream gathering systems that feed the Wetzel County Interconnect.
The System was placed in service on October 1, 2021, following the completion of construction activities that commenced in the second quarter of 2020 and proceeded through hydrostatic testing and commissioning in the third quarter of 2021. The original construction cost of the System, as recorded on Ridgeline's books and records, is $587.2 million, which represents historical cost as audited by the Company's independent public accounting firm, Ashford & McBride LLP. This cost figure encompasses all costs of construction, including materials, labor, rights-of-way, regulatory compliance, environmental mitigation, and allowance for funds used during construction ("AFUDC").
In connection with the original FERC filing, a comprehensive pipeline valuation was performed by Ridgepoint Appraisal & Valuation Inc. of Houston, Texas, which confirmed the reasonableness of the $587.2 million historical cost figure and provided the basis for certain rate base components included in the filing.
B. Financing Context
The construction of the Ridgeline Pipeline System was financed through a combination of senior secured debt, second lien notes, and equity contributions, as follows:
(i) Senior Secured Credit Facility: A $400 million senior secured term loan and a $75 million revolving credit facility, for total first lien capacity of $475 million. The facility is administered by Pinnacle National Bank, N.A., as Administrative Agent, with a lending syndicate consisting of Pinnacle National Bank, N.A. (40% commitment), Granite Trust Company (30% commitment), and Lakeshore Capital Bank (30% commitment). The facility matures on October 1, 2028, and bears interest at SOFR plus 325 basis points. As of December 31, 2024, the outstanding balance under the term loan portion of the facility is approximately $362.8 million, reflecting scheduled amortization payments and voluntary prepayments made from operating cash flow.
(ii) Second Lien Senior Secured Notes: $150 million in aggregate principal amount of 7.875% Second Lien Senior Secured Notes due 2030, privately placed with Harborview Capital Management LLC and Sentinel Ridge Fund LP. These notes are secured by a second-priority lien on substantially all assets of Ridgeline and are subordinated in right of payment and lien priority to the senior secured credit facility.
(iii) Equity Contribution: A $37.2 million equity contribution by DEH, representing the difference between total construction cost ($587.2 million) and total debt financing ($400 million term loan + $150 million second lien notes = $550 million). This equity contribution, together with retained earnings and operating cash flow, constitutes the equity component of Ridgeline's capital structure for ratemaking purposes.
The depreciation rate directly affects annual depreciation expense, which in turn flows through to multiple financial and regulatory metrics of importance to Ridgeline and its stakeholders. On the regulatory side, annual depreciation expense is a direct component of the FERC cost of service and therefore affects the recourse rate charged to shippers. Additionally, accumulated depreciation reduces net plant in service, which is the largest component of rate base; as accumulated depreciation grows over time, rate base declines (all else equal), reducing the return on rate base component of the cost of service. On the financing side, depreciation expense affects covenant compliance calculations under the senior secured credit facility, including the debt service coverage ratio ("DSCR") and the leverage ratio, both of which incorporate EBITDA and, indirectly, the level of depreciation-related cash flow.
The interplay between regulatory depreciation and financial covenant compliance underscores the importance of establishing a depreciation rate that is defensible before FERC while also producing financial results consistent with Ridgeline's obligations under its credit agreements. The 2.5% rate achieves both objectives.
C. Procedural Context
Ridgeline's original FERC application was filed on May 12, 2022, and was assigned Docket Nos. RP22-847-000 (rate filing) and RP22-847-001 (certificate filing). The filing was made pursuant to Sections 4 and 7 of the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717c and 717f, and the Commission's implementing regulations at 18 C.F.R. Parts 154, 157, and 284. The tariff filing is classified as a Part 284, Subpart G open-access transportation tariff, designated as FERC Gas Tariff, Original Volume No. 1.
Following the initial filing, three parties intervened in the proceeding:
•  Appalachian Transmission Pipeline Company ("ATPC"): ATPC, an interstate natural gas transmission pipeline company (FERC Code: 840117), filed a protest on August 15, 2022. ATPC is represented by William Pratt of Kellner, Royce & Dillard LLP. ATPC's protest focused primarily on interconnection cost allocation, specifically the proposed allocation of $14.7 million of the total $22.3 million interconnection facility cost to ATPC, and on certain metering station design specifications at the delivery point.
•  Mountainside Gas Producers Coalition ("MGPC"): MGPC, a coalition of 14 natural gas producers operating in the Marcellus and Utica shale formations, intervened on July 28, 2022. MGPC is represented by Rebekah Montague of Whitmore & Sable LLP and has retained Dr. Eleanor Vasquez as its rate expert witness. MGPC's intervention focused on the proposed return on equity ("ROE") and the load factor used to calculate the recourse rate.
•  Clearwater Municipal Gas Authority ("CMGA"): CMGA, a municipal gas distribution authority, intervened on August 1, 2022. CMGA is represented by Stephen Greer of Fordham Municipal Law Group PC, and its General Manager, Dennis Ott, has been actively involved in the proceeding. CMGA has generally supported ATPC's positions on interconnection cost allocation.
The proceeding is currently in a dormant posture following the issuance of a Deficiency Letter by the Commission on January 19, 2023, which identified 14 specific deficiency items requiring supplemental information and analysis. None of the 14 deficiency items specifically addressed the depreciation rate. On February 6, 2023, Administrative Law Judge Clara Whitfield issued an order staying the procedural schedule pending Ridgeline's response to the Deficiency Letter.
In response to the Deficiency Letter and the associated procedural challenges, Ridgeline engaged Braswell Energy Consulting Group LLC ("Braswell") under engagement number BEC-2023-0041 on April 15, 2023, to assist with the tariff redesign. The engagement is led by Dr. Raymond Braswell, a former FERC economist with extensive experience in natural gas pipeline rate proceedings. The tariff redesign effort has been ongoing since that date and is nearing completion.
The current deadline for filing the redesigned tariff and supplemental testimony is February 21, 2025. Ridgeline is preparing supplemental pre-filed testimony from multiple witnesses, including Angela Moretti (cost-of-service), Dr. Natasha Orlov (rate design), and Thomas Greaves (engineering and operations), among others.
FERC Trial Staff assigned to the proceeding includes Lead Trial Attorney Jonathan Briggs and Lead Economic Analyst Dr. Miriam Okafor. Both individuals have been responsive and professional in pre-hearing communications, and their positions on specific contested issues are discussed further in Section VIII below.
III. Rate Base and Depreciation in the Original Filing
A. Rate Base Summary (As Filed, May 2022; Test Year Ended March 31, 2022)
The original FERC filing included a detailed Statement of Rate Base prepared in accordance with 18 C.F.R. § 154.312 and consistent with the Uniform System of Accounts prescribed by the Commission for natural gas companies. The rate base calculation, using a test year ending March 31, 2022, is summarized below:
Several components of this calculation warrant further explanation:
Gross Plant in Service ($587,200,000). Gross plant in service represents the original construction cost of the Ridgeline Pipeline System, recorded at historical cost on Ridgeline's books in accordance with the Uniform System of Accounts. This figure includes all capitalized costs incurred during the construction period, including pipeline materials, installation labor, rights-of-way acquisition, compressor station equipment, measurement and control facilities, environmental compliance and mitigation, regulatory filing costs, and AFUDC. The figure was audited by Ashford & McBride LLP and confirmed by the independent valuation performed by Ridgepoint Appraisal & Valuation Inc.
Accumulated Depreciation ($23,490,000). Accumulated depreciation as of the test year end (March 31, 2022) reflects the depreciation accrued from the in-service date of October 1, 2021, through the test year end. The depreciation calculation is based on the proposed 2.5% annual straight-line depreciation rate applied to gross plant of $587.2 million. For the partial period from October 1, 2021, through March 31, 2022 (six months), straight-line depreciation at the annual rate of 2.5% yields approximately $7.34 million ($587.2 million × 2.5% × 6/12). The as-filed accumulated depreciation figure of $23.49 million reflects this partial-period calculation together with certain prior-period adjustments as documented in the filing workpapers. The accumulated depreciation figure reduces gross plant to arrive at net plant in service, which is the primary component of rate base.
Working Capital Allowance ($18,640,000). The working capital allowance was computed using the FERC formula method, which calculates working capital as one-eighth (1/8) of total annual operations and maintenance ("O&M") expense plus administrative and general ("A&G") expense. This methodology provides a reasonable estimate of the cash working capital required to fund ongoing pipeline operations between billing cycles.
Accumulated Deferred Income Taxes (ADIT) (($12,450,000)). ADIT represents the accumulated tax timing differences arising from the use of accelerated depreciation methods for federal and state income tax purposes (specifically, the Modified Accelerated Cost Recovery System, or "MACRS") relative to the straight-line depreciation method used for book and ratemaking purposes. ADIT is a credit balance that reduces rate base, reflecting the Commission's policy that ratepayers should receive the benefit of tax deferrals generated by the use of accelerated tax depreciation.
Other Rate Base Items ($42,500,000). Other rate base items include gas stored in the pipeline (linepack), prepaid expenses, and materials and supplies inventories, all of which represent capital invested in the pipeline's operations that is properly includable in rate base under FERC's ratemaking methodology.
B. Annual Depreciation Expense
Annual depreciation expense for the test year is $14,680,000, calculated as follows:
Gross Plant in Service: $587,200,000 × Annual Depreciation Rate: 2.5% = Annual Depreciation Expense: $14,680,000 (full-year basis)
This calculation assumes a full year of depreciation at the proposed rate, consistent with standard FERC practice of annualizing test year expenses to reflect a normalized, representative level of annual costs. The $14.68 million annual depreciation expense is a component of both the original cost of service ($97.36 million) and the revised cost of service ($103.15 million) that forms the basis of the redesigned tariff. The depreciation expense figure remains unchanged between the two cost-of-service calculations because neither the underlying depreciation rate (2.5%) nor the gross plant in service ($587.2 million) has been modified in the tariff redesign.
It bears emphasis that the annual depreciation expense of $14.68 million is the second-largest single expense component of the cost of service, after the return on rate base. In the original filing, the return on rate base was $61.62 million; in the revised cost of service, the return on rate base has been adjusted to $56.57 million (reflecting a revised weighted average cost of capital). In both cases, depreciation expense at $14.68 million represents a substantial and material component of the total cost of service that directly affects the recourse rate. Accordingly, the depreciation rate must be rigorously supported and defensible before the Commission.
IV. FERC Depreciation Policy Framework
A. Governing Regulatory Framework
The Federal Energy Regulatory Commission regulates the depreciation practices of jurisdictional natural gas pipeline companies under the authority of the Natural Gas Act, 15 U.S.C. § 717 et seq., and the Commission's implementing regulations, principally 18 C.F.R. Part 154 (Rate Schedules and Tariffs) and the Uniform System of Accounts ("USoA") prescribed for natural gas companies. The NGA grants FERC broad authority over the rates, terms, and conditions of service for interstate natural gas transportation, including the authority to determine just and reasonable rates under NGA § 4 and to investigate and modify existing rates under NGA § 5.
Depreciation rates for jurisdictional natural gas pipelines are established in connection with cost-of-service rate proceedings. For initial rate filings under NGA § 4, such as the Ridgeline filing at issue, the pipeline proposes a depreciation rate as part of its cost-of-service presentation, and the Commission evaluates the reasonableness of the proposed rate based on the evidence of record. In subsequent rate proceedings, whether initiated by the pipeline under NGA § 4 or by the Commission or third parties under NGA § 5, depreciation rates may be revisited and adjusted based on updated information regarding the pipeline's physical condition, expected useful life, retirement experience, and other relevant factors.
FERC Form 2, the Annual Report of Major Natural Gas Companies, requires jurisdictional pipelines to report depreciation expense by functional account category, consistent with the USoA. The relevant functional account categories for the Ridgeline Pipeline System include, among others, Account 365 (Transmission Plant — Land and Land Rights), Account 366 (Transmission Plant — Rights of Way), Account 367 (Transmission Plant — Mains), Account 368 (Transmission Plant — Compressor Station Equipment), and Account 369 (Transmission Plant — Measuring and Regulating Station Equipment). Each of these account categories may, in principle, carry a different depreciation rate reflecting the unique physical characteristics and expected useful life of the assets within that category. However, for purposes of initial rate filings by new pipelines, it is common practice — and generally accepted by the Commission — to apply a single composite depreciation rate across all transmission plant accounts. Ridgeline's proposed 2.5% rate is applied on a composite basis.
B. FERC Policy on Depreciation Lives for Natural Gas Pipelines
FERC has a well-established body of precedent governing the selection of depreciable lives for interstate natural gas transmission pipeline facilities. The Commission has historically approved depreciable lives ranging from 30 to 50 years for mainline transmission pipeline plant, with the precise life determined based on the specific facts and circumstances of each case. The 40-year useful life implied by Ridgeline's proposed 2.5% annual depreciation rate (1 ÷ 0.025 = 40 years) falls within the central range of lives approved by the Commission and is consistent with the most commonly applied depreciation rate in recent FERC proceedings.
In evaluating the reasonableness of a proposed useful life for natural gas transmission pipeline plant, the Commission considers a range of factors, including:
(a) Physical deterioration: The rate at which the physical components of the pipeline system — primarily the carbon steel pipe itself, but also compressor station equipment, valves, fittings, and measurement equipment — are expected to degrade over time due to corrosion, fatigue, stress, and environmental exposure. Modern cathodic protection systems, protective coatings, and pipeline integrity management programs can significantly extend the physical life of pipeline assets.
(b) Technological obsolescence: The risk that advances in pipeline technology, materials science, or competing energy infrastructure could render the pipeline system technologically obsolete before the end of its physical life. For mainline transmission pipeline, this risk is generally considered low, as the fundamental technology of high-pressure steel pipe has remained largely unchanged for decades.
(c) Regulatory and environmental factors: The potential impact of future regulatory requirements, including more stringent environmental standards, pipeline safety regulations, or land use restrictions, that could shorten the effective useful life of the pipeline or increase the cost of continued operations.
(d) Actual retirement experience of comparable pipeline systems: Data on the actual service lives and retirement patterns of comparable pipeline systems in the same geographic region and serving similar market functions. For new pipelines without their own retirement history, the Commission has accepted reliance on industry-wide retirement data and the experience of comparable systems.
(e) Expected demand patterns for natural gas transportation: The long-term outlook for demand for natural gas transportation services in the relevant market, including consideration of supply trends, downstream market developments, and the potential impact of energy transition policies on future gas demand.
With respect to depreciation studies, FERC's policy has evolved over time. For mature pipeline systems with decades of operating history and retirement experience, the Commission has sometimes ordered comprehensive depreciation studies that incorporate actuarial analysis of actual retirement data to determine remaining useful lives. However, for initial rate filings by newly constructed pipelines — such as the Ridgeline filing — the Commission has generally accepted the use of the straight-line depreciation method at rates within the established range of 2.0% to 3.33% (30 to 50 years) without requiring a full actuarial depreciation study, recognizing that new pipelines lack the retirement history necessary to support such an analysis. In these cases, the Commission evaluates the reasonableness of the proposed rate based on engineering analysis, comparable pipeline data, and the other factors enumerated above. Ridgeline's reliance on these supporting factors, rather than a full depreciation study, is consistent with established Commission practice for new pipeline filings.
C. Straight-Line Method
The straight-line method of depreciation is the standard FERC-approved methodology for computing depreciation on natural gas pipeline plant. Under this method, annual depreciation expense is computed according to the following formula:
Annual Depreciation = (Original Cost − Net Salvage Value) ÷ Estimated Useful Life
Where:
•  Original Cost is the historical cost of the depreciable plant, as recorded on the pipeline's books of account in accordance with the USoA;
•  Net Salvage Value is the estimated gross salvage value (i.e., the expected proceeds from the sale or scrapping of retired plant) less the estimated cost of removal, retirement, and site restoration; and
•  Estimated Useful Life is the expected period in years over which the plant will provide useful service.
If net salvage value is assumed to be zero — that is, if the expected gross salvage value equals the expected cost of removal, or if no specific assumption is made regarding salvage — the depreciation rate simplifies to:
Depreciation Rate = 1 ÷ Estimated Useful Life
For a 40-year useful life: 1 ÷ 40 = 0.025 = 2.5%.
If net salvage is negative — that is, if the estimated cost of removal exceeds the estimated gross salvage value, as is discussed in detail in Section VI below — the depreciation rate should, in principle, be adjusted upward from the baseline rate to accrue for the anticipated net removal costs over the useful life of the asset. The magnitude of the upward adjustment depends on the estimated level of negative salvage, expressed as a percentage of original cost, divided by the useful life.
Ridgeline's current proposal treats net salvage as zero for purposes of the 2.5% depreciation rate. This approach produces a straightforward and easily understood depreciation rate that aligns with industry norms and FERC precedent. The negative salvage issue is addressed separately in Section VI, where we discuss the option of including a distinct negative salvage accrual as a separate line item in the cost of service or, alternatively, deferring that issue to a future rate proceeding.
V. Support for the 2.5% Annual Depreciation Rate (40-Year Life)
A. Engineering and Physical Life Analysis
The Ridgeline Pipeline System consists of approximately 187 miles of 24-inch-diameter, high-pressure carbon steel transmission pipeline, designed and constructed in accordance with the following industry codes and regulatory standards:
•  API 5L: Specification for Line Pipe, published by the American Petroleum Institute, governing the manufacture, testing, and quality control of the steel pipe used in the System;
•  ASME B31.8: Gas Transmission and Distribution Piping Systems, published by the American Society of Mechanical Engineers, establishing engineering requirements for the design, fabrication, installation, inspection, and testing of the pipeline; and
•  49 C.F.R. Part 192: Transportation of Natural and Other Gas by Pipeline — Minimum Federal Safety Standards, promulgated by the Pipeline and Hazardous Materials Safety Administration ("PHMSA") of the U.S. Department of Transportation, governing the safety of pipeline design, construction, operation, and maintenance.
The pipeline was constructed using modern, high-grade carbon steel pipe with a specified minimum yield strength and wall thickness appropriate for the maximum allowable operating pressure ("MAOP") of the System. The pipe is externally coated with fusion-bonded epoxy ("FBE") to resist corrosion and is further protected by a comprehensive cathodic protection system consisting of impressed current and galvanic anode installations along the entire pipeline right-of-way. The cathodic protection system is designed to maintain the pipe-to-soil potential at levels that effectively prevent external corrosion throughout the design life of the pipeline.
From a metallurgical perspective, modern carbon steel pipeline, when properly coated and cathodically protected, has a physical life expectancy that substantially exceeds 40 years. Industry experience and academic research have demonstrated that well-maintained, coated, and cathodically protected steel pipelines can safely operate for 60 to 80 years or more without requiring wholesale replacement of the mainline pipe. The 40-year depreciable life proposed for the Ridgeline System is therefore conservative relative to the expected physical life of the pipeline itself.
The System is equipped with comprehensive inline inspection ("ILI") capabilities, including the ability to accommodate smart pigs for magnetic flux leakage ("MFL") and ultrasonic testing ("UT") inspections. These ILI tools enable Ridgeline to monitor the condition of the pipeline wall in detail, detecting and quantifying metal loss, dents, cracks, and other anomalies. The pipeline integrity management program ("IMP") implemented by Ridgeline includes regular ILI inspections, direct assessment protocols, and risk-based maintenance planning, all of which serve to extend the effective useful life of the pipeline by enabling targeted repair and remediation before anomalies progress to the point of requiring section replacement or early retirement.
The three compressor stations — Wetzel Station, Mannington Station, and Waynesburg Station — have an aggregate installed compression capacity of 45,000 HP and utilize a combination of gas turbine-driven and electric motor-driven centrifugal compressor units. While individual compressor components have replacement cycles that may be shorter than the overall pipeline system life (e.g., gas turbine hot section overhauls at 25,000–50,000 operating hours, bearing and seal replacements at periodic intervals), these component replacements are planned maintenance activities that are funded through O&M expense or incremental capital expenditure budgets. They do not require premature retirement of the compressor station as a whole, much less the overall pipeline system. The compressor station structures, foundations, piping, and ancillary equipment are designed for service lives consistent with or exceeding the 40-year system life.
These engineering and physical life considerations are documented in the direct testimony of Thomas Greaves, Vice President of Engineering and Operations for Ridgeline, filed on December 5, 2022. Mr. Greaves's testimony, based on his 28 years of experience in the design, construction, and operation of natural gas pipeline systems, concludes that the Ridgeline Pipeline System has a minimum expected useful life of 40 years, with significant potential for continued service beyond that horizon. His testimony details the System's design parameters, construction quality assurance program, cathodic protection system performance, integrity management program, and compressor station maintenance planning — all supporting the 40-year depreciable life assumption.
B. Comparable Pipeline Depreciation Rates
A survey of depreciation rates approved by FERC for comparable interstate natural gas transmission pipelines in the Appalachian Basin and other regions confirms that the proposed 2.5% rate (40-year life) is well within the range of rates in current use and is, in fact, the most commonly approved rate for pipeline transmission plant in recent proceedings.
The following table summarizes the depreciation rates used by a selection of comparable FERC-jurisdictional pipelines, drawn from public FERC filings and Form 2 reports:
As the survey demonstrates, comparable pipelines typically utilize depreciation rates ranging from 2.0% to 3.33%, corresponding to depreciable lives of 30 to 50 years. The 2.5% rate (40-year life) is the modal value in this sample and is used by a majority of the comparable systems, including ATPC — the intervenor with the most direct operational comparability to Ridgeline.
It is noteworthy that ATPC itself, as a 640-mile interstate pipeline system with 3.8 Bcf/d capacity and FERC Code 840117, uses a depreciation rate within this range for its own transmission plant, as reported in its FERC Form 2 filings. This fact significantly reduces the likelihood that ATPC would challenge Ridgeline's proposed 2.5% rate, as doing so would be inconsistent with ATPC's own ratemaking treatment of its pipeline assets.
A more detailed benchmarking analysis of comparable pipeline depreciation rates, including a discussion of the specific facts and circumstances underlying each comparable's rate selection, is provided in the companion memorandum on comparable pipeline rate comparison (see Attachment B).
C. Demand and Obsolescence Considerations
The assessment of an appropriate depreciable life for the Ridgeline Pipeline System must also consider the expected demand for the System's transportation services over the planning horizon, as well as the risk of technological or market-driven obsolescence.
Demand outlook. The Ridgeline Pipeline System serves the Marcellus and Utica shale formations, which together constitute the largest natural gas producing region in the United States. According to U.S. Energy Information Administration ("EIA") data and industry forecasts, the Appalachian Basin has accounted for approximately one-third of total U.S. dry natural gas production in recent years, with production from the Marcellus Shale alone exceeding 35 Bcf/d. The continued development of the Marcellus and Utica formations is expected to sustain and increase natural gas production in the region for decades, driven by the enormous scale of the resource base, the favorable economics of Appalachian dry gas production, and the growing demand for natural gas as a fuel for power generation, industrial use, LNG export, and petrochemical feedstock.
The Ridgeline System's current throughput of approximately 680 MMcf/d represents 56.67% utilization of the System's 1.2 Bcf/d design capacity. This substantial headroom for additional throughput indicates that the System is positioned to capture incremental production growth in its service area without requiring significant capacity expansion. The current utilization level, while modest, is not unusual for a pipeline system in its early years of operation, and management expects utilization to increase as additional upstream production is developed and connected to the gathering systems that feed the Wetzel County Interconnect.
The participation of the 14-member Mountainside Gas Producers Coalition in this proceeding — and the Coalition's general support for the Ridgeline interconnection — provides independent market evidence of ongoing producer demand for incremental takeaway capacity from the Appalachian production basins. The producers' willingness to engage in the rate proceeding and to negotiate firm transportation commitments on the Ridgeline System underscores the System's commercial viability over a multi-decade time horizon.
Technological Obsolescence. The risk of technological obsolescence for mainline transmission pipeline is minimal. The fundamental technology of high-pressure steel pipe for natural gas transportation has been in use for over a century, and while incremental improvements in materials, coatings, and construction techniques have occurred over that period, the core technology remains unchanged. Unlike upstream production equipment or downstream end-use technologies, which are subject to relatively rapid technological change, mainline transmission pipeline is a long-lived, stable asset class that has demonstrated multi-decade longevity across numerous operating environments.
The greater technology change risk for the Ridgeline System attaches to compression and measurement equipment, which may require periodic upgrades or replacement to incorporate more efficient, lower-emissions technologies or to comply with evolving regulatory standards. However, as noted in Section V.A above, these component-level replacements are addressed through periodic capital investment funded through O&M and capital expenditure budgets, rather than through premature retirement of the overall system.
Energy Transition and Greenhouse Gas Policy Risks. The ongoing energy transition and the evolving regulatory landscape with respect to greenhouse gas emissions present a potential risk to the long-term value of natural gas infrastructure assets. Notably, FERC Deficiency Item 13 in the January 19, 2023 Deficiency Letter raised the issue of greenhouse gas emission cost recovery, indicating the Commission's awareness of these policy dynamics.
We have carefully considered whether energy transition risks justify a shorter depreciable life for the Ridgeline Pipeline System. Our assessment is that these risks do not, at this time, warrant a departure from the standard 40-year depreciable life. While the trajectory of future energy policy is inherently uncertain, the consensus among industry analysts and energy forecasters is that natural gas will continue to play a significant role in the U.S. energy supply for at least the next three to four decades, serving as a bridge fuel in the transition to lower-carbon energy sources and as a firm, dispatchable complement to intermittent renewable generation. The 40-year depreciable life is consistent with this consensus outlook.
Furthermore, DEH's own strategic positioning provides additional assurance of the parent company's commitment to the long-term operation of the Ridgeline System. DEH currently has a 250 MW wind energy portfolio under development, demonstrating the parent company's forward-looking approach to the energy transition and its diversification across both conventional and renewable energy assets. This diversification strategy does not imply near-term stranding of the Ridgeline gas pipeline asset; rather, it reflects a prudent, balanced approach to portfolio management that recognizes both the enduring value of natural gas infrastructure and the growing importance of renewable energy.
D. No Intervenor Challenge to the Depreciation Rate
A significant factor supporting the continued use of the 2.5% depreciation rate in the redesigned tariff is the absence of any challenge to the rate from intervenors or FERC Trial Staff in the proceeding to date.
Neither ATPC, MGPC, CMGA, nor FERC Trial Staff raised any objection to the 2.5% depreciation rate in their answering testimony filed on January 9, 2023. Dr. Eleanor Vasquez, the rate expert retained by MGPC, focused her testimony exclusively on the proposed return on equity and the load factor assumptions used in rate design; she did not address the depreciation rate, depreciation expense, or the depreciable life of the pipeline system. Similarly, ATPC's protest focused on interconnection cost allocation and metering station design issues, with no mention of depreciation. CMGA's intervention was limited to supporting ATPC's cost allocation positions.
Moreover, the FERC Deficiency Letter of January 19, 2023, did not identify the depreciation rate as one of the 14 enumerated deficiency items. While the Deficiency Letter is not dispositive of the Commission's ultimate position on depreciation — and FERC Staff retains the ability to raise depreciation issues in supplemental testimony following the redesigned tariff filing — the absence of the depreciation rate from the Deficiency Letter strongly suggests that FERC Staff found the proposed 2.5% rate to be facially reasonable and consistent with Commission precedent.
This absence of challenge provides significant, though not conclusive, support for maintaining the 2.5% rate in the redesigned tariff. It indicates that the rate is within the zone of reasonableness recognized by the parties and the Commission, and it reduces the litigation risk associated with the depreciation component of the cost of service.
VI. Negative Salvage Analysis
A. Concept of Negative Salvage
Negative salvage is a concept in regulatory depreciation accounting that arises when the estimated cost of retirement, removal, and site restoration at the end of an asset's useful life exceeds the gross salvage (scrap) value of the retired asset. In other words, negative salvage represents the net cost — over and above any recovery from scrap — of removing a pipeline asset from service, decommissioning associated facilities, restoring the right-of-way and other disturbed areas to their original condition, and conducting any necessary environmental remediation.
For natural gas transmission pipelines, negative salvage is the norm rather than the exception. The costs of pipeline removal or abandonment in place, compressor station decommissioning, right-of-way restoration, and environmental remediation are substantial, and they typically far exceed the scrap value of the steel pipe, equipment, and other materials that can be recovered upon retirement. This is due to several factors:
(a) The cost of excavating and removing buried pipeline, or alternatively of properly abandoning pipeline in place (including purging, capping, and cathodic protection disconnection), is a major expense that increases with pipeline diameter and length;
(b) Right-of-way restoration, including regrading, revegetation, and stabilization of disturbed areas, can be costly, particularly in the mountainous terrain of the Appalachian region through which the Ridgeline System traverses;
(c) Environmental remediation obligations, including the cleanup of any contamination associated with compressor stations (e.g., lubricating oils, coolants, PCBs in older equipment) and the remediation of any soil or groundwater impacts along the pipeline route, can be significant; and
(d) The scrap value of the retired pipeline — primarily the value of the steel pipe itself — while not negligible, is modest relative to the original cost of the pipeline and the costs of removal.
FERC policy permits — and in many cases affirmatively expects — pipelines to accrue for negative salvage through the depreciation component of their cost of service. The rationale underlying this policy is the principle of intergenerational equity: current ratepayers who benefit from the pipeline's transportation services should bear a proportionate share of the future costs of retiring the pipeline at the end of its useful life. If negative salvage costs are not accrued during the pipeline's active service life, the full burden of these costs would fall upon the last generation of ratepayers or upon the pipeline company itself, neither of which would be just and reasonable.
B. Estimated Negative Salvage for the Ridgeline Pipeline System
In connection with the tariff redesign, Ridgeline retained Ridgepoint Appraisal & Valuation Inc. of Houston, Texas — the same firm that performed the original pipeline valuation in connection with the May 2022 FERC filing — to provide an estimated range of net removal costs for the Ridgeline Pipeline System. The Ridgepoint analysis considered multiple scenarios for end-of-life treatment, including full pipeline removal, partial removal and partial abandonment in place, and full abandonment in place, and estimated costs under each scenario based on current market rates for the relevant decommissioning and restoration activities.
The results of the Ridgepoint analysis are summarized as follows:
The estimated gross removal cost range of $45 million to $75 million (in current dollars) encompasses the full spectrum of decommissioning activities, from mainline pipeline removal or abandonment to compressor station decommissioning, right-of-way restoration, and environmental remediation. The width of the range reflects the significant uncertainty inherent in estimating costs that will not be incurred for several decades, as well as the sensitivity of the estimate to assumptions about the method of pipeline retirement (full removal vs. abandonment in place) and future environmental regulatory requirements.
The estimated gross salvage (scrap) value range of $8 million to $12 million reflects the value of the recoverable steel pipe and equipment at current commodity prices for steel scrap. The range accounts for variability in scrap steel prices and the proportion of pipeline assets that would be physically recoverable upon retirement. Note that the low and high ends of the salvage range are inversely ordered relative to the removal cost range in the table above, reflecting the fact that a higher gross salvage value produces a lower net negative salvage.
The resulting estimated negative salvage range is ($33 million) to ($63 million), with a midpoint of approximately ($48 million). Expressed as a percentage of the original construction cost of $587.2 million, the negative salvage midpoint represents approximately 8.2% of original cost. This percentage is consistent with the range of negative salvage estimates approved by FERC in comparable pipeline proceedings, as discussed in Section VI.D below.
Excerpts from the Ridgepoint analysis are provided as Attachment C to this memorandum.
C. Treatment in the Original Filing vs. Redesigned Tariff
In the original May 2022 filing, Ridgeline proposed a 2.5% depreciation rate that did not include a specific negative salvage accrual component. The depreciation rate was calculated simply as 1 ÷ 40 years = 2.5%, with net salvage effectively treated as zero. This approach — while resulting in a depreciation expense that does not accrue for future removal costs — was adopted in the original filing for simplicity and because the negative salvage estimate had not been finalized at the time of filing.
This approach was accepted without challenge from FERC Trial Staff or intervenors during the initial round of testimony filed on January 9, 2023. No party argued that the 2.5% rate was understated by virtue of the omission of a negative salvage component.
For the tariff redesign, Calderwood & Harkness recommends that Ridgeline include an explicit negative salvage accrual as either an adjustment to the depreciation rate or as a separately stated line item in the cost-of-service schedules. This recommendation is based on FERC's general expectation that pipelines accrue for negative salvage during the active service life of their assets, and on the principle that it is preferable to establish the negative salvage accrual in the initial tariff rather than seeking to recover these costs retroactively in a future rate proceeding.
Two options for incorporating the negative salvage accrual are presented for management's consideration:
Option A: Increase the Composite Depreciation Rate. Under this approach, the composite depreciation rate would be increased from 2.5% to approximately 2.7% to incorporate a negative salvage accrual of approximately 0.2 percentage points. The calculation is as follows:
Negative salvage midpoint: $48,000,000 Original cost: $587,200,000 Negative salvage as % of original cost: 8.2% Annual negative salvage accrual: 8.2% ÷ 40 years ≈ 0.2% per year Adjusted depreciation rate: 2.5% + 0.2% ≈ 2.7% Additional annual depreciation expense: $587,200,000 × 0.2% ≈ $1,174,400
This approach would increase the annual depreciation expense from $14,680,000 to approximately $15,854,400, an increase of approximately $1.17 million per year.
Option B: Separately State the Negative Salvage Accrual. Under this approach, the depreciation rate would remain at 2.5% (producing annual depreciation expense of $14,680,000), and the negative salvage accrual of approximately $1.17 million per year would be separately stated as a distinct line item in the cost-of-service schedules. This approach provides greater transparency and makes it easier for FERC Staff, intervenors, and the ALJ to identify and evaluate the negative salvage component independently from the base depreciation expense.
Recommendation. Of the two options, we recommend Option B for transparency and consistency with FERC precedent in recent proceedings. The Commission has increasingly favored the separate statement of negative salvage accruals, as it facilitates review and avoids embedding assumptions about future removal costs within a single, opaque composite depreciation rate.
However, it is important to note that the current draft revised cost of service of $103.15 million does not yet incorporate the negative salvage accrual. Any addition of a negative salvage accrual — whether through Option A or Option B — would increase the revised cost of service and, consequently, increase the revised recourse rate above the current proposed level of $0.3140/Dth. Using Option B as an illustration:
Additional negative salvage accrual: ~$1,174,400/year Impact on recourse rate: $1,174,400 ÷ 328,500,000 Dth/yr ≈ $0.0036/Dth Revised recourse rate with negative salvage: $0.3140 + $0.0036 ≈ $0.3176/Dth
This increase, while modest in absolute terms, would widen the already significant gap between Ridgeline's proposed recourse rate ($0.3140/Dth, which represents the floor of Ridgeline's acceptable range) and the position advocated by ATPC and MGPC (approximately $0.2560/Dth, representing the ceiling of the intervenors' acceptable range). The existing gap of $0.058/Dth has been a central obstacle in settlement negotiations, and any increase in Ridgeline's proposed rate could complicate those negotiations by signaling inflexibility or by providing intervenors with additional grounds for objection.
Strategic Recommendation. For the foregoing strategic reasons, we recommend that Ridgeline defer inclusion of an explicit negative salvage accrual in the initial redesigned tariff filing. Instead, Ridgeline should preserve the right to assert a negative salvage accrual in future NGA § 4 or § 5 rate proceedings, after the initial tariff has been established and the System has accumulated several years of operating history. This approach avoids widening the rate gap during the current proceeding while preserving Ridgeline's ability to recover negative salvage costs in the future, supported by the Ridgepoint analysis and updated engineering and cost data that will be available at that time.
In the supplemental testimony, the cost-of-service witness (Angela Moretti) should acknowledge the existence of negative salvage as a future consideration and note that Ridgeline reserves the right to seek recovery of negative salvage costs in subsequent proceedings. This approach puts intervenors and FERC Staff on notice without actually increasing the proposed rate at this time.
D. FERC Precedent on Negative Salvage
A survey of FERC orders addressing negative salvage for natural gas transmission pipelines confirms that the concept is well-established in Commission practice and that the estimated negative salvage for the Ridgeline System falls within the range of amounts previously approved.
FERC has approved negative salvage accruals ranging from approximately 5% to 15% of original cost in various pipeline rate proceedings. The specific percentage approved in any given case depends on the facts and circumstances, including the size and configuration of the pipeline system, the terrain through which the pipeline traverses, the applicable environmental regulatory requirements, and the method of pipeline retirement (full removal vs. abandonment in place).
The midpoint estimate of 8.2% of original cost for the Ridgeline Pipeline System falls comfortably within this approved range. It is neither so low as to suggest that future removal costs are being underestimated, nor so high as to impose an unreasonable burden on current ratepayers.
The Commission's analytical framework for evaluating negative salvage proposals generally requires the pipeline to present:
(i) Engineering studies or estimates of the expected cost of retirement, removal, and site restoration, prepared by qualified professionals;
(ii) Where available, actuarial data on the actual removal costs experienced by the pipeline or comparable pipeline systems; and
(iii) Comparisons to industry-wide removal cost experience, as reported in FERC Form 2 filings and other publicly available data.
The Ridgepoint analysis satisfies the first requirement, and industry-wide data from FERC Form 2 filings can be marshaled to satisfy the third. The second requirement — actuarial data on actual removal costs — is not applicable to a new pipeline with no retirement history, and the Commission has accepted engineering estimates in lieu of actuarial data in proceedings involving new pipelines.
A summary of relevant FERC precedent on depreciation and negative salvage is provided as Attachment E to this memorandum.
VII. Interaction with Other Cost-of-Service Components
A. Depreciation and Rate Base
The depreciation rate and the resulting accumulated depreciation have a direct and ongoing impact on Ridgeline's rate base. Under FERC ratemaking methodology, rate base is calculated as gross plant in service less accumulated depreciation (yielding net plant in service), plus working capital, less accumulated deferred income taxes, plus other rate base items. As accumulated depreciation increases over time, net plant in service declines, which in turn reduces rate base (all else equal).
As of the test year ended March 31, 2022, accumulated depreciation of $23.49 million reduced gross plant of $587.2 million to net plant in service of $563.71 million. Since the proceeding has been dormant since early 2023, an additional approximately two to three years of depreciation have accrued on Ridgeline's books through the expected filing date in February 2025. At the annual rate of $14.68 million, accumulated depreciation as of December 31, 2024, would be approximately $47 million to $50 million (depending on precise timing and any adjustments), reducing net plant in service to approximately $537 million to $540 million.
However, the rate base for purposes of the FERC filing remains as filed at $612.40 million, using the original test year ended March 31, 2022. Under FERC's ratemaking framework, the test year data in an NGA § 4 filing is generally fixed at the time of filing, and rate base is not automatically updated for subsequent changes in accumulated depreciation unless the Commission or the parties agree to use an updated test year.
This distinction between "book" accumulated depreciation (which continues to accrue on Ridgeline's financial statements) and "regulatory" accumulated depreciation (which is frozen at the test year level for ratemaking purposes) has important strategic implications. If FERC Trial Staff or intervenors were to advocate for an updated test year — for example, to reflect actual operating data through a more recent period — rate base would decline due to the additional accumulated depreciation that has accrued since the original test year. This decline in rate base would reduce the return on rate base component of the cost of service, which could in turn lower the total cost of service and the recourse rate. This possibility should be considered in settlement strategy discussions, as an updated test year could move the recourse rate closer to the intervenors' target range.
The relationship between depreciation expense and accumulated deferred income taxes ("ADIT") is also relevant. ADIT of ($12.45 million) in the original rate base reflects the cumulative timing differences between tax depreciation and book depreciation. For federal income tax purposes, the Ridgeline Pipeline System is depreciated using the Modified Accelerated Cost Recovery System ("MACRS"), which provides for accelerated depreciation deductions in the early years of the asset's life. For book and ratemaking purposes, depreciation is computed on a straight-line basis at 2.5% per year. The difference between accelerated tax depreciation and straight-line book depreciation creates a deferred tax liability that reduces rate base, consistent with FERC policy that ratepayers should benefit from the time value of tax deferrals generated by accelerated depreciation. As the asset ages and tax depreciation deductions decline relative to book depreciation, the ADIT balance will reverse, increasing rate base. This interplay is a standard feature of regulated utility ratemaking and does not affect the reasonableness of the 2.5% book depreciation rate.
B. Depreciation and the Revised Cost of Service
The revised cost of service of $103.15 million includes depreciation expense of $14.68 million as a pass-through component, unchanged from the original filing. The complete component breakdown of the revised cost of service is as follows:
The revised weighted average cost of capital ("WACC") of 9.2375% reflects a capital structure of 55% equity and 45% debt, a revised return on equity ("ROE") of 12.50%, and a cost of debt of 5.25%. The revised WACC and the resulting return on rate base represent the primary changes between the original cost of service ($97.36 million) and the revised cost of service ($103.15 million). The depreciation expense, O&M, A&G, and other components remain substantially unchanged.
The revised billing determinants used to translate the total cost of service into a per-unit recourse rate are computed as follows:
Design capacity: 1,200,000 Dth/d × Days per year: 365 × Load factor: 75% = Annual billing determinants: 328,500,000 Dth/yr
The revised recourse