UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
Ridgeline Midstream Services LLC
Docket Nos. RP22-847-000 and RP22-847-001
PRE-FILED DIRECT TESTIMONY OF DR. NATASHA ORLOV ON BEHALF OF RIDGELINE MIDSTREAM SERVICES LLC
RATE DESIGN AND TARIFF PROVISIONS
December 5, 2022
Filed by:
Calderwood & Harkness LLP George Trujillo, Responsible Partner Brett Callahan, Lead Associate David Stanton, Working Associate 1601 K Street NW, Suite 900 Washington, DC 20006 Tel: (202) 555-4100
On behalf of:
Ridgeline Midstream Services LLC 700 Kanawha Boulevard East, Suite 1400 Charleston, WV 25301
FERC Code: 960442 EIN: 87-4231956
TABLE OF CONTENTS
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I. INTRODUCTION AND QUALIFICATIONS
A. Identity and Position
Q. Please state your full name, title, and business address.
A. My name is Dr. Natasha Orlov. I serve as Director of Rates & Regulatory at Ridgeline Midstream Services LLC ("Ridgeline" or the "Company"). My business address is 700 Kanawha Boulevard East, Suite 1400, Charleston, West Virginia 25301.
Q. By whom are you employed?
A. I am employed by Ridgeline Midstream Services LLC, a Delaware limited liability company and wholly owned subsidiary of Dunmore Energy Holdings Ltd. ("DEH"), a Cayman Islands exempted limited company registered under the Cayman Registry, Registration No. CR-381204. Ridgeline is the owner and operator of the Ridgeline Pipeline System (the "System" or the "Pipeline"), a 187-mile, 24-inch-diameter high-pressure natural gas transportation pipeline extending from Wetzel County, West Virginia to Greene County, Pennsylvania. I have held my current position at Ridgeline since May 2020, approximately seventeen months prior to the Pipeline's in-service date of October 1, 2021.
Q. Please briefly describe Ridgeline Midstream Services LLC.
A. Ridgeline is a FERC-jurisdictional interstate natural gas pipeline company organized under the laws of the State of Delaware. The Company was formed for the purpose of constructing, owning, and operating the Ridgeline Pipeline System, which provides firm and interruptible natural gas transportation service in the Appalachian Basin. Ridgeline is the sole entity responsible for the commercial operation, rate design, tariff administration, and regulatory compliance associated with the Pipeline. The Company maintains its principal offices in Charleston, West Virginia, and employs approximately 68 full-time personnel, including operations, engineering, commercial, and administrative staff. The Company is subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC" or the "Commission") under the Natural Gas Act ("NGA"), 15 U.S.C. §§ 717 et seq., and the Commission's regulations thereunder.
B. Professional Qualifications
Q. Please describe your educational background.
A. I hold a Doctor of Philosophy (Ph.D.) in Energy Economics from the Massachusetts Institute of Technology, Department of Economics, which I received in May 2011. My doctoral dissertation, titled "Optimal Pricing Structures for Natural Gas Pipeline Transportation Under Regulatory Constraints," examined the efficiency and equity implications of alternative rate design methodologies for interstate natural gas pipelines under the regulatory framework established by the NGA and FERC's implementing regulations. I also hold a Master of Science (M.S.) in Applied Mathematics from Georgetown University (2006) and a Bachelor of Arts (B.A.) in Economics, magna cum laude, from the University of Virginia (2004).
Q. Please describe your professional experience.
A. Upon completion of my doctoral studies, I joined the consulting practice of Cambridge Energy Analytics, LLC ("CEA"), a Washington, D.C.-based firm specializing in regulatory economics and energy infrastructure advisory services. At CEA, from 2011 through 2016, I advised numerous FERC-jurisdictional natural gas pipeline companies on rate design, tariff development, cost-of-service analysis, and regulatory strategy in connection with both initial rate filings and general Section 4 rate cases under the NGA. During my tenure at CEA, I participated in the preparation and filing of cost-of-service studies, rate design workpapers, and tariff provisions for over a dozen interstate natural gas pipeline proceedings before FERC, including initial tariff filings for new greenfield pipeline projects and rate case proceedings for established systems.
From 2016 through 2020, I served as Senior Manager, Regulatory Affairs at Cascade Partners LLC ("AVPC"), a FERC-jurisdictional pipeline operating approximately 310 miles of natural gas transportation facilities in Pennsylvania and West Virginia. At AVPC, I was responsible for the development and implementation of rate design strategies, the preparation of tariff filings under 18 C.F.R. Part 154, the management of regulatory compliance matters, and shipper relations. During my time at AVPC, I supervised the preparation of AVPC's general rate case filing in Docket No. RP18-312-000, in which the Commission accepted AVPC's proposed rates and tariff provisions as just and reasonable.
I joined Ridgeline Midstream Services LLC in May 2020 as Director of Rates & Regulatory. In this capacity, I am responsible for all aspects of rate design, tariff compliance, regulatory filings before the Commission, and the management of shipper relations and commercial matters pertaining to the Ridgeline Pipeline System.
Q. Are you familiar with FERC's regulatory framework governing natural gas pipeline rates and tariffs?
A. Yes. I am thoroughly familiar with the provisions of the NGA, including Section 4 (rates and charges) and Section 7 (certificates of public convenience and necessity), as well as 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 for Orders Permitting and Approving Abandonment Under Section 7 of the Natural Gas Act), and 284 (Certain Sales and Transportation of Natural Gas Under the Natural Gas Policy Act of 1978 and Related Authorities). I am also familiar with the Commission's policy statements, orders, and precedent governing rate design, cost allocation, and tariff provisions for interstate natural gas pipelines, including but not limited to the Commission's Statement of Policy on Rate Design, issued in connection with Order No. 636, and subsequent policy pronouncements addressing modified fixed-variable rate design methodology, negotiated rates, and open-access transportation principles.
Q. Have you previously submitted testimony before FERC?
A. Yes. I submitted pre-filed direct and rebuttal testimony on rate design and tariff provisions in the AVPC rate case, Docket No. RP18-312-000, in 2018. I also submitted affidavit testimony in support of a FERC Section 4 rate filing by Kanawha River Gas Transmission, Inc. in Docket No. RP19-655-000 in 2019, during my tenure at AVPC. In addition, I have provided expert consulting support and prepared workpapers used in connection with testimony submitted by other witnesses in numerous FERC proceedings during my career at Cambridge Energy Analytics, LLC.
Q. Please describe your current responsibilities at Ridgeline.
A. As Director of Rates & Regulatory, I have overall responsibility for the design and development of Ridgeline's tariff rates and rate structures, the preparation and filing of tariff sheets and rate schedules under 18 C.F.R. Part 154, oversight of billing determinant calculations and cost-of-service allocation methodologies, coordination with the Company's engineering, operations, and financial personnel to ensure that rate design reflects the physical and economic characteristics of the Pipeline, the management of shipper and stakeholder consultations concerning tariff provisions, and the preparation and coordination of regulatory filings before the Commission. I report directly to Ridgeline's Senior Vice President of Commercial Operations and General Counsel. I also supervise a team of three regulatory analysts and a tariff administrator who support the Company's rate design and regulatory compliance activities.
C. Purpose of Testimony
Q. What is the purpose of your testimony in this proceeding?
A. The purpose of my testimony is to present and support the rate design methodology, billing determinants, and tariff provisions underlying the proposed recourse rates for firm and interruptible natural gas transportation service on the Ridgeline Pipeline System, as set forth in Ridgeline's FERC Gas Tariff, Original Volume No. 1 (the "Tariff"), filed in this proceeding under Section 4 of the NGA and the Commission's regulations at 18 C.F.R. Part 284, Subpart G, as an open-access transportation tariff.
Specifically, my testimony addresses the following matters:
1. The rate design methodology underlying the proposed recourse rate of $0.2265 per dekatherm ("Dth") for firm transportation service on the Ridgeline Pipeline System, consisting of a reservation charge of $0.2223/Dth and a usage charge of $0.0042/Dth, under Rate Schedule FT-1;
2. The justification for the 100% load factor assumption used to derive annual billing determinants of 438,000,000 Dth per year, based upon the Pipeline's design capacity of 1,200,000 Dth per day;
3. The methodology for the split between the reservation charge and the usage charge under the modified fixed-variable ("MFV") rate design, consistent with prevailing FERC policy;
4. The derivation and structure of the proposed interruptible transportation rate under Rate Schedule IT-1;
5. The General Terms and Conditions ("GT&Cs") of the Tariff, which establish the operational, commercial, and administrative framework governing all transportation service on the Ridgeline Pipeline System;
6. The proposed rate schedules, specifically Rate Schedule FT-1 for firm transportation service and Rate Schedule IT-1 for interruptible transportation service;
7. The treatment of interconnection costs in the rate design, specifically with respect to the proposed interconnection with Appalachian Trunk Pipeline Company, LLC ("ATPC") at the Wetzel County Interconnect;
8. A comparison of Ridgeline's proposed recourse rate with the rates of similarly situated FERC-jurisdictional interstate natural gas pipelines in the Appalachian Basin; and
9. A response to anticipated arguments by intervenors regarding load factor, rate level, and the reservation/usage charge split.
Q. How does your testimony relate to the testimony of other witnesses in this proceeding?
A. My testimony is part of a coordinated presentation of evidence on behalf of Ridgeline. The testimony of the following witnesses provides the factual and analytical foundation upon which the rate design and tariff provisions addressed in my testimony are based:
• James K. Winfield, Senior Vice President of Commercial Operations, Ridgeline Midstream Services LLC, provides testimony on the policy justification and need for the Ridgeline Pipeline System, including the market demand for transportation capacity, the status of executed and pending precedent agreements, and the projected throughput ramp-up trajectory;
• Angela Moretti, Vice President and Controller, Ridgeline Midstream Services LLC, provides testimony on the cost of service and rate base underlying the proposed rates, including a total rate base of $612.40 million and a total cost of service of $97.36 million;
• Thomas Greaves, P.E., Vice President of Engineering, Ridgeline Midstream Services LLC, provides testimony on the engineering design and specifications of the Ridgeline Pipeline System, including system capacity, compressor station design, metering and measurement facilities, and interconnection facilities; and
• Dr. Raymond Braswell, Managing Director, Thornhill Capital Advisors, LLC, provides independent expert testimony on the appropriate return on equity ("ROE") and capital structure for the Ridgeline Pipeline System, including a proposed ROE of 14.00%, a capital structure of 55% equity and 45% debt, and a resulting weighted average cost of capital ("WACC") of 10.0625%.
My testimony draws upon and is consistent with the analyses and conclusions presented in the testimony of each of these witnesses. In particular, the rate design presented herein is derived from the cost-of-service determination supported by Ms. Moretti and the capital cost parameters supported by Dr. Braswell. The billing determinant calculations in my testimony rely upon the system design capacity confirmed in the testimony of Mr. Greaves. The market justification for the 100% load factor assumption is supported by the testimony of Mr. Winfield regarding projected throughput growth and shipper commitments.
D. Summary of Exhibits Sponsored
Q. Please identify the exhibits that you sponsor in this proceeding.
A. I sponsor the following exhibits, which have been prepared by me or under my direct supervision and are filed concurrently with this testimony:
In addition, my testimony references certain exhibits sponsored by other witnesses in this proceeding, including Exhibit A (Policy Testimony of James K. Winfield), Exhibit B (Cost of Service and Rate Base Testimony of Angela Moretti), Exhibit C (Engineering Testimony of Thomas Greaves), and Exhibit D (ROE and Capital Structure Testimony of Dr. Raymond Braswell). Where my testimony cross-references exhibits sponsored by other witnesses, I do so for contextual purposes and to demonstrate the consistency of the rate design with the underlying cost-of-service and engineering analyses.
II. OVERVIEW OF THE RIDGELINE PIPELINE SYSTEM AND SERVICE OFFERINGS
A. System Description (Summary)
Q. Please provide a summary description of the Ridgeline Pipeline System.
A. The Ridgeline Pipeline System is a 187-mile, 24-inch-diameter high-pressure interstate natural gas transportation pipeline extending from the Wetzel County Interconnect in Wetzel County, West Virginia to the Waynesburg Compressor Station in Greene County, Pennsylvania. The System is designed to transport natural gas produced from the Marcellus and Utica Shale formations in the Appalachian Basin to downstream markets via interconnection with the interstate pipeline grid.
The Pipeline's receipt point is at the Wetzel County Interconnect, located in Wetzel County, West Virginia, at approximately 39.6120° North latitude, 80.7540° West longitude. At this location, Ridgeline's milepost 0.0 ties into the 30-inch mainline of Appalachian Trunk Pipeline Company, LLC ("ATPC") at ATPC Milepost 412.6. The design capacity of the interconnection is 800 million cubic feet per day ("MMcf/d") bidirectional, expandable to 1.2 billion cubic feet per day ("Bcf/d") with additional compression and metering facilities.
The Pipeline's primary delivery point is at the Waynesburg Compressor Station, located in Greene County, Pennsylvania, at approximately 39.8965° North latitude, 80.1810° West longitude. The Waynesburg Compressor Station serves as both a compression and metering facility, providing custody transfer measurement for gas delivered from the System.
The System includes three compressor stations:
1. Wetzel Station, located at approximately milepost 2.3 in Wetzel County, West Virginia, with installed compression of 15,000 horsepower ("HP");
2. Mannington Station, located at approximately milepost 78.5 in Marion County, West Virginia, with installed compression of 15,000 HP; and
3. Waynesburg Station, located at approximately milepost 184.2 in Greene County, Pennsylvania, with installed compression of 15,000 HP.
The aggregate installed compression for the System is 45,000 HP. The compressor stations utilize natural gas-fired reciprocating compressor units manufactured by Granite Harbor Group/Solar and are designed to maintain system pressures sufficient to achieve the Pipeline's design capacity of 1.2 Bcf/d.
Q. What is the design capacity of the Ridgeline Pipeline System?
A. The design capacity of the Ridgeline Pipeline System is 1.2 Bcf/d. For rate design purposes, this is equivalent to 1,200,000 Dth per day, based on an assumed BTU content of 1,000 BTU per cubic foot. This assumption is conservative and consistent with standard practice for rate design calculations; actual BTU content of gas transported on the System may vary and is subject to the gas quality specifications set forth in the GT&Cs.
Q. What is the current throughput on the Pipeline?
A. As of the date of this testimony, the Ridgeline Pipeline System is transporting approximately 680 MMcf/d, which represents approximately 56.67% utilization of the Pipeline's design capacity (680,000 Dth/d ÷ 1,200,000 Dth/d). The Pipeline achieved its in-service date on October 1, 2021, and the current throughput level reflects the early operational period. As discussed further in Section IV below and in the testimony of Mr. Winfield, throughput is projected to increase as additional shippers execute precedent agreements and as production volumes from the Marcellus and Utica Shale formations continue to grow.
Q. What was the original construction cost of the Ridgeline Pipeline System?
A. The original construction cost of the Ridgeline Pipeline System was approximately $587.2 million, inclusive of pipeline facilities, compressor stations, metering stations, right-of-way acquisition, and environmental and permitting costs. The development and construction of the Pipeline was completed over a period of approximately 30 months, from initial ground-breaking in April 2019 through mechanical completion in August 2021 and commercial in-service on October 1, 2021. A detailed discussion of the construction costs and their treatment in rate base is provided in the testimony of Ms. Moretti.
Q. Are there any additional details regarding the engineering and design specifications of the Pipeline that are relevant to your testimony?
A. The engineering and design specifications of the Ridgeline Pipeline System are addressed in detail in the testimony of Thomas Greaves, P.E., Vice President of Engineering, which I cross-reference and incorporate by reference to the extent relevant to my rate design analysis. For purposes of my testimony, the key engineering parameters relevant to rate design are the design capacity of 1,200,000 Dth/d, the pipeline length of 187 miles, the 24-inch pipeline diameter, the aggregate installed compression of 45,000 HP, and the measurement and metering configurations at the receipt and delivery points.
B. Proposed Service Types
Q. What types of transportation service does Ridgeline propose to offer on the Pipeline?
A. Ridgeline proposes to offer two types of natural gas transportation service on the Ridgeline Pipeline System, each governed by a separate rate schedule within the Tariff:
1. Firm Transportation Service (Rate Schedule FT-1): Firm transportation service is Ridgeline's primary service offering. Under Rate Schedule FT-1, a shipper reserves a specified quantity of transportation capacity on the Pipeline, expressed as a Maximum Daily Quantity ("MDQ") in Dth per day. The firm shipper is obligated to pay a reservation charge for the reserved capacity regardless of whether the shipper actually utilizes that capacity on any given day. In addition, the shipper pays a usage charge for each Dth of gas actually transported. Firm shippers are entitled to the highest scheduling priority on the System.
2. Interruptible Transportation Service (Rate Schedule IT-1): Interruptible transportation service is available to shippers on a space-available, interruptible basis when firm capacity is not being utilized on the System. IT service does not require a long-term capacity reservation and is subject to curtailment or interruption at any time in favor of firm transportation service. IT shippers pay a daily volumetric rate for each Dth of gas actually transported.
Both services are offered under the open-access transportation principles of Part 284, Subpart G of the Commission's regulations, 18 C.F.R. §§ 284.221 et seq. Ridgeline is committed to providing non-discriminatory access to the Pipeline for all creditworthy shippers, consistent with the Commission's open-access transportation policies established in Order No. 636 and subsequent policy pronouncements.
Q. Are there any other service types that Ridgeline proposes to offer at this time?
A. No. At this time, Ridgeline's initial tariff filing proposes only Rate Schedule FT-1 for firm transportation service and Rate Schedule IT-1 for interruptible transportation service. Ridgeline reserves the right to propose additional services or rate schedules in the future, subject to the Commission's approval and the applicable requirements of the NGA and the Commission's regulations.
C. Sole Member and Corporate Structure
Q. Please describe the corporate ownership and structure of Ridgeline Midstream Services LLC.
A. Ridgeline Midstream Services LLC is 100% owned by Dunmore Energy Holdings Ltd. ("DEH"). DEH is a Cayman Islands exempted limited company, with its registered address at 4th Floor, Harbour Place, 103 South Church Street, George Town, Grand Cayman KY1-1002, Cayman Islands. DEH serves as the sole member of Ridgeline and is the ultimate parent entity of the Ridgeline corporate structure for purposes of this proceeding.
Patricia Dunmore is the founder, chairperson of the board of directors, and 72% controlling shareholder of DEH. The remaining 28% of DEH's equity interests are held by a combination of institutional investors and individual shareholders, none of whom individually holds a controlling interest.
DEH is a diversified midstream energy holding company with an estimated enterprise value of approximately $2.8 billion based on an internal valuation as of December 31, 2023, and annual consolidated revenue of approximately $485 million for the fiscal year ending December 31, 2023. DEH's portfolio of midstream energy assets includes approximately 1,200 miles of natural gas gathering and transportation pipelines across the Appalachian Basin and the Mid-Continent region, two cryogenic natural gas processing plants with an aggregate processing capacity of approximately 400 MMcf/d, and a 250 megawatt ("MW") wind energy portfolio currently under development in West Virginia and Pennsylvania. The Ridgeline Pipeline System is DEH's largest single midstream transportation asset and is the centerpiece of DEH's Appalachian Basin infrastructure strategy.
Q. Is the corporate ownership structure relevant to the rate design presented in your testimony?
A. The corporate ownership structure is relevant to the extent that it confirms Ridgeline's financial backing and the support of its parent company for the substantial capital investment required to construct and operate the Ridgeline Pipeline System. The financial strength and commitment of DEH as Ridgeline's sole member provide assurance that the Company has the resources to sustain the Pipeline through the throughput ramp-up period and to meet its obligations to shippers and the Commission. The capital structure and cost of capital applicable to Ridgeline for ratemaking purposes are addressed in the testimony of Dr. Braswell.
III. RATE DESIGN METHODOLOGY
A. Overview of Rate Design Approach
Q. Please provide an overview of the rate design approach that Ridgeline has adopted for its proposed tariff rates.
A. Ridgeline proposes a cost-of-service-based rate design that is consistent with the Commission's traditional ratemaking methodology for interstate natural gas pipelines. Under this approach, the total cost of service — determined in accordance with the Commission's regulations and policies and as presented in the testimony of Angela Moretti — is used as the basis for deriving the maximum recourse rates that Ridgeline is authorized to charge for firm and interruptible transportation service on the Pipeline.
The total cost of service for the Ridgeline Pipeline System, as supported by Ms. Moretti's testimony, is $97.36 million. This cost of service includes the following principal components: return on rate base, depreciation expense, operations and maintenance ("O&M") expense, administrative and general ("A&G") expense, taxes other than income taxes, income tax allowance, and applicable revenue credits. The detailed derivation and support for each of these components is presented in Ms. Moretti's testimony and the accompanying cost-of-service workpapers filed as Exhibit B.
The total cost of service is allocated between a reservation charge and a usage charge using the modified fixed-variable ("MFV") rate design methodology. The resulting proposed recourse rate for firm transportation service under Rate Schedule FT-1 is $0.2265/Dth, consisting of a reservation charge of $0.2223/Dth and a usage charge of $0.0042/Dth. This rate represents the maximum rate that Ridgeline may charge for firm transportation service; shippers may negotiate discounted rates below this maximum, consistent with the Commission's negotiated rate authority.
The Tariff is filed as FERC Gas Tariff, Original Volume No. 1, under Part 284, Subpart G of the Commission's regulations.
Q. Is the proposed rate design consistent with the Commission's ratemaking policies for new pipeline initial rate filings?
A. Yes. The proposed rate design is fully consistent with the Commission's long-standing policies governing rate design for initial tariff filings by new FERC-jurisdictional interstate natural gas pipelines. The MFV methodology, the use of design capacity as the basis for billing determinants, and the 100% load factor assumption are all standard elements of the initial rate filing framework that the Commission has endorsed in numerous prior proceedings. I discuss each of these elements in detail in the sections that follow.
B. Modified Fixed-Variable Rate Design
Q. Please explain the modified fixed-variable rate design methodology and how Ridgeline has applied it in this proceeding.
A. The modified fixed-variable rate design methodology is the prevailing rate design framework employed by FERC-jurisdictional interstate natural gas pipelines. Under the MFV methodology, the cost of service is classified into fixed and variable components, and these components are then allocated to the reservation charge and the usage charge, respectively.
Fixed costs are those costs that do not vary with the volume of gas transported on the Pipeline. These costs include the return on rate base, depreciation, income taxes, taxes other than income taxes, and a significant portion of O&M and A&G expenses that are incurred regardless of the level of throughput on the system. Because these costs represent the cost of maintaining the pipeline facilities in a state of readiness to provide transportation service, they are appropriately recovered through the reservation charge, which is paid by firm shippers based on their reserved capacity rather than actual volumes transported.
Variable costs are those costs that vary directly with the volume of gas transported. For natural gas pipeline systems, variable costs primarily consist of fuel and lost-and-unaccounted-for gas ("LAUF") costs associated with compressor station operations, as well as a limited portion of O&M expenses that are directly attributable to throughput levels. These costs are recovered through the usage charge, which is assessed on each Dth of gas actually transported.
In applying the MFV methodology to the Ridgeline Pipeline System, I have classified each component of the total cost of service as either fixed or variable, based on the nature of the cost and its relationship to throughput volumes. The classification of each cost component is as follows:
• Return on rate base: $61.62 million. This is a fixed cost, representing the return on the capital invested in the Pipeline. It does not vary with throughput volumes and is allocated entirely to the reservation charge.
• Depreciation expense: $14.68 million. This is a fixed cost, representing the recovery of the capital investment in the Pipeline over its useful life. It does not vary with throughput volumes and is allocated entirely to the reservation charge.
• Operations and maintenance expense: $12.44 million. This cost is allocated between the reservation charge and the usage charge based on the fixed/variable classification of individual O&M line items. The majority of O&M expenses — including pipeline maintenance, compressor station maintenance (exclusive of fuel), right-of-way maintenance, regulatory compliance costs, and similar items — are fixed in nature and are allocated to the reservation charge. A limited portion of O&M expenses, consisting primarily of variable compressor fuel costs, lubricants, and consumables directly related to throughput levels, is classified as variable and allocated to the usage charge.
• Administrative and general expense: $4.82 million. This is a fixed cost, representing corporate overhead, management, insurance, and other general business expenses. It does not vary with throughput volumes and is allocated entirely to the reservation charge.
• Taxes other than income taxes: $3.80 million. This is a fixed cost, consisting principally of property taxes and franchise taxes applicable to the Pipeline. It does not vary with throughput volumes and is allocated entirely to the reservation charge.
• Income tax allowance: $16.10 million. This is a fixed cost, representing the income tax obligation associated with the Pipeline's regulated activities. It does not vary with throughput volumes and is allocated entirely to the reservation charge.
• Revenue credits: ($16.10 million). Revenue credits offset a portion of the cost of service. The revenue credit amount reflects certain revenues and cost offsets that reduce the net cost of service to be recovered from firm transportation shippers. The treatment of revenue credits is presented in the cost-of-service workpapers filed as Exhibit B and is discussed in Ms. Moretti's testimony.
Q. What is the resulting allocation of cost of service between the reservation charge and the usage charge?
A. Based on the fixed/variable classification described above, the resulting allocation is as follows:
Approximately 98.1% of the total cost of service is recovered through the reservation charge, and approximately 1.9% is recovered through the usage charge. This allocation is consistent with the capital-intensive nature of natural gas pipeline transportation, where the overwhelming majority of costs are fixed costs associated with the construction, maintenance, and operation of the pipeline facilities, and only a small fraction of costs vary directly with throughput volumes.
Q. Is this allocation consistent with the cost allocations used by other FERC-jurisdictional pipelines?
A. Yes. The approximately 98/2 split between reservation and usage charges is well within the range observed among FERC-jurisdictional interstate natural gas pipelines, particularly for new greenfield pipeline systems with high capital costs and relatively low variable operating costs. Many pipeline rate designs approved by the Commission reflect reservation charge recoveries in excess of 95% of the total cost of service, with the usage charge recovering only the fuel-related and throughput-variable components. The detailed workpapers supporting the classification and allocation of each cost item are provided in Exhibits E and I.
C. Consistency with FERC Precedent
Q. Is the MFV rate design methodology proposed by Ridgeline consistent with FERC policy and precedent?
A. Yes. The Commission has consistently endorsed the MFV rate design methodology as the appropriate framework for rate design by interstate natural gas pipelines. The Commission's endorsement of the MFV methodology dates to its foundational restructuring of the natural gas pipeline industry in Order No. 636, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, issued in 1992. In Order No. 636, the Commission determined that the MFV rate design — under which fixed costs are recovered through the reservation charge and variable costs through the usage charge — best promotes efficient use of pipeline capacity, provides appropriate price signals to shippers, and ensures that pipelines have a reasonable opportunity to recover their fixed costs.
Since Order No. 636, the Commission has consistently applied and reaffirmed the MFV rate design methodology in numerous proceedings involving both initial rate filings for new pipelines and general rate cases for existing systems. In particular, the Commission has approved MFV rate designs for new greenfield pipeline projects in the Appalachian Basin and elsewhere, including proceedings in which the reservation charge recovers in excess of 95% of the total cost of service. The Commission has recognized that for capital-intensive pipeline systems, the fixed nature of the vast majority of costs makes the MFV methodology — with its emphasis on recovery of fixed costs through the reservation charge — the most appropriate rate design approach.
Ridgeline's proposed rate design is also consistent with the rate designs employed by comparable FERC-jurisdictional pipelines in the Appalachian Basin, as discussed further in Section IX below. The Pipeline's MFV rate design reflects the same fixed/variable cost classification methodology and the same allocation principles that the Commission has approved for similarly situated pipelines.
Q. Are you aware of any FERC policy or precedent that would be inconsistent with Ridgeline's proposed rate design?
A. No. I am not aware of any Commission policy or precedent that would be inconsistent with the rate design proposed by Ridgeline in this proceeding. The MFV methodology, the use of design capacity as the billing determinant basis, and the 100% load factor assumption for an initial rate filing by a new pipeline are all well-established elements of the Commission's ratemaking framework, as I discuss in further detail in the following sections.
IV. BILLING DETERMINANTS AND LOAD FACTOR ASSUMPTION
A. Design Capacity as Billing Determinant Basis
Q. Please explain the billing determinant basis used to derive the proposed recourse rate.
A. The billing determinants for the proposed recourse rate are based on the design capacity of the Ridgeline Pipeline System. The design capacity of the Pipeline, as confirmed in the testimony of Mr. Greaves, is 1.2 Bcf/d, which is equivalent to 1,200,000 Dth/d at the assumed BTU content of 1,000 BTU per cubic foot.
The annual billing determinant is derived by multiplying the daily design capacity by 365 days per year:
1,200,000 Dth/d × 365 days/year = 438,000,000 Dth/year
This annual billing determinant of 438,000,000 Dth/year represents the maximum annual throughput that could be transported on the Pipeline if the entire design capacity were fully subscribed and utilized every day of the year. The use of design capacity as the billing determinant basis is the standard approach for initial rate filings by new pipelines before the Commission.
Q. Why is design capacity the appropriate basis for the billing determinants?
A. Design capacity is the appropriate basis for the billing determinants because it reflects the full capacity of the facilities as constructed and the level of investment that must be recovered through the tariff rates. The Ridgeline Pipeline System was designed and constructed with a capacity of 1,200,000 Dth/d to serve the growing production volumes from the Marcellus and Utica Shale formations and the corresponding demand for transportation capacity to downstream markets. The cost of constructing the Pipeline to this design capacity — $587.2 million — is the investment that underlies the rate base and cost of service from which the proposed rates are derived. Using the full design capacity as the billing determinant basis ensures that the per-unit rate reflects the cost of the facilities as built and provides shippers with the benefit of the Pipeline's full capacity potential.
B. 100% Load Factor Assumption
Q. What load factor does Ridgeline propose for computing the billing determinants?
A. Ridgeline proposes the use of a 100% load factor for computing the billing determinants. Under a 100% load factor assumption, the annual billing determinant is equal to the full design capacity of 1,200,000 Dth/d multiplied by 365 days per year, yielding 438,000,000 Dth/year.
Q. Please explain the rationale for the 100% load factor assumption.
A. There are several complementary reasons supporting the use of a 100% load factor for this initial rate filing:
First, the Ridgeline Pipeline System is a new system seeking its initial tariff rate before the Commission. The Commission has consistently recognized that a 100% load factor is appropriate for initial rate filings by new pipelines, where the pipeline is designed to serve a demonstrable market and the pipeline operator is willing to bear the volumetric risk associated with throughput levels that may be below design capacity during the initial ramp-up period. The Commission has reasoned that the use of a 100% load factor results in the lowest possible per-unit rate for shippers, thereby promoting the marketability of the pipeline's service and encouraging subscriptions that will contribute to the pipeline's long-term utilization.
Second, the 100% load factor reflects the full design capacity of the Pipeline and represents the investment cost that must be recovered to support the facilities as constructed. The $587.2 million in construction costs and the resulting $612.40 million rate base represent the cost of building a 1,200,000 Dth/d pipeline. Using a load factor lower than 100% would, in effect, require existing or initial shippers to bear the cost of capacity that remains unsubscribed, resulting in a higher per-unit rate that does not reflect the pipeline's full capacity potential.
Third, the Ridgeline Pipeline System was designed and constructed to serve the growing natural gas production from the Marcellus and Utica Shale formations in the Appalachian Basin. As discussed in the testimony of Mr. Winfield, demand for natural gas transportation capacity in the region is projected to grow as production volumes increase and as new downstream markets develop. The Pipeline's design capacity was established based on comprehensive market demand analyses and production forecasts indicating that full capacity utilization is achievable within a reasonable planning horizon.
Fourth, using a load factor lower than 100% would result in a higher per-unit rate, which could deter potential shippers from subscribing to the Pipeline's service and create a self-fulfilling under-subscription scenario. A higher rate would reduce the Pipeline's competitiveness relative to alternative transportation options available to shippers, further constraining throughput and potentially preventing the Pipeline from achieving the throughput levels necessary to support its financial viability.
Fifth, Ridgeline is expressly willing to bear the volumetric risk associated with throughput below design capacity during the ramp-up period. By adopting a 100% load factor and a correspondingly lower per-unit rate, Ridgeline accepts that its revenues may be below the full cost of service during the initial years of operation while throughput builds toward design capacity. This willingness to bear risk demonstrates Ridgeline's confidence in the market for its service and its commitment to providing competitive rates that will attract and retain shippers.
Q. You noted that current throughput is approximately 680 MMcf/d, or 56.67% of design capacity. How do you reconcile the current utilization level with the 100% load factor assumption?
A. The current throughput of approximately 680 MMcf/d reflects the early operational phase of the Ridgeline Pipeline System, which achieved its in-service date only approximately 14 months ago, on October 1, 2021. The ramp-up of throughput on a new pipeline system is a gradual process that depends on the execution and activation of shipper agreements, the development of new production wells in the Pipeline's service area, and the construction of gathering system interconnections that deliver gas to the Pipeline's receipt point.
As discussed in Mr. Winfield's testimony, Ridgeline has executed precedent agreements representing a significant portion of the Pipeline's design capacity, and additional precedent agreements are under active negotiation. The projected throughput growth trajectory, based on executed and pending precedent agreements and independent market demand analyses, indicates that throughput is expected to increase materially over the next several years as additional shipper commitments are activated and as Marcellus and Utica Shale production in the Pipeline's service area continues to grow. I cross-reference and rely upon Mr. Winfield's testimony for the detailed analysis of projected throughput growth and the basis for Ridgeline's confidence in achieving full utilization of the Pipeline's design capacity within a reasonable planning horizon.
The Commission has consistently recognized that current throughput levels during the initial ramp-up period of a new pipeline do not dictate the appropriate load factor for an initial rate filing. Rather, the Commission evaluates the reasonableness of the load factor assumption based on the pipeline's design capacity, the demonstrable market for the pipeline's service, and the pipeline operator's willingness to bear the volumetric risk of under-utilization during the ramp-up period.
C. Impact of Load Factor on Rate Level
Q. Have you prepared a sensitivity analysis showing the impact of alternative load factor assumptions on the per-unit rate?
A. Yes. I have prepared a sensitivity analysis, which is filed as Exhibit G, that illustrates the impact of alternative load factor assumptions on the per-unit rate. The results are summarized as follows:
As the sensitivity analysis demonstrates, reducing the load factor assumption from 100% to 85% would increase the per-unit rate from $0.2265/Dth to approximately $0.2615/Dth — an increase of approximately 15.5%. Reducing the load factor assumption further to 75% would increase the per-unit rate to approximately $0.2963/Dth — an increase of approximately 30.8% over the proposed rate.
Q. What conclusions do you draw from this sensitivity analysis?
A. The sensitivity analysis confirms that the choice of load factor assumption has a significant impact on the per-unit rate. Lower load factor assumptions produce materially higher per-unit rates, which would undermine the competitiveness of Ridgeline's service in the regional transportation market and could discourage prospective shippers from subscribing to the Pipeline. A rate of $0.2615/Dth or $0.2963/Dth would be significantly less attractive to shippers than the proposed rate of $0.2265/Dth, particularly in a competitive market where shippers have alternative transportation options available. This would impede Ridgeline's ability to attract throughput commitments and achieve the utilization levels necessary to support the Pipeline's long-term financial viability.
It is Ridgeline's position that the 100% load factor best balances the interests of the Pipeline and its shippers. The 100% load factor produces the lowest possible per-unit rate, maximizing the value proposition for shippers while requiring Ridgeline to bear the volumetric risk of under-utilization during the ramp-up period. This approach is consistent with the Commission's policy of encouraging competitive rates for new pipeline service and promoting efficient use of pipeline capacity.
D. Levelization
Q. Is the proposed rate levelized?
A. Yes. The proposed recourse rate of $0.2265/Dth is levelized over a 25-year period. Levelization is a rate design technique in which the tariff rate is designed to recover the cost of service evenly over the useful life of the pipeline, rather than front-loading cost recovery in the early years when the rate base (and correspondingly, the return on rate base) is at its highest level.
Q. Please explain the levelization methodology.
A. Under a traditional, non-levelized rate design, the tariff rate would be highest in the early years of the pipeline's operation, when the undepreciated rate base is largest and the associated return on rate base and depreciation charges are at their highest levels. As the rate base declines over time due to depreciation, the cost of service — and thus the tariff rate — would decline correspondingly. This declining rate profile creates a "tilted" rate structure that results in higher rates for shippers in the early years and lower rates in later years.
Levelization smooths this rate profile by setting a constant rate that recovers the present value of the total cost of service evenly over the useful life of the pipeline. The levelized rate is set at a level that, when applied to the projected billing determinants over the 25-year period, produces a revenue stream whose present value equals the present value of the annual cost of service over the same period, discounted at the pipeline's weighted average cost of capital.
The effect of levelization is to produce a lower rate in the early years of the pipeline's operation (relative to the non-levelized rate) and a somewhat higher rate in the later years, with the result that the rate remains constant over the entire 25-year period. This approach benefits shippers by providing rate certainty and avoiding the rate shock that would result from the high initial rates under a non-levelized design. It also benefits the pipeline by aligning the rate with the expected throughput ramp-up trajectory, as lower rates in the early years promote shipper subscriptions and throughput growth.
The detailed levelization schedule, showing the annual cost of service, the levelized rate, and the present value calculations, is provided in Exhibit H.
Q. Is the Commission's acceptance of levelized rates for new pipeline initial tariff filings well-established?
A. Yes. The Commission has accepted levelized rate designs in numerous initial tariff filings by new pipeline projects. The Commission has recognized that levelization promotes efficient use of new pipeline capacity by providing competitive initial rates that attract shipper commitments and facilitate throughput ramp-up, while ensuring that the pipeline has a reasonable opportunity to recover its full cost of service over the life of the facilities. Ridgeline's 25-year levelization period is consistent with the useful life assumptions used in the cost-of-service study and is appropriate given the expected operational life of the Pipeline's facilities.
V. RESERVATION AND USAGE RATE DERIVATION
A. Reservation Charge Derivation
Q. Please explain the derivation of the proposed reservation charge.
A. The reservation charge is derived by dividing the total fixed cost of service allocated to the reservation component by the annual billing determinants. As discussed in Section III.B above, the total fixed cost of service allocated to the reservation charge is approximately $95.52 million. This amount represents the sum of all fixed cost-of-service components — return on rate base, depreciation, fixed O&M, A&G, taxes other than income taxes, and income tax allowance — net of applicable revenue credits and after deduction of the variable cost component allocated to the usage charge.
The reservation charge is calculated as follows:
Total fixed cost of service allocated to reservation: $95,520,000
Annual billing determinants: 438,000,000 Dth/year
Base reservation charge: $95,520,000 ÷ 438,000,000 Dth = $0.2181/Dth
The base reservation charge of $0.2181/Dth is then adjusted to $0.2223/Dth to reflect rounding adjustments and the application of the 25-year levelization methodology described in Section IV.D above. The levelization adjustment accounts for the smoothing of the rate over the useful life of the Pipeline and ensures that the reservation charge is set at a level that, when combined with the usage charge, will recover the present value of the total cost of service over the 25-year levelization period.
Q. What does the reservation charge represent, and how is it paid?
A. The reservation charge is the daily demand charge payable by firm transportation shippers under Rate Schedule FT-1 regardless of whether the shipper actually transports any gas on a given day. The reservation charge reflects the cost of maintaining the Pipeline in a state of readiness to provide firm transportation service at the shipper's reserved Maximum Daily Quantity. A firm shipper's monthly reservation charge obligation is calculated by multiplying the reservation charge rate ($0.2223/Dth) by the shipper's MDQ and by the number of days in the billing month.
The reservation charge is the primary mechanism for recovering the Pipeline's fixed costs, which constitute the vast majority of the cost of service. The reservation charge ensures that firm shippers contribute to the recovery of the Pipeline's fixed investment costs in proportion to their reserved capacity, thereby providing revenue stability and supporting the Pipeline's ability to meet its financial obligations.
Q. Is the reservation charge consistent with the Commission's rate design policies?
A. Yes. The reservation charge, as derived through the MFV methodology, is consistent with the Commission's long-standing policies on rate design for interstate natural gas pipelines. The Commission has repeatedly affirmed that the reservation charge is the appropriate mechanism for recovering a pipeline's fixed costs, and that the MFV methodology — under which fixed costs are allocated to the reservation charge — best promotes efficient capacity utilization and provides appropriate price signals to shippers.
B. Usage Charge Derivation
Q. Please explain the derivation of the proposed usage charge.
A. The usage charge is derived by dividing the total variable cost of service allocated to the usage component by the annual billing determinants. As discussed in Section III.B above, the total variable cost of service allocated to the usage charge is approximately $1.84 million. This amount represents the fuel-related costs and throughput-variable operating expenses associated with the transportation of gas on the Pipeline.
The usage charge is calculated as follows:
Total variable cost of service allocated to usage: $1,840,000
Annual billing determinants: 438,000,000 Dth/year
Usage charge: $1,840,000 ÷ 438,000,000 Dth = $0.0042/Dth
The usage charge of $0.0042/Dth is a volumetric charge assessed on each Dth of gas actually transported on the Pipeline. The usage charge covers fuel-related costs, including the cost of compressor fuel consumed in the operation of the Pipeline's three compressor stations, as well as variable operating expenses that are directly attributable to throughput volumes, such as compressor lubricants and consumable materials.
Q. Is the usage charge component relatively small in relation to the total rate?
A. Yes. The usage charge of $0.0042/Dth represents approximately 1.9% of the total recourse rate of $0.2265/Dth. This is consistent with the capital-intensive nature of pipeline transportation, where variable costs constitute a very small fraction of the total cost of service. The overwhelmingly fixed nature of pipeline costs — which include return on investment, depreciation, property taxes, income taxes, and the majority of O&M and A&G expenses — is reflected in the predominance of the reservation charge in the total rate.
C. Total Recourse Rate
Q. What is the total proposed recourse rate for firm transportation service on the Ridgeline Pipeline System?
A. The total proposed recourse rate for firm transportation service under Rate Schedule FT-1 is as follows:
This is the maximum rate applicable to firm transportation service under Rate Schedule FT-1. Shippers may negotiate discounted rates below the maximum recourse rate, consistent with the Commission's negotiated rate authority. Any discounted or negotiated rate arrangement would be subject to the terms and conditions of the Tariff and the Commission's applicable regulations and policy statements governing negotiated rates.
Q. Is the proposed recourse rate just and reasonable?
A. Yes. As I discuss in detail throughout this testimony, the proposed recourse rate of $0.2265/Dth is derived from a rigorously prepared cost-of-service study supported by the testimony of Ms. Moretti, employing a rate design methodology — the MFV approach — that is consistent with prevailing FERC policy and precedent. The rate is designed to recover the Pipeline's total cost of service of $97.36 million over the useful life of the facilities, using a 100% load factor and 25-year levelization that produce the lowest possible per-unit rate for shippers. The rate is competitive with the rates charged by comparable pipelines in the Appalachian Basin, as discussed in Section IX below. For all of these reasons, the proposed rate is just and reasonable within the meaning of Section 4 of the Natural Gas Act.
D. Derivation of Rate Components — Workpaper References
Q. Where can the detailed workpapers supporting the derivation of the rate components be found?
A. The detailed workpapers supporting the derivation of the reservation charge and usage charge are provided in the following exhibits:
• Exhibit E — Rate Design Workpapers, which present the step-by-step derivation of the reservation charge and usage charge from the total cost of service, including all intermediate calculations, rounding adjustments, and levelization adjustments.