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2003 Annual Report on Electric Utility Efficiency


Report to the Utilities and Energy Committee

On Actions taken by the Commission Pursuant to 35-A M.R.S.A. § 3195



I.                    Background


35-A M.R.S.A. § 3195 authorizes the Public Utilities Commission (Commission) to adopt rate mechanisms that promote electric utility efficiency.  Subsection 5 of Section 3195 states:


            Annual Report.  The Commission shall submit to the joint standing committee of the Legislature having jurisdiction over utilities matters an annual report detailing any actions taken or proposed to be taken by the Commission under this section, including actions on mechanisms for protecting ratepayers from the transfer of risks associated with rate-adjustment mechanisms.  The report must be submitted by December 31st of each year.


            Since 1995, several Maine utilities have operated under Alternative Rate Plans (ARPs).  These plans replace traditional rate of return regulation[1] with a multi-year price cap approach that places an upper limit on the utility’s rate increases, while allowing the utility to retain savings it accomplishes through improved efficiencies.  In addition, the plans typically contain pricing flexibility provisions that allow the utility to offer reduced or re-designed rates to customers who would otherwise replace electricity with another fuel or leave the service territory.  Pricing flexibility allows the utility to obtain a contribution to its fixed costs that it would otherwise lose, thereby avoiding a shift of those fixed costs to remaining customers.  We have found that the ARPs create rate predictability and stability, reduce regulatory costs, and provide stronger incentives for utilities to minimize their costs.  The plans maintain a comprehensive and predictable regulatory approach.


            This report describes Commission actions taken during 2003 to promote electric efficiency through incentive rate plans or special rate contracts.


II.                  Central Maine Power Company’s Alternative Rate Plan


During 2000, the Commission approved a new 7-year Alternative Rate Plan (ARP 2000) for Central Maine Power Company (CMP).  With generation open to market competition, transmission service subject to Federal Energy Regulatory Commission (FERC) jurisdiction, and stranded costs being periodically adjusted in accordance with Maine law, ARP 2000 only applies to distribution delivery activities.  CMP’s ARP 2000 provides for annual rate changes on July 1st of each year.  Rate changes are based on a well-established formula of inflation minus a productivity offset, adjusted for mandated costs, earnings sharing and service quality index (SQI) penalties.  In comparison with CMP’s previous ARP, the ARP 2000 contains significantly stronger productivity incentives, allows only low-end earnings sharing, and increases the number of service and reliability indices that CMP must maintain.  These changes responded in part to CMP’s merger with Energy East, Inc.  In our order approving the CMP/Energy East merger, we recognized that the rate conditions imposed in connection with our merger approval (ensuring that ratepayers receive a reasonable portion of the efficiency savings while allowing Energy East an opportunity to recover its acquisition premium) could best be accomplished through an incentive rate plan.[2]


On March 18, 2003, CMP made its annual rate change filing for rates to go into effect on July 1, 2003.  The most significant portion of this year’s price change was a 7.5% reduction in rates to reflect the removal of costs associated with recovered regulatory assets, most significantly costs associated with the 1998 Ice Storm.  Pursuant to the terms of the Commission’s Order Approving the ARP 2000 Plan, the productivity offset for the 2003 price change was 2.25%, which resulted in a reduction of 0.91% when netted against the prior year’s inflation rate of 1.34%.  In addition, certain over-collections related to the Demand-Side Management (DSM) program and the Electric Lifeline Program (ELP) were flowed back to ratepayers, and thus reduced rates, while certain previously approved deferrals related to transformer costs were included and increased rates.  The overall impact of the third-year price change, including the removal of last year’s one-time reductions, was a 7.82% reduction to CMP’s core distribution rates.[3]


In 2003, the Commission also completed a mid-period review of the service quality components of the ARP 2000 plan.  The ARP 2000 Plan approved by the Commission called for a mid-period review, to be conducted in 2003, to provide parties an opportunity to request the Commission to modify or add to CMP’s service quality indices for effect on January 1, 2004.  The Commission issued a Notice of Investigation initiating the SQI Mid-Period Review on August 21, 2002.  The PUC Complaint Ratio and the Call Center Service Quality (Customer Survey) indicators were specifically targeted by the parties to the ARP 2000 Stipulation for replacement during the mid-period review.  To ensure that all the parties to ARP 2000 had an opportunity to pursue the contemplated collaborative effort and to provide parties with the opportunity to present any unresolved issues to the Commission in sufficient time for implementation on January 1, 2004, the Commission Staff began working with the parties to develop replacement measures for the PUC Complaint Ratio and the Customer Survey metrics in the Fall of 2002. 


On May 28, 2003, the Advisory Staff filed its Bench Analysis, which provided its preliminary views and recommendations in this matter.  The Staff stated that based on the information shared during the collaborative process, the parties and the Advisory Staff were in agreement that the two metrics targeted for replacement were accomplishing their objectives and should be retained.  The Commission Staff did recommend, however, that as part of the Mid-Period Review the Commission modify the Customer Average Interruption Duration Index (CAIDI) and System Average Interruption Frequency Index (SAIFI) outage exemptions from their current service-area basis to a company-wide basis.  According to the Staff, the current service area exemption criteria was inappropriately excluding a large number of small-scale non-extraordinary events from CAIDI and SAIFI performance calculations.[4]


The Public Advocate filed Comments on June 24, 2003 in support of the Bench Analysis recommendations.  CMP filed its Response to the Bench Analysis on August 22, 2003, arguing that the service reliability indicators, including CAIDI and SAIFI, were working as intended by the ARP and should not be changed.  If the Commission were inclined to review the CAIDI and SAIFI measures, however, CMP stated that any change should be neutral as to shifting any risk under the ARP.


On December 4, 2003, the OPA, the Industrial Energy Consumers Group (IECG) and CMP submitted a stipulation that resolved all mid-period review issues.  Under the terms of the Stipulation, the original exemption criteria of ARP 2000’s SQI mechanism would be modified for purposes of calculating CMP’s CAIDI, SAIFI and Business Call Answering performance indices from the current service-area basis to a company-wide basis.  Under the revised exemption criteria, outages would be excluded when 10% or more of the customers within CMP’s service territory were out of service.  When the exclusion applied, all outages associated with the event would be excluded for the duration of the event.  The Business Call Answering metric would exclude days when 10% or more of CMP’s customers were affected by outages.  In addition to these automatic exemptions, CMP could request permission to exclude data from the calculation of the CAIDI and SAIFI indicators on days when specific events, otherwise non-excludable, affected CMP’s ability to maintain service quality and resulted in substantial damage to CMP’s system.


In recognition of the changes to the CAIDI and SAIFI metrics (outage exclusions determined on a service territory basis rather than on 11 separate service center areas) and based on CMP’s improved outage data collection approach and query tool developed during this proceeding, the parties to the Stipulation proposed that the CAIDI baseline should be reduced from the current 2.58 hours/year to 2.32 hours/year and that the SAIFI baseline should be increased from the current 1.80 interruptions per year to 2.10 interruptions per year.  CMP will calculate its ongoing CAIDI and SAIFI performance using its improved outage database and the query tools developed during the proceeding.


On December 12, 2003, the Commission issued an order approving the Stipulation.  The modifications to the ARP 2000 SQI proposed in the Stipulation will take effect on January 1, 2004.  The new standards are not applicable to the measurement of CMP’s service quality performance for calendar year 2003, however.[5] 


III.                Bangor Hydro-Electric Company’s Alternative Rate Plan


In our order approving the proposed merger between Bangor Hydro-Electric Company (BHE) and Emera, Inc. (Emera), BHE was directed to file an Alternative Rate Plan proposal within two months of the closing of the merger with Emera or by June 30, 2001, whichever was earlier.[6]  In July 2001, BHE filed a proposal to implement an “All-In ARP” that would allow BHE to sell both transmission and distribution (T&D) delivery and standard offer service and to earn a return on the sale of these combined services.  The Commission rejected the proposal to allow BHE to sell standard offer service, stating that it was inconsistent with the Legislature’s decision to open Maine’s retail generation market to competition and to prohibit T&D utilities from selling generation to retail customers.[7]


Subsequent to our rejection of BHE’s “All-In ARP,” our Staff and the intervenors to the ARP case began a collaborative effort to develop an ARP for BHE.  On June 11, 2002, we issued an order which approved a Stipulation entered into by BHE, the OPA, and Georgia-Pacific Company, and thus approved an Alternative Rate Plan for BHE.  The BHE ARP, as it was referred to in the Stipulation, took effect on the date of the Order and will run through December 31, 2007.  The Stipulation provides for annual rate changes to occur on July 1st of each year of the ARP commencing on July 1, 2003.  The rate changes will occur in accordance with an Annual Percentage Price Change formula which is composed of Basic Rate Reductions, Mandated Costs, Net Capital Gains and Losses, Earnings Sharing and Service Quality Penalties.  The first two Basic Rate Reductions (BRR) to occur in 2003 and 2004 were set at –2.50% and –2.75%.  The rate changes in years four (2005) through six (2007) of the ARP depend on inflation.  If inflation in the two years prior to the time of those rates changes averages less than 3%, as is currently projected, the Basic Rate Reductions for those years will be –2.75%, -2.00% and –2.00%.[8]  Under the terms of the ARP, BHE is required to submit specific information each year on March 15 to be used to compute the annual allowable price change to go into effect on July 1 of that year.  The ARP Stipulation also establishes service reliability and customer service performance levels and subjects BHE to penalties of up to $840,000 if BHE’s performance drops below the established levels.  The BHE ARP calls for a mid-period review of the BHE ARP SQI to occur in 2004. 


            On March 15, 2003, BHE submitted its first annual ARP price change filing.  Pursuant to the terms of BHE’s ARP, the Company proposed to decrease its distribution rates by this year’s Basic Rate Reduction, or 2.5%.  No other adjustments were proposed by BHE.  BHE provided information with its filing on each of the Service Quality Index metrics.  However, the penalty provisions of the SQI mechanism were not applicable to BHE’s 2002 performance.  On June 25, 2003, we issued an order which approved BHE’s annual filing as proposed.[9]


            On September 24, 2003, BHE filed a petition with the Commission pursuant to the provisions of 35-A M.R.S.A. §§ 1303 and 1321, requesting that the Commission initiate a proceeding to investigate the SQI of its Alternative Rate Plan.  Specifically, in its petition BHE seeks to modify the CAIDI and SAIFI components of the SQI.  According to BHE, the data used by BHE, and ultimately relied on by the Commission to develop the CAIDI and SAIFI baselines, was faulty and, therefore, such baselines are not an accurate yardstick of BHE’s service performance.  BHE, therefore, requested that the Commission initiate an investigation to determine whether the use of the current CAIDI and SAIFI baselines are reasonable and whether such baselines should be modified.  The Commission issued a Notice of Investigation on October 7, 2003 and currently BHE’s request is being reviewed and analyzed by our Staff and the parties to the proceeding.


IV.       Maine Public Service Company


            On March 6, 2003, Maine Public Service Company (MPS) filed a request for approval of an Alternative Rate Plan to begin on July 1, 2003 and which would then run for seven years.  At the outset of the plan, MPS’s distribution rates would be increased by 8.9%, or $1.267 million, and then would increase annually by the rate of inflation during the next three years of the plan.  A productivity analysis would be conducted at the end of the third year of the plan to determine if a productivity offset was necessary for years 4 through 7.  In addition, rates would be adjusted for extraordinary costs, changes in variable interest rates, pursuant to an “economic conditions adjustment factor,” for earnings sharing outside a “dead-band,” for pricing flexibility lost revenues, and pursuant to a reliability safety and service quality index.


            In order to ensure that MPS’s rates were just and reasonable at the start of any ARP which might be approved in this case, the Hearing Examiner, in a Procedural Order dated April 2, 2003, ordered the Company to submit a “Chapter 120”[10] cost of service filing by April 10, 2003.  On April 11, 2003, the Company submitted its Chapter 120 filing based on a 2002 test year, adjusted for known and measurable changes.  In its filing, the Company alleged that it was entitled to a rate increase of $1.713 million under traditional cost of service principles.  However, MPS stated that it would not change its initial request for a $1.267 million increase.  MPS’s customers were provided with notice of the request to increase rates and were provided with an opportunity to comment or provide testimony at a public witness hearing on May 9, 2003.  No member of the public testified at that time.


            Following the submittal of MPS’s Chapter 120 filing, the OPA and our Advisory Staff conducted extensive discovery on the MPS filing both by way of written data requests and at a number of informal technical conferences.  Based on the information provided, the parties and our Advisory Staff held a number of settlement conferences.


            On September 3, 2003, the Commission approved a Stipulation entered into between MPS, the OPA, McCain Foods, Inc. and Huber, Inc.  Under the terms of the Stipulation all issues involving MPS’s initial rate increase request were resolved.  As amended by a Supplemental Stipulation approved by the Commission on October 29, 2003, MPS was authorized to increase its distribution rates by $685,037, or by approximately 4.5%, of which $306,827 was related to the cost of locking in MPS’s variable rate at today’s comparatively low fixed rates.  The parties to the proceeding were not able to come to agreement on MPS’s ARP proposal, however.[11]  Under the terms of the Stipulation, MPS was required to notify the Commission and the parties if it wished to proceed with its ARP proposal by December 31, 2003.  On December 29, 2003, we received notification from MPS that it did not wish to proceed and that it was withdrawing its proposal at this time.




[1] Rate of return regulation is a regulatory approach in which the Commission examines all reasonable expenses a utility is likely to incur and establishes rates that will allow the utility, if operated efficiently, to recover those expenses and earn a reasonable return on its investments.

[2] CMP Group, Inc. Et. Al., Request For Approval Of Reorganization And Of Affiliated Interest Transactions, Docket No. 99-411, Order (Jan. 4, 2000).

[3] Central Maine Power Company Review (Post-Merger) “ARP 2000,” Docket No. 2003‑179, Order Approving Stipulation (June 24, 2003).

[4] For purposes of the customer service and reliability indices, the service areas are defined as:  Augusta, Waterville, Dover, Farmington, Skowhegan, Rockland, Portland, Alfred, Lewiston, Bridgton and Brunswick.

[5] Public Utilities Commission, Mid-Period Review of CMP’s ARP 2000 Service Quality Indices, Docket No. 2002-445, Order Approving Stipulation (Dec. 12, 2003).

[6] Bangor Hydro-Electric Company Et. Al., Request For Approval of Reorganization (Joint Petition), Docket No. 2000-663, Order Rejecting Revised Stipulation and Approving Stipulation (Jan. 5, 2001). 

[7] Bangor Hydro-Electric Company, Request For Approval Of Alternative Rate Plan, Docket No. 2001-410, Order Rejecting Standard Offer Proposal (Sept. 5, 2001).

[8] Bangor Hydro-Electric Company, Request for Approval of Alternative Rate Plan, Docket No. 2001-410, Bangor Hydro-Electric Company, Proposed Rate Change to Increase Annual Revenues Approximately $6.4 Million, Docket No. 2001-728, Order Approving Stipulation (June 11, 2002).

[9] Bangor Hydro-Electric Company, Annual Price Change Pursuant to BHE Alternative Rate Plan (ARP), Docket No. 2003-203, Order Approving Stipulation (June 25, 2003).

[10] Chapter 120 of the Commission’s rules governs the material that utilities must submit when initiating a traditional rate of return rate proceeding.

[11] Maine Public Service Company, Request for Approval of Alternative Rate Plan, Docket No. 2003-85, Order Approving Stipulation (Part One)(Sept. 3, 2003).