MECL Open Access Transmission Tariff Stakeholder Session
Get insights into the upcoming MECL Open Access Transmission Tariff stakeholder session scheduled for February 18, 2022. Learn about the key discussions and updates related to this important session.
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Presentation Transcript
MECL Open Access Transmission Tariff Stakeholder Session February 18, 2022
Session Outline Review process followed to update Open Access Transmission Tariff ( OATT ) Schedules Present OATT Schedules updated to reflect actual costs incurred No changes proposed for OATT Terms and Conditions 2
Island Overview 3
OATT Development 2003-2006 In 2003, the Commission was directed by the Government of Prince Edward Island to inquire into, and report on, certain matters relating to electricity generation and transmission access in PEI The Commission concluded that the establishment of a United States Federal Energy Regulatory Commission ( FERC ) compliant OATT was necessary, and ordered Maritime Electric to file a FERC-compliant OATT in Order UE06-02 An OATT applies to all Transmission Customers, and provides non-discriminatory access to all Transmission Customers. In PEI s case, this includes Maritime Electric, the City of Summerside, and merchant wind In December 2006, Maritime Electric filed the proposed OATT and subsequently, at the Commission s direction, engaged in a stakeholder review process 4
OATT Development 2007-2016 In October 2007, Maritime Electric filed an amended OATT to reflect the results of the stakeholder review process The Commission approved the amended OATT on an interim basis (the Interim OATT ), effective June 30, 2008 (Order UE08-03) Disagreement between Maritime Electric and Summerside Electric on certain issues led to various regulatory and legal proceedings, which concluded in early 2015 In July 2016, Maritime Electric filed an application to update the Interim OATT to reflect: Changes in the electric power industry since 2006, largely related to subsequent FERC Orders Charges for various services based on 2014 cost data 5
OATT Development 2018 In March 2018, Maritime Electric amended the July 2016 OATT filing to reflect the updated NB-PEI interconnection cost, while leaving all other costs based on 2014 system costs (determined through the 2014 Cost Allocation Study) Effective August 1, 2018, the OATT was approved under Order UE18-05 Maritime Electric was to apply to the Commission, at least once in every three years, for approval of its transmission revenue requirements The current 2021 OATT Application fulfills that requirement 6
Cost Allocation Study Overview The proposed OATT charges are based upon 2020 transmission system costs determined by Chymko Consulting Ltd ( Chymko ) in the 2020 Cost Allocation Study ( CAS ) filed with the Commission on July 22, 2021 The 2020 CAS is a technical update to the comprehensive 2017 CAS prepared by Chymko and filed with the Commission on June 29, 2018 in advance of the 2018 General Rate Application The methodology of the 2017 CAS was consistent with previous cost allocation studies filed with the Commission and industry practice. The Commission did not express any concerns with the 2017 CAS The 2020 CAS uses the same methodology as the 2017 CAS 7
CAS and OATT Cost Determination Process The starting point for the 2020 CAS is the 2020 Maritime Electric Statement of Earnings, which is summarized in Table 1, page 6 of the 2020 CAS Using the Statement of Earnings, Chymko determines for the purposes of OATT which costs pertain to transmission, defined as high-voltage transmission facilities operating at a voltage of 69 kV or greater 8
Chymko Consulting Utility Ratemaking Experience Client Experience Utility Experience Regional Experience Municipalities Electric Prince Edward Island Crown Corporations Natural Gas Nova Scotia Private Utilities Water New Brunswick Co-operative Utilities Wastewater British Columbia Institutional Consumers Waste Management Alberta Regulators Recycling Saskatchewan 9
Generally Accepted Practices in Ratemaking Influences Local Operating Conditions Precedents Data Availability Administrative Burden Methods Assignments Allocations Special Studies Outcome Literature Bonbright NARUC Logical Consistency 10
Cost Allocation Process - Overview Income Statement Functionalization Classification Allocation 11
Functionalization Customer Care Services & Metering Income Statement Lighting Distribution Network Amortization Functionalize $203M $203M Generation & Power Supply O&M 12
Classification & Allocation Classification Cost drivers Allocation Classification informs allocation Measurable Refine allocator for circumstances Acceptable Examples: Functions classified by: Number of meters Demand Number of bills Energy Subsets thereof Sites 13
Cost Allocation Study & OATT Distribution Cost allocation informs Network rate design For this application, the $203M most important part is functionalization $18.97M Generation & Power Supply 14
CAS and OATT Cost Determination Process Chymko determined 2020 transmission costs to be $18.97 million These figures can be seen in Appendix A of the 2021 OATT application ($ thousands) OM&A expenses Amortization expense Interest, income taxes and return 9,147 3,014 6,812 18,974 Total* * Rounded 15
CAS and OATT Cost Determination Process (contd) Not all transmission costs are OATT costs. As a result, the next step requires an analysis of what transmission costs should be deducted from OATT costs This requires professional judgment on the part of Chymko and/or Maritime Electric staff, who rely upon industry practice and previous regulatory decisions including the Commission s ($ thousands) OM&A expenses Amortization expense Interest, income taxes and return 9,147 3,014 6,812 18,974 Total* Less adjustment to amortization Less cable debt collection and Y-115 expense Less accrued revenue adjustment 79 3,211 56 Adjusted total 15,628 * Rounded 16
OATT Cost Included Excluded Transmission lines and equipment Distribution substations Transmission substation costs Direct assign facilities for third parties Portion of Energy Control Centre Facilities dedicated to serving generation Portion of Maritime Electric overhead costs supplying only Maritime Electric Interconnection costs Cable/interconnection debt repayment costs Cable contingency fund Generation costs 17 17
2020 OATT Facilities Excludes transmission costs related to: T-23/25 Y-115 Portion of Y-104 Y-108 Y-112 Interconnection Debt Collection 18
Breakdown of OATT and Non-OATT Related Costs Some of the transmission costs relate to dedicated facilities, which are designated as non-OATT facilities ($ thousands) 2020 2014* MECL related - misc. facilities (non-OATT) MECL related - contracted wind (non-OATT) Merchant wind related (non-OATT) Transmission Service (Schedules 7, 8; Attachment H) ECC related (Schedule 1) 45 54 1,783 224 13,238 338 15,628 1,121 325 8,766 298 10,563 * Updated in 2018 to include costs associated with upgraded NB-PEI Interconnection Total The cost to provide Point-to-Point and Network Service is $13.238 million 19
2021 OATT Application Updated costs reflected in OATT Schedules No changes to Terms and Conditions Reflects infrastructure additions over the six year period of 2015-2020 All transmission-related capital expenditures received Commission approval 2016 OATT filing was based on the 2014 CAS 2018 update continued to be based on the 2014 CAS, plus known costs associated with upgraded NB-PEI interconnection Average Gross Plant in Service OATT Transmission Facilities increased $29.4 million over 2018 update 20
Regulator Approved Capital Budgets 2015-2020 Approved Annual Budget ($M) Approved Transmission Portion ($M) Year Order 2015 2016 2017 2018 2019 2020 TOTAL UE14-04 UE15-01 UE16-08 UE17-03 UE18-09 UE19-09 26.9 30.7 29.4 30.8 32.9 34.3 184.9 7.7 10.4 8.6 6.2 7.3 9.4 49.7 Transmission portion of annual capital budget includes expenditures on all transmission facilities (OATT and non- OATT) as well as substation expenditures 21
OATT Transmission Infrastructure Additions 2015-2020 Project Transmission Line Refurbishments and Projects Y-104 Build (2015-2017 portion of project) 69 & 138 kV Switch Replacement Y-109 Extension to Borden Lorne Valley Switching Station 69 KV Breaker Replacement Communications Equipment T-3 Rebuild Borden to Albany T-8 Rebuild T-1 Line Extension to Bagnall Road Transmission Capacitors T-21 Line Rebuild 138 kV Tap to Clyde River Substation Modernization T-15 Extension to Airport Y-109 Bannockburn Road - Steel Towers Other Cost ($M) 8.0 5.2 2.2 2.1 1.9 1.3 1.2 1.1 1.0 1.0 0.9 0.8 0.4 0.4 0.4 0.2 1.3 29.4 Total (rounded) 22
Y-104 Project Breakdown Y-104 build cost shown is the portion allocated to OATT facilities Project commenced in 2014, so $1.4 million of the line cost was included in 2014 Cost Allocation Study, and is reflected in the current OATT rates Total length 83.1 km. For purposes of OATT costs, 47.2 km is considered OATT facility; 35.9 km for Maritime Electric customers only Total cost - $11.6 million. $6.6 million is considered OATT-designated facility. Remaining $5.0 million is for Maritime Electric customers only 23
Transmission System Users Maritime Electric to deliver energy to its customers (90% of PEI load) City of Summerside to deliver energy it purchases from the mainland to the City s distribution system (which supplies 10% of the PEI load) West Cape wind farm to deliver its output to purchasers on the mainland 24
Transmission System Usage Demand determinants are used to determine equivalent transmission system usage for services OATT clause enabling energy exporters to procure Non-Firm service at off-peak rates at all hours (over a non-constrained path) leads to different demand determinants for energy flow-based services (Schedules 7, 8, and Attachment H) and ancillary services (Schedules 1 and 2) Schedules 7, 8 and Attachment H are based on Non-Appalachian Pricing , while Schedules 1 and 2 are based on Appalachian Pricing Schedules 7, 8, Attach H Schedules 1 and 2 (MW) MECL Network (average 12 CP) Summerside Short-Term Firm Summerside Non-Firm Merchant Wind Non-Firm 2020 213.8 11.6 4.7 35.4 265.5 2014* 189.0 10.0 6.7 33.7 239.4 2020 213.8 11.6 4.7 56.6 286.7 2014* 189.0 10.0 6.7 53.3 259.0 Total 25 *Updated in 2018 to include costs associated with upgraded NB-PEI Interconnection
Calculation of Schedule Rates Schedule 1 Scheduling, Control and Dispatch Appalachian pricing used to determine system usage (firm service or equivalent) 2020 2014* Annual cost ($ thousands) Firm Service or Equivalent (MW) Rate ($ / MW-year) 332 298 286.7 259.0 1,158.77 1,148.40 Schedules 7, 8 and Attachment H Non-Appalachian pricing used to determine system usage (firm service or equivalent) 2020 2014* Annual cost ($ thousands) Firm Service or Equivalent (MW) Rate ($ / MW-year) 13,238 265.5 49,858.76 8,766 239.4 36,619.25 26 * Updated in 2018 to include costs associated with upgraded NB-PEI Interconnection
Schedules Proposed Rates as Filed Schedule in OATT Reference in OATT Filing Proposed Rates ($/MW-month) Existing Rates ($/MW-month) Services Scheduling, System Control and Dispatch Reactive Supply and Voltage Control from Capacitive Sources Regulation (Automatic Generation Control) Load Following AGC and Load Following for Non-Dispatchable Wind Energy Imbalance Operating Reserve Spinning Operating Reserve Supplemental (10 minute) Operating Reserve Supplemental (30 minute) Point-to-Point Transmission Service Non-Capital Support Charge Rate Residual Uplift Network Transmission Service 1 2 Appendix F Appendix H NB OATT NB OATT NB OATT Section 6.3 NB OATT NB OATT NB OATT Appendix D Section 8.0 Section 6.3 Appendix E 98.23 50.58 8,210.57 8,175.68 $0.44/MWh n/a 8,164.06 3,908.48 3,908.48 4,154.90 1.88% n/a 4,154.90 95.70 127.97 8,210.57 8,175.68 $0.44/MWh n/a 8,164.06 3,908.48 3,908.48 3,051.60 1.79% n/a 3,051.60 3(a) 3(b) 3(c) 4 5 6(a) 6(b) 7 and 8 9 10 Attachment H 27
Correction to CAS Before After 28
Revised CAS Transmission Costs The updated CAS results in the following revised transmission costs: ($ thousands) Revised Original* OM&A expenses Amortization expense Interest, income taxes and return 9,016 3,014 5,607 17,638 9,147 3,014 6,812 18,974 Total Less adjustment to amortization Less cable debt collection and Y-115 expense Less accrued revenue adjustment 79 79 3,211 3,211 46 56 Adjusted total 14,302 15,628 * Filed with the Commission on July 30, 2021 29
OATT Transmission Infrastructure Additions 2015-2020 Project Transmission Line Refurbishments and Projects Y-104 Build (2015-2017 portion of project) 69 & 138 kV Switch Replacement Y-109 Extension to Borden Lorne Valley Switching Station 69 KV Breaker Replacement Communications Equipment T-3 Rebuild Borden to Albany T-8 Rebuild T-1 Line Extension to Bagnall Road Transmission Capacitors T-21 Line Rebuild 138 kV Tap to Clyde River Substation Modernization T-15 Extension to Airport Y-109 Bannockburn Road - Steel Towers Other Cost ($M) 8.0 5.2 2.2 2.1 1.9 1.3 1.2 1.1 1.0 1.0 0.9 0.8 0.4 0.4 0.4 0.2 1.3 29.4 Subtotal (rounded) Adjustment to Dedicated Facilities Church Road Substation 2.8 32.2 30 Total (rounded)
Revised Breakdown of OATT and Non-OATT Costs The revised breakdown of OATT and non-OATT costs is as follows: ($ thousands) Revised Original* MECL related - misc. facilities (non-OATT) MECL related - contracted wind (non-OATT) Merchant wind related (non-OATT) Reactive Power from Capacitive Sources (Schedule 2) Transmission Service (Schedules 7, 8; Attachment H) ECC related (Schedule 1) 43 45 1,268 207 243 12,209 332 14,302 1,783 224 - 13,238 338 15,628 Total * Filed with the Commission on July 30, 2021 Revised OATT Rate schedules will be filed with the Commission 31
Revised OATT Schedule Costs Schedule in OATT Reference in OATT Filing Revised Rates ($/MW-month) Original Rates* ($/MW-month) Services Scheduling, System Control and Dispatch Reactive Supply and Voltage Control from Capacitive Sources Regulation (Automatic Generation Control) Load Following AGC and Load Following for Non-Dispatchable Wind Energy Imbalance Operating Reserve Spinning Operating Reserve Supplemental (10 minute) Operating Reserve Supplemental (30 minute) Point-to-Point Transmission Service Non-Capital Support Charge Rate Residual Uplift Network Transmission Service 1 2 Appendix F Appendix H NB OATT NB OATT NB OATT Section 6.3 NB OATT NB OATT NB OATT Appendix D Section 8.0 Section 6.3 Appendix E 96.56 70.65 8,210.57 8,175.68 $0.44/MWh n/a 8,164.06 3,908.48 3,908.48 3,831.93 1.77% n/a 3,831.93 98.23 50.58 8,210.57 8,175.68 $0.44/MWh n/a 8,164.06 3,908.48 3,908.48 4,154.90 1.88% n/a 4,154.90 3(a) 3(b) 3(c) 4 5 6(a) 6(b) 7 and 8 9 10 Attachment H * Filed with the Commission on July 30, 2021 32
Definitions AGC (Automatic Generation Control): Equipment that automatically adjusts generation in a balancing authority area from a central location to maintain the balancing authority s interchange schedule plus frequency bias Ancillary services: Services required to ensure that the interconnected electric system is operated in a manner that provides a satisfactory level of service with acceptable levels of voltage and frequency Appalachian pricing: A pricing methodology where rates for Non-Firm Transmission Service are higher during on-peak hours than for off-peak hours which reflects the higher usage of the system during on-peak hours 33
Definitions Energy Imbalance: The difference between what actually happens for each generator and load and what they prearranged through schedules. Mathematically energy imbalance (EI) can be expressed as follows: EI = Actual Production or Usage - Scheduled Production or Usage. Firm Transmission Service: The highest quality or priority service offered to customers under a filed rate schedule that anticipates no planned interruption Load following: The use of on-line generation, storage, or load equipment to track the intra- and inter-hour changes in customer loads Network Service: A transmission service designed to allow customers to deliver energy from multiple resources to their load under one transmission contract Non-Appalachian pricing: A pricing methodology where rates for Non-Firm Transmission Service are the same during both on-peak hours and off-peak hours 34
Definitions Non-Firm Transmission Service: A Point-To-Point Transmission Service that is available from transmission capability in excess of that needed for reliable service to Network Customers and other Transmission Customers taking Firm Point-To-Point Transmission Service Operating Reserve (Spinning): The unloaded generation that is synchronized to the system and ready to serve additional demand Operating Reserve (Supplemental): Generation not connected to the system but capable of serving demand within a specified time or interruptible load that can be removed from the system in a specified time Point-to-Point Transmission Service: The reservation and transmission of capacity and energy on either a Firm or Non-Firm basis, from the point(s) of receipt to point(s) of delivery 35
