UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act 1934
Date of Report (Date of earliest event reported): December 17, 2013
UNITIL CORPORATION
(Exact name of registrant as specified in its charter)
| New Hampshire | 1-8858 | 02-0381573 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) | ||
| 6 Liberty Lane West, Hampton, New Hampshire | 03842-1720 | |||
| (Address of principal executive offices) | (Zip Code) | |||
Registrant’s telephone number, including area code: (603) 772-0775
N/A
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 7.01 Regulation FD Disclosure
On December 17, 2013, the Maine Public Utilities Commission (“MPUC”), during its public deliberations, voted unanimously to approve a Settlement and Stipulation (“Stipulation”) in Docket No. 2013-00133, the base rate proceeding for the Maine division of Northern Utilities, Inc. (the “Company”), Unitil Corporation’s natural gas distribution utility subsidiary. A final written order commemorating the vote for approval, and which is statutorily necessary for the approval to become an official act of the MPUC, is expected to be issued by or on December 31, 2013. The vote approved a comprehensive Stipulation among the Company and the Office of the Public Advocate. The approved Stipulation provides for a total increase in annual revenue of $3.8 million, effective January 1, 2014. The Stipulation also includes a Targeted Infrastructure Replacement Adjustment (“TIRA”) rate mechanism, which will provide for annual adjustments to distribution base rates in future years to recover costs associated with the Company’s investments in specified operational and safety-related infrastructure replacement and reliability upgrade projects to its natural gas distribution system. The TIRA will have an initial term of four (4) years, and applies to investments made in eligible facilities in each of the calendar years 2013, 2014, 2015, and 2016. The Stipulation also includes an Earnings Sharing Mechanism, and a rate design change which allocates a higher percentage of revenue recovery to fixed monthly customer distribution charges than does the current rate design. The Stipulation is filed as Exhibit 99.1 to this Form 8-K. Exhibit 6 to the Stipulation, the Company’s Terms, Conditions and Tariffs for the Sale of Gas in the State of Maine, has been excluded from this filing and will be available on the Company’s website upon final written approval by the MPUC.
The Company also filed a base rate case for its New Hampshire natural gas division with the New Hampshire Public Utilities Commission (“NHPUC”) in April 2013. In New Hampshire, the Company requested an increase of $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. In New Hampshire, Northern Utilities has been authorized to implement temporary rates to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established. A final rate order for the New Hampshire filing is expected by the end of the first quarter of 2014.
Item 9.01 Financial Statements and Exhibits
| (d) | Exhibits |
| Number | Exhibit | |
| 99.1 | MPUC Stipulation dated December 5, 2013 and related exhibits | |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
UNITIL CORPORATION
| By: | /s/ Mark H. Collin | |
| Mark H. Collin | ||
| Senior Vice President, Chief Financial Officer and Treasurer
| ||
| Date: | December 19, 2013 |
EXHIBIT INDEX
| Number | Exhibit | |
| 99.1 | MPUC Stipulation dated December 5, 2013 and related exhibits | |
Exhibit 99.1
| STATE OF MAINE PUBLIC UTILITIES COMMISSION |
DOCKET NO. 2013-00133
December 5, 2013 | |
| NORTHERN UTILITIES, INC. d/b/a UNITIL, Proposed Increase In Rates |
STIPULATION | |
Northern Utilities, Inc., d/b/a Unitil (“Company”) and the Maine Office of Public Advocate (“OPA”), collectively the “Parties”, hereby agree and stipulate as follows:
I. PURPOSE
The purpose of this Stipulation is to resolve all issues in Docket No. 2013-00133, as further specified in Section III below. The provisions agreed to in this Stipulation have been reached as a result of information filed in this proceeding, obtained through discovery, meetings and Technical Conferences, and from discussions and negotiations among the Parties in this case. The Parties agree that they will work together to obtain Commission approval of the terms of the Stipulation in the public interest.
II. PROCEDURAL HISTORY
The Company submitted its Notice of Intent to File a General Rate Case in Docket No. 2013-00133 on February 1, 2013, in accordance with Section 6, Chapter 120 of the Maine Public Utilities Commission’s (“the Commission”) rules. On February 21, 2013, the OPA filed its Petition to Intervene as a party in the proceeding.
STIPULATION
Docket No. 2013-00133
Page 2 of 16
On April 1, 2013, the Company submitted its initial filing in Docket No. 2013-00133, including Direct Testimony and studies sponsored by Mark H. Collin, Thomas P. Meissner, Jr., David L. Chong, George E. Long, Paul M. Normand, Douglas J. Debski, James D. Simpson, and Dr. Samuel C. Hadaway. The Company’s initial filing sought Commission approval for an annual increase of $4,578,140 in distribution revenues, based upon a test year ending December 31, 2012; an overall weighted average rate of return on rate base of 8.54%; and certain known and measurable adjustments to test year revenues, expenses, and rate base. The Company requested that the new rates become effective on January 1, 2014, consistent with the Stipulation previously approved by the Commission in the Company’s prior base rate proceeding, Docket No. 2011-0092.
In addition, the Company requested approval to implement a multi-year alternative rate plan (“Rate Plan”) that would allow for future changes in the Company’s distribution rates, without the need to file a general rate case, for a defined period of time. The Company structured the Rate Plan around a proposal to implement an annual capital cost recovery mechanism to recover the costs of targeted improvements and upgrades to the Company’s distribution system and other safety related improvements, which mechanism known as the Targeted Infrastructure Recovery
STIPULATION
Docket No. 2013-00133
Page 3 of 16
Adjustment (“TIRA”). These system upgrade programs include a) the Cast Iron Replacement Program (“CIRP”) approved by the Commission in Docket No. 2008-151; b) the replacement of bare steel and non-cathodically protected (unprotected) coated steel mains and services; and (c) replacement of farm tap regulators (together, “Eligible Facilities”). The Company proposed the first annual TIRA adjustment for May 1, 2014, to recover the Company’s 2013 investment costs of these programs and improvements.
The Company also submitted an Accounting Cost of Service Study and a Marginal Cost of Service Study and proposed changes in rate design to reallocate recovery among classes in order to better reflect costs of service by class and to increase the fixed monthly customer charge, while decreasing volumetric usage changes.
By Notice of Proceeding issued on April 5, 2013, the Hearing Examiner opened this proceeding, established the deadline for Petitions to Intervene as April 29, 2013, and scheduled the Initial Case Conference for May 8, 2013. The Company mailed the Notice of Proceeding to its customers on April 11, 2014. At the Initial Case Conference, the Hearing Examiner granted the OPA’s Petition to Intervene.1 The Parties also discussed the remaining schedule for the case, which was confirmed in the Hearing Examiner’s Procedural Order dated June 24, 2013.
| 1 | No other petitions to intervene were filed. Two individuals have filed public comments in this docket. |
STIPULATION
Docket No. 2013-00133
Page 4 of 16
During May and June 2013, the Maine Public Utilities Staff (“the Staff”) and OPA issued numerous written Data Requests regarding the Company’s initial filing, to which the Company responded. During the course of the case, the Staff, OPA and the Company have issued more than 250 written and oral Data Requests. Many of these Data Requests had multiple subparts.
The Commission held a Technical Conference on May 31, 2013 on the Company’s Direct Testimony, during which both the OPA and the Staff asked questions of Company witnesses and made additional oral Data Requests of the Company. On June 18, 2013, the Commission held an additional Technical Conference to consider the CIRP, and to review the Company’s 2012 CIRP performance report and its CIRP plans for 2013. At this Technical Conference, the Hearing Examiner requested that the Company submit to the Commission previous responses of Fitchburg Gas and Electric Light Company to the Massachusetts Attorney General’s oversight questions (issued on April 11, 2013), regarding lost and accounted for gas and gas leaks. The Company complied with this request on June 24, 2013.
STIPULATION
Docket No. 2013-00133
Page 5 of 16
On July 9, the OPA filed the Direct Testimony, Exhibits, and work papers of three witnesses: Thomas S. Catlin, Jerome D. Mierzwa, and Johnny R. Brown. Mr. Catlin concluded that the Company had a revenue deficiency of $1,518,801, based on various adjustments to the Company’s proposed revenue requirements recommended by Mr. Mierzwa, Mr. Brown and Mr. Caitlin. On July 17, 2013, the Company submitted Data Requests to the OPA witnesses, to which the OPA responded.
On July 30, 2013, the Commission held a Technical Conference to allow questions on the OPA’s Direct Testimony, during which the Company and the Staff asked questions and made further, oral Data Requests of OPA’s witnesses.
The Hearing Examiner issued a Procedural Order on August 27, 2013, setting revised dates for the filing of the Bench Analysis, related discovery and responses, and the Technical Conference on the Bench Analysis.
The Staff issued its corrected Bench Analysis on September 12, 2013. The Company filed Data Requests on the Bench Analysis, to which the Staff responded. A Technical Conference on the Bench Analysis occurred on September 26, 2013, where the Company and OPA asked questions of Staff regarding the Bench Analysis. During the Technical Conference, the Company made further, oral Data Requests of Staff.
On October 8, 2013, the Company filed the Rebuttal Testimony of Mark H. Collin, Thomas P. Meissner, David L. Chong, Cindy L. Carroll, James D. Simpson, and Dr. Samuel C. Hadaway. The Company’s Rebuttal Testimony included an amended revenue requirement, reflecting a distribution revenue increase of $4,850,687, described the changes made to
STIPULATION
Docket No. 2013-00133
Page 6 of 16
the Company’s revenue requirement calculations, and proposed certain changes to its Rate Plan and TIRA. The Company filed the Appendix to the Rebuttal Testimony of Mr. Collin on October 9, 2013. On October 11, 2013, both the OPA and Staff issued Data Requests regarding the Company’s Rebuttal Testimony, to which the Company responded.
On October 18, 2013, the Parties, including Staff, engaged in settlement negotiations in person that resulted in the Parties reaching agreement on this Stipulation. These negotiations were preceded by phone calls and email exchanges between the Parties and Staff with respect to the terms of a negotiated settlement.
III. RECOMMENDED APPROVALS AND FINDINGS
Based on the record in this case, the Parties to this Stipulation agree and recommend that the Commission issue an Order that approves, accepts, and adopts this Stipulation, as just and reasonable and in the public interest, including the following provisions:
A. DISTRIBUTION RATE CHANGES
The Parties agree to an increase in the Company’s distribution revenues of $3,801,564 which consists of an increase in delivery revenues of $3,444,259 and an increase in production revenues of $357,304.2 Rates derived to recover the delivery revenue requirement increase to take effect on January 1, 2014 are attached to this Stipulation as Exhibit 1.
| 2 | With this increase, total production revenues of $1,138,171 will be included and collected within the Cost of Gas Factor Clause (CGFC) effective January 1, 2014. Per Second Revised Page 41 of Northern’s tariff, within the CGFC, Local Production Capacity and Storage Costs include the costs of providing storage supply service from the Company’s on-system supplemental gas facilities as well as any miscellaneous Administration and General costs associated with providing gas supply service, as determined in the Company’s most recent rate case proceeding or rate design proceeding. |
STIPULATION
Docket No. 2013-00133
Page 7 of 16
Rate Base: The Company’s revenue requirement is calculated based on a rate base of $111,760,626.
Cost of Capital: The Company’s revenue requirement is calculated on the basis of a weighted average cost of capital of 8.40% and a pretax weighted cost of capital of 11.75%. The cost of capital is applied to the rate base of $111,760,626.
B. RATE DESIGN
Class Allocation: The Company’s revenue requirement associated with the base rate increase described in Section III. A, above, shall be allocated to customer classes to generate the distribution charges for effect on January 1, 2014 indicated in Exhibit 1, attached to this Stipulation. This rate design allocates a higher percentage of revenue requirements to fixed monthly customer distribution charges and a lower percentage of revenue requirements to seasonal volumetric distribution charges and rate blocks than does the current rate design.
STIPULATION
Docket No. 2013-00133
Page 8 of 16
In addition, rate design changes to the customer and volumetric charges for the Residential Non-Heating Class (R-1) will be phased in as described herein such that at the end of the R-1 phase-in the customer charges for R-1 and the Residential Heating Class (R-2) will be equal and the first block volumetric charges for R-1 will be 81.65% of the R-2 first block volumetric charges and the second block volumetric charges for R-1 will be 81.09% of the R-2 second block volumetric charges. The phase-in methodology is described in the paragraph below.
Three R-1 phase-in steps, each implementing approximately one-third of the changes to Residential Non-Heating Class volumetric and monthly customer charges, will take effect on January 1, 2014; May 1, 2015; and May 1, 2016. The first phase-in adjustment will be on January 1, 2014 with the distribution base rates for all classes as shown in Exhibit 1. The second phase-in adjustment for R-1, which will occur on May 1, 2015, will be calculated as approximately half of the amount needed to reach the target levels described above. The calculation will take place following the application of the TIRA adjustment to rates. After the third and final phase-in adjustment on May 1, 2016, the R-1 and R-2 customer charges will be equal and the R-1 and R-2 volumetric distribution charges will be in the same proportion as described above. This calculation will take place following the application of the annual TIRA adjustment to rates.
STIPULATION
Docket No. 2013-00133
Page 9 of 16
With the first phase-in implemented on January 1, 2014, the resulting $338,725 revenue shortfall will be collected from all customer classes via an increase in customer and volumetric charges on a pro-rata basis. When the second and final R-1 phase-in adjustments are made, the customer and volumetric charges for all customer classes will be reduced on a pro-rata basis by the amount of incremental revenue that will result from the R-1 phase-in such that the Company’s total distribution revenue will be neutral when calculated based on weather normalized billing units from the immediately prior calendar year.
C. TIRA (TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT)
The Parties agree that the Company shall be allowed to implement, pursuant to the tariff attached to this Stipulation as Exhibit 2, a Targeted Infrastructure Replacement Adjustment (“TIRA”) which will provide for annual adjustments to distribution base rates to recover costs associated with the Company’s investments in targeted operational and safety-related infrastructure replacement and upgrade projects as described in Exhibit 2.
1. Eligible Facilities
The TIRA will allow for the recovery by the Company of prudently-incurred investments in the Eligible Facilities, which include facilities defined in the scope of work for (1) the Cast Iron Replacement Program (“CIRP”), approved by the Commission in Docket No. 2008-151, (2) the replacement of bare steel and non-cathodically protected (“unprotected”) coated steel mains and services, and (3) the replacement of farm tap regulators, all as described more fully in Section 4.03 of Exhibit 2. The scopes of work and schedules for the programs identified in (2) and (3) shall be specified in a Commission Order following the compliance filing in this proceeding described in Paragraph III. C. 5, below.
STIPULATION
Docket No. 2013-00133
Page 10 of 16
2. Term and Effective Dates
The TIRA will have an initial term of four (4) years, and applies to investments made in Eligible Facilities in each of the Calendar Years 2013, 2014, 2015, and 2016. The Company’s TIRA filing is due by February 28 of each year. Subject to review and approval by the Commission, the TIRA-adjusted distribution base rates shall become effective for service rendered on and after May 1 of 2014, 2015, 2016, and 2017. In the event the Company files a base rate case prior to the end of the initial term, the resulting revenue requirement shall be pro formed to reflect annualization of any TIRA rate adjustment not fully reflected in the test year. Any request to renew or extend the TIRA beyond its initial term shall be subject to Commission review and approval.
3. Calculation
The annual TIRA adjustment will be calculated using the most recently completed Calendar Year weather-normalized firm sales and delivery service revenue, will include indirect overheads, use a pretax weighted average cost of capital of 11.00%, and include an operations and maintenance (“O&M”) offset of $5,544 per mile of cast iron, bare steel and non-cathodically protected (unprotected) coated steel mains taken out of service. An example illustrating this calculation, including annual depreciation rates, is set forth in Exhibit 3.
STIPULATION
Docket No. 2013-00133
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4. TIRA Rate Impact Cap
The TIRA Rate Impact Cap shall be set at 4% of the Company’s distribution revenues. Amounts in excess of the TIRA rate impact cap shall be deferred and shall accrue carrying costs at the prime rate. The prime rate shall be fixed on a quarterly basis and established as reported in the Wall Street Journal on the first business day of the month preceding the calendar quarter. If more than one prime rate is reported, the average of the reported prime rates shall be utilized.
5. Compliance Filing; Performance Standard
The Company agrees to submit a filing by December 31, 2013 detailing the scopes and schedules for the unprotected steel and farm tap regulator programs. The filing will provide project cost estimates, the support for such estimates, project schedules, and revisions to the Earned Value Management (“EVM”) model that would permit tracking of cost and schedule performance metrics of the combined scope of work including the CIRP, unprotected steel and farm tap regulator replacement programs. The project scopes of the unprotected steel and farm tap regulator replacement programs, EVM revisions and performance metrics will be established by a Commission Order following this compliance filing.
STIPULATION
Docket No. 2013-00133
Page 12 of 16
If, in any year, one or more of the EVM performance indices (on a cumulative life-to-date basis) applicable to the Eligible Facilities falls below 100%, then the TIRA for that year will be suspended pending a review by the Commission of the reasonableness of the schedule and costs associated with the program.
D. EARNINGS SHARING
The Company will be allowed to retain all earnings up to a return on equity of 10%. Earnings in excess of 10% and up to an including 11% will be shared equally, 50/50, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. See the TIRA tariff, Exhibit 2.
The methodology for determining earnings and calculating potential earnings sharing is illustrated in Exhibit 4. As Exhibit 4 demonstrates, for purposes of calculating the earnings sharing, the Company’s earnings shall be calculated in accordance with the manner in which earnings are calculated in its Annual Report filed with the Commission but with revenues adjusted to reflect weather normalization and the removal of unbilled revenue.
STIPULATION
Docket No. 2013-00133
Page 13 of 16
E. REQUESTS FOR NEW CUSTOMER SERVICE AND SERVICE QUALITY BENCHMARKS
1. REQUESTS FOR NEW CUSTOMER SERVICE
The Company agrees to work with Staff and the OPA to study and develop a benchmark for tracking requests for new customer service and the Company’s responses to such requests. The intent of this study is to develop a service quality metric with respect to new service appointments that reflects the factors within the Company’s control in terms of handling requests for new service. The study will take place during 2014 and will be implemented, once agreed upon by Staff, OPA and the Company, and approved by the Commission, but not later than May 1, 2015.
2. SERVICE QUALITY BENCHMARKS
Certain of the Company’s current service quality benchmarks and their respective weights shall be amended and replaced in accordance with Exhibit 5. In addition, the maximum penalty amount for which the Company is responsible during any calendar year shall be $500,000. These amended service quality benchmarks shall be applicable to service provided beginning January 1, 2014.
F. Other Tariff Issues
Exhibit 6 includes individual tariff pages reflecting this settlement. Also, Exhibit 6 includes revised tariff pages filed by the Company in this proceeding and in compliance with Section 5.C.2 of Chapter 120 and not revised by this Stipulation because they reflect housekeeping issues only. These tariff pages shall become effective January 1, 2014.
STIPULATION
Docket No. 2013-00133
Page 14 of 16
IV. STIPULATIONS AS TO PROCEDURE
A. Staff Presentation of Stipulation.
The Parties to this Stipulation waive any rights they may have under 5 M.R.S. § 9062(4) and Section 742 of the Commission’s Rules of Practice and Procedure to the extent necessary to permit Staff to discuss this Stipulation and the resolution of this matter with the Commissioners prior to and at the Commission’s scheduled deliberations, without providing to the Parties an Examiner’s Report or the opportunity to file Exceptions.
B. Record.
The record on which the Parties enter into this Stipulation and on which the Commission may base its decision whether to accept and approve this Stipulation shall consist of: (1) this Stipulation; and (2) any and all confidential or public materials contained in the Commission’s Record of Docket No. 2013-00133 as of this date.
C. Non-Precedential Effect.
This Stipulation shall not be considered legal precedent, nor shall it preclude a Party from making any contention or exercising any rights, including the right of appeal, in any future Commission investigation or proceeding or any other trial or action. Furthermore, nothing in this Stipulation shall preclude any Party, during the remainder of this docket, from contesting any issue that has previously been raised in this Docket, including, without limitation, rate design issues.
STIPULATION
Docket No. 2013-00133
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D. Stipulation as an Integrated Document/Void if Rejected.
This Stipulation represents the full agreement between the Parties to the Stipulation, and rejection of any provision or term of this Stipulation constitutes a rejection of the whole. If not accepted by the Commission in its entirety and according to each of its terms, this Stipulation shall be void and of no further force and effect.
E. Conflict between Stipulation and Exhibits.
In the event of any conflict between this Stipulation and the Exhibits hereto, the Exhibits shall govern.
Respectfully submitted this 5th day of December 2013.
| Public Advocate | ||
| Office of the Public Advocate | ||
| By: /s/ William C. Black, Esq. | ||
| William C. Black, Esq. | ||
| Wayne R. Jortner, Esq. | ||
| Office of Public Advocate | ||
| 112 State House Station | ||
| Augusta, ME 04333 | ||
| (207) 287-2445 | ||
STIPULATION
Docket No. 2013-00133
Page 16 of 16
| NORTHERN UTILITIES INC. | ||
| By: /s/ Gary Epler | ||
| Gary Epler | ||
| Chief Regulatory Counsel | ||
| Unitil Services Corporation | ||
| 6 Liberty Lane West | ||
| Hampton, NH 03842-1720 | ||
| (603) 773-6440 | ||
Northern Utilities Inc.
Docket 2013-00133
Stipulation Exhibit 1
Page 1 of 1
Northern Utilities, Inc. - Maine
2013-00133 Stipulation
FINAL January 1, 2014 Distribution Charges Including Year 1 Residential Non-Heat Phase-In
And Year 1 Phase-In Revenue Shortfall Allocated To All Classes’ Rates on a Pro-Rata Basis
| Customer | Winter | Summer | ||||||||||||||||||||
| Class |
Description |
Charge | First | Second | First | Second | ||||||||||||||||
| R-2 |
Residential, Heating | $ | 22.24 | $ | 0.4073 | $ | 0.3118 | $ | 0.4073 | $ | 0.3118 | |||||||||||
| R-1 |
Residential, Non-Heating | $ | 12.90 | $ | 0.5177 | $ | 0.3696 | $ | 0.5177 | $ | 0.3696 | |||||||||||
| G-40/T-40 |
Low Annual, High Winter Use | $ | 52.82 | $ | 0.2719 | $ | 0.2510 | $ | 0.2719 | $ | 0.2510 | |||||||||||
| G-50/T-50 |
Low Annual, Low Winter Use | $ | 52.82 | $ | 0.2719 | $ | 0.2510 | $ | 0.2719 | $ | 0.2510 | |||||||||||
| G-41/T-41 |
Medium Annual, High Winter Use | $ | 154.19 | $ | 0.2610 | $ | 0.2480 | $ | 0.2527 | $ | 0.2296 | |||||||||||
| G-51/T-51 |
Medium Annual, Low Winter Use | $ | 154.19 | $ | 0.2332 | $ | 0.2202 | $ | 0.2248 | $ | 0.2018 | |||||||||||
| G-42/T-42 |
High Annual, High Winter Use | $ | 890.03 | $ | 0.2402 | $ | 0.2092 | $ | 0.2001 | $ | 0.1672 | |||||||||||
| G-52/T-52 |
High Annual, Low Winter Use | $ | 890.03 | $ | 0.2198 | $ | 0.1828 | $ | 0.1628 | $ | 0.1264 | |||||||||||
Northern Utilities, Inc.
Docket 2013-00133
Stipulation Exhibit 2
| M.P.U.C. | Second Revised Page 30.1 | |
| Northern Utilities, Inc. | Superseding First Revised Page 30.1 |
TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT
| 1.0 | Purpose |
The purpose of the Targeted Infrastructure Replacement Adjustment (TIRA) is to provide for annual adjustments to distribution base rates to recover the TIRA Revenue Requirements associated with the Company’s investments in specified targeted operational and safety-related infrastructure replacement and upgrade projects. This Tariff includes an Earnings Sharing Mechanism (ESM) to provide for a sharing of any excess earnings as specified herein.
| 2.0 | Applicability |
The TIRA, including its ESM, shall be applicable to all of the Company’s firm sales and delivery service customers.
| 3.0 | Term |
The TIRA shall provide for annual adjustments to distribution base rates on May 1 of 2014, 2015, 2016 and 2017.
| 4.0 | Targeted Infrastructure Replacement Adjustment (TIRA) |
| 4.01 | Purpose |
The purpose of the TIRA is to establish a mechanism to make annual adjustments to distribution base rates to recover the TIRA Revenue Requirements associated with the Company’s investments in specified targeted operational and safety-related infrastructure replacement and upgrade projects, as further defined in Section 4.03 (“Eligible Facilities”). This mechanism applies to investments made in Eligible Facilities in each of the Calendar Years 2013, 2014, 2015, and 2016.
| 4.02 | Effective Dates |
The adjustments to distribution base rates pursuant to the TIRA shall be determined annually by the Company as defined below, subject to review and approval by the MPUC. The TIRA filing shall be made by February 28 of each year. The adjustment to distribution base rates pursuant to the TIRA shall become effective for service rendered on and after May 1 of 2014, 2015, 2016, and 2017.
| 4.03 | Eligible Facilities |
The TIRA allows for the recovery of the TIRA Revenue Requirements for prudently incurred investments, including all appropriately capitalized costs, in the following targeted operational and safety-related projects: (a) replacement of all facilities and performance of system pressure conversion upgrades in the scope of work for the Cast Iron Replacement Program (CIRP), approved by the MPUC in Docket No. 2008-151; (b) replacement of bare steel and non-cathodically protected (unprotected) coated steel mains and services; and (c) replacement of farm tap regulators (together, “Eligible Facilities”). The scope of work, costs, tracking mechanisms and TIRA Performance Indices for (b) and (c) will be as approved by the MPUC.
| Issued: December 5, 2013 | Issued by: | Mark H Collin | ||||
| Effective: January 1, 2014 | Title: | Treasurer |
| M.P.U.C. | Third Revised Page 30.2 | |
| Northern Utilities, Inc. | Superseding Second Revised Page 30.2 | |
| TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT | ||
Investment in Eligible Facilities may include only the following plant accounts:
| a. | Account No. 367, Transmission Mains |
| b. | Account No. 376, Distribution Mains |
| c. | Account No. 378, Measuring and Regulating Stations |
| d. | Account No. 380, Distribution Services |
| e. | Account No. 381, Meters |
| f. | Account No. 382, Meter Installations |
| g. | Account No. 383, House Regulators |
| h. | Account No. 385, Industrial Measuring and Regulating Equipment |
| i. | Account No. 106, Completed but not yet classified [Eligible Facilities only] |
| 4.04 | Definitions |
The following terms shall be used in this TIRA Tariff as defined in this section, unless the context requires otherwise.
| (1) | “Accumulated Deferred Income Taxes” is the net accumulated difference between actual accelerated depreciation expense used in the calculation of federal income and state franchise taxes and depreciation expense as determined by United States Generally Accepted Accounting Principles. |
| (2) | “Accumulated Reserve for Depreciation” is the net balance arising from the provision for Depreciation Expense and the cost of removal. |
| (3) | “Calendar Year” is the annual period beginning on January 1st and ending on December 31st. |
| (4) | “Customer ESM Share” shall be an amount to be refunded to customers as provided in Section 5.03. |
| (5) | “Depreciation Expense” is the return of the Company’s investment in TIRA gross plant investments at annual rates illustrated in the Stipulation (Exhibit 3) approved by the MPUC in Docket No. 2013-00133. |
| (6) | “Distribution Revenue” is the total revenue derived from the billing of Company’s distribution base rates to the Rate Classes. |
| (7) | “Eligible Facilities” are those facilities as defined in Section 4.03. |
| Issued: December 5, 2013 | Issued by: | Mark H Collin | ||||
| Effective: January 1, 2014 | Title: | Treasurer |
| M.P.U.C. | Third Revised Page 30.3 | |
| Northern Utilities, Inc. | Superseding Second Revised Page 30.3 | |
| TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT | ||
| (8) | “MPUC” is the Maine Public Utilities Commission. |
| (9) | “Operating and Maintenance Expense Offset” is an amount of $5,544 per mile of cast iron, bare steel and non-cathodically protected (unprotected) coated steel mains taken out of service in a Calendar Year preceding the TIRA annual recovery period that begins each May 1. |
| (10) | “Property Tax Rate” is the average of the property tax rates in effect in the cities of Portland, South Portland and Westbrook, Maine, to be updated each year. |
| (11) | “Rate Class” is the group of customers that receive service under one of the Company’s firm sales and delivery service rate schedules: |
| (a) | Residential Non-Heating Rate R-1 |
| (b) | Residential Heating Rate R-2 |
| (c) | Commercial and Industrial Service (Low Annual Use, High Peak Period Use) Rate G-40, Rate T-40 |
| (d) | Commercial and Industrial Service (Medium Annual Use, High Peak Period Use) Rate G-41, Rate T-41 |
| (e) | Commercial and Industrial Service (High Annual Use, High Peak Period Use) Rate G-42, Rate T-42 |
| (f) | Commercial and Industrial Service (Low Annual Use, Low Peak Period Use) Rate G-50, Rate T-50 |
| (g) | Commercial and Industrial Service (Medium Annual Use, Low Peak Period Use) Rate G-51, Rate T-51 |
| (h) | Commercial and Industrial Service (High Annual Use, Low Peak Period Use) Rate G-52, Rate T-52 |
| (12) | “TIRA Adjustment Multiplier” is a multiplicative factor, a number greater than 1.0 determined pursuant to this Section 4.0, which is applied to the distribution base rate components for each Rate Class to recover TIRA Revenue Requirements for each annual recovery period beginning May 1. |
| (13) | “TIRA Performance Indices” are the Cost Performance Index and the Schedule Performance Index. |
| (14) | “TIRA Revenue Requirement” is the incremental revenue requirement through December 31 of the Calendar Year preceding the TIRA annual recovery period that begins each May 1. |
| Issued: December 5, 2013 | Issued by: | Mark H Collin | ||||
| Effective: January 1, 2014 | Title: | Treasurer |
| M.P.U.C. | Third Revised Page 30.4 | |
| Northern Utilities, Inc. | Superseding Second Revised Page 30.4 | |
| TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT | ||
| 4.05 | Limitation on Recovery |
The TIRA Revenue Requirements allowable for recovery in the current Calendar Year shall not exceed four percent (4.0%) of total weather-normalized Distribution Revenues for total sales in the above Rate Classes. Total weather-normalized Distribution Revenues will be calculated using then-current distribution base rates and weather-normalized sales levels for the immediately preceding Calendar Year. Any TIRA Revenue Requirements over this 4% limit will be deferred with interest at the prime rate and added to the TIRA Revenue Requirements for recovery in subsequent year(s), subject to this same 4% limitation.
| 4.06 | Performance Standard |
If, in any year, the TIRA Performance Indices (on a cumulative life-to-date basis) applicable to the Eligible Facilities, as approved by the MPUC, falls below 100%, then the TIRA for that year will be suspended pending a more comprehensive review by the MPUC of the reasonableness of the schedule and costs associated with the program.
| 4.07 | Calculation of TIRA Revenue Requirement |
The annual TIRA, not to exceed the cap pursuant to §4.05, will be calculated as a percentage change to current base rates and will be based upon the TIRA Revenue Requirement as a percentage of the previous year’s weather-normalized Distribution Revenue. The TIRA Revenue Requirement will be the sum of the annual Depreciation Expense, estimated property tax expense based on the Property Tax Rate, Operation and Maintenance Expense Offset and allowed return for the Eligible Facilities. The allowed return shall be calculated by multiplying the sum of the properly capitalizable costs less the related Accumulated Reserve for Depreciation and Accumulated Deferred Income Taxes by a pre-tax rate of return of 11.00%. The TIRA calculations shall use the methodology illustrated in the Stipulation approved by the MPUC in Docket No. 2013-00133.
| 4.08 | Adjustment to Distribution Base Rates |
Effective each May 1 for the years 2014, 2015, 2016, and 2017, the Company’s distribution base rate customer and usage charges for each Rate Class shall be adjusted. To determine the Company’s base distribution peak and off peak customer and volumetric rates to be effective May 1 of each current Calendar Year, the base distribution peak and off peak rates that are in effect just prior to May 1 of that Calendar Year will be multiplied by the TIRA Adjustment Multiplier. The TIRA Adjustment Multiplier will be calculated by dividing (1) the sum of the prior Calendar Year’s weather-normalized Distribution Revenues plus the current Calendar Year annual TIRA Revenue Requirement by (2) the prior Calendar Year weather-normalized Distribution Revenues. Weather-normalized Distribution Revenues will be calculated by multiplying the distribution peak and off peak base rates that are in effect just prior to May 1 of the current Calendar Year by the weather-normalized sales for the immediately preceding Calendar Year, plus actual booked customer charges.
| Issued: December 5, 2013 | Issued by: | Mark H Collin | ||||
| Effective: January 1, 2014 | Title: | Treasurer |
| M.P.U.C. | Second Revised Page 30.5 | |
| Northern Utilities, Inc. | Superseding First Revised Page 30.5 | |
| TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT | ||
| 5.0 | Earnings Sharing Mechanism (“ESM”) |
| 5.01 | Purpose |
The purpose of the ESM is to allow for the sharing with customers of any Company excess earnings, as defined below, which occur in Calendar Years 2013, 2014, 2015 and 2016. The Company shall be allowed to retain all earnings that result in a return on equity (“ROE”) of up to and including 10%. Any earnings that result in a ROE in excess of 10% and up to and including 11% shall be shared equally (50/50) between the Company and customers. Any earnings that result in a ROE in excess of 11% shall be returned to customers in accordance with the procedures described below.
| 5.02 | Effective Date |
The ESM adjustment rate shall be determined annually by the Company during the term of the TIRA and subject to review and approval by the MPUC. The ESM filing shall be made by February 28 of each year and shall be based on earnings and sales for the most recent completed Calendar Year. The ESM adjustment rate (if applicable) shall become effective for service rendered on and after May 1 of 2014, 2015, 2016 and 2017.
| 5.03 | ESM Calculation |
The ESM calculation shall be made in accordance with the methodology illustrated in the Stipulation approved by the MPUC in Docket No. 2013-00133. For purposes of the ESM, the calculation of the ROE shall be based on the calculation of the Return on Common Equity Subject to MPUC Jurisdiction (Page 16-A, Line 24) as submitted in the Company’s Annual Report to the MPUC, with modification to include a weather normalization and unbilled revenue adjustments.
The Customer ESM Share shall be a percentage of the ESM Amount as provided below:
| 1) | For any year in which the Company’s ROE is less than or equal to 10%, the Customer ESM Share shall be 0%. |
| 2) | For any year in which the Company’s ROE is greater than 10% but less than or equal to 11%, the Customer ESM Share shall be 50% of all amounts above a 10% ROE. |
| 3) | For any year in which the Company’s ROE is greater than 11%, the Customer ESM Share shall be 50% of all amounts from 10% up to and including 11%, and 100% of all amounts above 11%. |
| Issued: December 5, 2013 | Issued by: | Mark H Collin | ||||
| Effective: January 1, 2014 | Title: | Treasurer |
| M.P.U.C. | Third Revised Page 30.6 | |
| Northern Utilities, Inc. | Superseding Second Revised Page 30.6 | |
| TARGETED INFRASTRUCTURE REPLACEMENT ADJUSTMENT | ||
For any recently completed Calendar Year subject to this ESM in which the Company’s earnings result in a ROE that exceeds 10%, the volumetric (per ccf) base rates charged to sales and delivery service customers shall be adjusted by a uniform volumetric ESM adjustment rate effective for a 12-month period that begins each May 1. The ESM adjustment rate shall be calculated by dividing the Customer ESM Share by the total weather normalized customer volumes during the most recently completed Calendar Year in which the excess earnings occurred. For purposes of clarity, for each recently completed Calendar Year subject to this ESM, the ESM adjustment rate shall be effective for a 12-month period the begins each May 1 and ends on April 30 of the succeeding year.
| Issued: December 5, 2013 | Issued by: | Mark H Collin | ||||
| Effective: January 1, 2014 | Title: | Treasurer |
| Northern Utilities, Inc. Docket 2013-00133 Stipulation Exhibit 3 Page 1 of 3 | ||||||||
Northern Utilities, Inc. - Maine
Illustrative Targeted Infrastructure Rate Adjustment
Revenue Requirement for Year Ended December 31, 20XX
| (1) | (2) | (3) | ||||||||
| LINE | YEAR | |||||||||
| NO. |
DESCRIPTION |
YEAR 1 | YEAR 2 | |||||||
| Rate Base: | ||||||||||
| 1 | Plant in Service | $ | 4,792,956 | $ | 11,458,049 | |||||
| 2 | Accumulated Reserve for Depreciation | (485,090 | ) | (1,064,737 | ) | |||||
|
|
|
|
|
|||||||
| 3 | Net Plant in Service |
5,278,047 | 12,522,786 | |||||||
| 4 | Accumulated Deferred Income Tax | 52,770 | 226,318 | |||||||
|
|
|
|
|
|||||||
| 5 | Rate Base |
$ | 5,225,277 | $ | 12,296,469 | |||||
| Revenue Requirement: | ||||||||||
| 6 | Rate Base | $ | 5,225,277 | $ | 12,296,469 | |||||
| 7 | Pre Tax Rate of Return | 11.00 | % | 11.00 | % | |||||
|
|
|
|
|
|||||||
| 8 | Return and Related Income Taxes |
574,780 | 1,352,612 | |||||||
| 9 | Annualized Depreciation Expense | 94,921 | 226,918 | |||||||
| 10 | Property Tax | 92,735 | 220,025 | |||||||
| 11 | O&M Savings ($5,544/mile) | (34,927 | ) | (64,865 | ) | |||||
|
|
|
|
|
|||||||
| 12 | Total TIRA Revenue Requirement |
$ | 727,509 | $ | 1,734,690 | |||||
| Rate Cap Limit: | ||||||||||
| 13 | TIRA Cumulative Revenue Requirement | $ | 727,509 | $ | 1,734,690 | |||||
| 14 | Previous Year TIRA Cumulative Revenue Requirement | — | 727,509 | |||||||
|
|
|
|
|
|||||||
| 15 | Current Year Incremental TIRA Revenue Requirement |
$ | 727,509 | $ | 1,007,181 | |||||
| 16 | Prior Year Weather Normal Distribution Revenue | $ | 33,143,873 | $ | 33,871,382 | |||||
| 17 | Percent Limit | 4.00 | % | 4.00 | % | |||||
|
|
|
|
|
|||||||
| 18 | Maximum Annual Revenue Requirement Increase |
$ | 1,325,755 | $ | 1,354,855 | |||||
| 19 | Allowable Incremental TIRA Revenue Requirement | $ | 727,509 | $ | 1,007,181 | |||||
|
|
|
|
|
|||||||
| 20 | Total Allowable TIRA Revenue Requirement |
$ | 727,509 | $ | 1,734,690 | |||||
|
|
|
|
|
|||||||
| Northern Utilities, Inc. Docket 2013-00133 Stipulation Exhibit 3 Page 2 of 3 | ||||||||
Northern Utilities, Inc. - Maine
Illustrative Targeted Infrastructure Rate Adjustment
Revenue Requirement for Year Ended December 31, 20XX
| (1) | (2) | (3) | ||||||||||||
| LINE | YEAR | |||||||||||||
| NO. |
DESCRIPTION |
YEAR 1 | YEAR 2 | |||||||||||
| Capital Expenditures: | ||||||||||||||
| 1 | 367 | Transmission Mains | $ | — | $ | — | ||||||||
| 2 | 376 | Distribution Mains | 5,101,846 | 7,091,118 | ||||||||||
| 3 | 378 | Meas. & Reg. Stations | — | 112,628 | ||||||||||
| 4 | 380 | Distribution Services | 223,661 | 201,913 | ||||||||||
| 5 | 381 | Meters | — | — | ||||||||||
| 6 | 382 | Meter Installations | — | — | ||||||||||
| 7 | 383 | House Regulators | — | — | ||||||||||
| 8 | 385 | Industrial Meas. & Reg. Equip. | — | — | ||||||||||
| 9 | 106 | Completed, not yet Classified | — | — | ||||||||||
|
|
|
|
|
|||||||||||
| 10 | Total Capital Expenditures | $ | 5,325,507 | $ | 7,405,659 | |||||||||
| 11 | Cost of Removal Estimate | 10 | % | 10 | % | |||||||||
|
|
Cost of Removal: |
|||||||||||||
| 12 | 367 | Transmission Mains | $ | — | $ | — | ||||||||
| 13 | 376 | Distribution Mains | 510,185 | 709,112 | ||||||||||
| 14 | 378 | Meas. & Reg. Stations | — | 11,263 | ||||||||||
| 15 | 380 | Distribution Services | 22,366 | 20,191 | ||||||||||
| 16 | 381 | Meters | — | — | ||||||||||
| 17 | 382 | Meter Installations | — | — | ||||||||||
| 18 | 383 | House Regulators | — | — | ||||||||||
| 19 | 385 | Industrial Meas. & Reg. Equip. | — | — | ||||||||||
| 20 | 106 | Completed, not yet Classified | — | — | ||||||||||
|
|
|
|
|
|||||||||||
| 21 | Total Cost of Removal | $ | 532,551 | $ | 740,566 | |||||||||
|
|
Plant Additions: |
|||||||||||||
| 22 | 367 | Transmission Mains | $ | — | $ | — | ||||||||
| 23 | 376 | Distribution Mains | 4,591,661 | 6,382,006 | ||||||||||
| 24 | 378 | Meas. & Reg. Stations | — | 101,365 | ||||||||||
| 25 | 380 | Distribution Services | 201,295 | 181,722 | ||||||||||
| 26 | 381 | Meters | — | — | ||||||||||
| 27 | 382 | Meter Installations | — | — | ||||||||||
| 28 | 383 | House Regulators | — | — | ||||||||||
| 29 | 385 | Industrial Meas. & Reg. Equip. | — | — | ||||||||||
| 30 | 106 | Completed, not yet Classified | — | — | ||||||||||
|
|
|
|
|
|||||||||||
| 31 | Total Plant Additions | $ | 4,792,956 | $ | 6,665,093 | |||||||||
|
|
Depreciation Rates: |
|||||||||||||
| 31 | 367 | Transmission Mains | 1.60 | % | 1.60 | % | ||||||||
| 32 | 376 | Distribution Mains | 1.87 | % | 1.87 | % | ||||||||
| 33 | 378 | Meas. & Reg. Stations | 3.49 | % | 3.49 | % | ||||||||
| 34 | 380 | Distribution Services | 4.34 | % | 4.34 | % | ||||||||
| 35 | 381 | Meters | 2.37 | % | 2.37 | % | ||||||||
| 36 | 382 | Meter Installations | 5.00 | % | 5.00 | % | ||||||||
| 37 | 383 | House Regulators | 2.56 | % | 2.56 | % | ||||||||
| 38 | 385 | Industrial Meas. & Reg. Equip. | 0.00 | % | 0.00 | % | ||||||||
| 39 | 106 | Completed, not yet Classified | 0.00 | % | 0.00 | % | ||||||||
| 40 | Weighted Avg Depreciation Expense | 1.97 | % | 1.96 | % | |||||||||
| Northern Utilities, Inc. Docket 2013-00133 Stipulation Exhibit 3 Page 3 of 3 | ||||||||
Northern Utilities, Inc. - Maine
Illustrative Targeted Infrastructure Rate Adjustment
Revenue Requirement for Year Ended December 31, 20XX
| (1) | (2) | (3) | (4) | (5) | ||||||||||||||
| LINE |
DESCRIPTION |
ADDITIONS | RATE | YEAR 1 | YEAR 2 | |||||||||||||
| Book Depreciation | ||||||||||||||||||
| 1 | Year 1 |
$ | 4,792,956 | 1.98 | % | $ | 47,460 | $ | 94,921 | |||||||||
| 2 | Year 2 |
$ | 6,665,093 | 1.98 | % | — | 65,999 | |||||||||||
|
|
|
|
|
|||||||||||||||
| 3 | Total Book Depreciation |
$ | 47,460 | $ | 160,919 | |||||||||||||
| Tax Depreciation | ||||||||||||||||||
| 4 | Year 1 |
$ | 4,792,956 | 3.750 | % | $ | 179,736 | $ | 346,004 | |||||||||
| 5 | Year 2 |
$ | 6,665,093 | 7.219 | % | — | 249,941 | |||||||||||
|
|
|
|
|
|||||||||||||||
| 6 | Total Tax Depreciation |
$ | 179,736 | $ | 595,945 | |||||||||||||
| 7 | Tax Minus Book Depreciation | $ | 132,275 | $ | 435,025 | |||||||||||||
| 8 | Tax Rate | 39.89 | % | 39.89 | % | |||||||||||||
|
|
|
|
|
|||||||||||||||
| 9 | Deferred Income Tax |
$ | 52,770 | $ | 173,548 | |||||||||||||
|
|
|
|
|
|||||||||||||||
| 10 | Accumulated Deferred Income Tax (1) | $ | 52,770 | $ | 226,318 | |||||||||||||
|
|
|
|
|
|||||||||||||||
Notes
| (1) | Actual depreciation rate for TIRA additions will be reflected in filings |
| Northern Utilities, Inc. | ||||||||
| Docket 2013-00133 | ||||||||
| Stipulation Exhibit 4 | ||||||||
| Page 1 of 1 |
Northern Utilities, Inc - Maine
Earnings Sharing Mechanism Calculation
| Line |
Item |
2012 | Explanation | |||||
| 1 | Weather-Normalized Return on Equity Calculation | |||||||
| 2 | Total Net Income from Commission Jurisdiction | $ | 3,604,527 | ME PUC Annual Report Page 16-A | ||||
| 3 | Adjustments to Weather-Normalize: | |||||||
| 4 | Weather Normalization |
$ | 1,643,525 | Adjust revenue for normal weather | ||||
| 5 | Unbilled Revenue |
(1,086,863 | ) | Remove unbilled revenue | ||||
| 6 | Tax Effect |
(222,053 | ) | -(Line 4 + 5) * 0.3989 Federal and State Tax Rate | ||||
|
|
|
|||||||
| 7 | Total Weather-Normalized Net Income From Commission Jurisdiction | $ | 3,939,137 | Line 2 + 4 + 5 + 6 | ||||
| 8 | Total Common Equity for Investments Subject to Commission Jurisdiction | $ | 64,725,426 | ME PUC Annual Report Page 16-A | ||||
|
|
|
|||||||
| 9 | Weather-Normalized Return on Equity | 6.1 | % | Line 7 / 8 | ||||
|
|
|
|||||||
| 10 | Earnings Sharing Calculation | |||||||
| 11 | Earnings Sharing Return on Equity 50% Threshold (“50% Threshold”) | 10.0 | % | Section 5.01 of TIRA Tariff | ||||
| 12 | Earnings Sharing Return on Equity 100% Threshold (“100% Threshold”) | 11.0 | % | Section 5.01 of TIRA Tariff | ||||
| 13 | If Weather-Normalized ROE > 50% Threshold but Less Than 100% Threshold | |||||||
| 14 | Weather-Normalized Return On Equity | 6.1 | % | |||||
| 15 | 50% Threshold | 10.0 | % | |||||
|
|
|
|||||||
| 16 | ROE Amount Subject to Earnings Sharing |
-3.9 | % | Line 14 - 15 | ||||
| 17 | Total Common Equity for Investments Subject to Commission Jurisdiction | $ | 64,725,426 | ME PUC Annual Report Page 16-A | ||||
| 18 | If ROE Amount Subject to Earnings Sharing is Positive; Else 0.0% | 0.0 | % | If Line 16 >0, Line 16; Else 0.0% | ||||
| 19 | 50% Sharing Between Company and Ratepayers | 50.0 | % | Portion Shared Between Company and Ratepayers | ||||
|
|
|
|||||||
| 20 | Net Income to be Credited to Ratepayers | $ | 0 | Line 17 * 18 * 19 | ||||
| 21 | Tax Effect | 0 | Line 22 - 20 | |||||
|
|
|
|||||||
| 22 | Revenue to be Credited to Ratepayers |
$ | 0 | Line 20 * 1 / (1 - 0.3989) | ||||
|
|
|
|||||||
| 23 | If Weather-Normalized ROE > 100% Threshold | |||||||
| 24 | Total Common Equity for Investments Subject to Commission Jurisdiction | $ | 64,725,426 | ME PUC Annual Report Page 16-A | ||||
| 25 | Difference Between 100% Threshold and 50% Threshold | 1.0 | % | |||||
| 26 | 50% Sharing Between Company and Ratepayers | 50.0 | % | Portion Shared Between Company and Ratepayers | ||||
|
|
|
|||||||
| 27 | Net Income to be Credited to Ratepayers (If Weather-Normalized ROE > 100% Threshold; Else $0) |
$ | 0 | Line 24 * 25 * 26 | ||||
| 28 | Tax Effect | 0 | Line 29 - 27 | |||||
|
|
|
|||||||
| 29 | Revenue to be Credited to Ratepayers |
$ | 0 | Line 27 * 1 / (1 - 0.3989) | ||||
|
|
|
|||||||
| 30 | Weather-Normalized Return On Equity | 6.1 | % | |||||
| 31 | 100% Threshold | 11.0 | % | |||||
|
|
|
|||||||
| 32 | ROE Amount Subject to Earnings Sharing |
-4.9 | % | Line 30 - 31 | ||||
| 33 | Total Common Equity for Investments Subject to Commission Jurisdiction | $ | 64,725,426 | ME PUC Annual Report Page 16-A | ||||
| 34 | If ROE Amount Subject to Earnings Sharing is Positive; Else 0.0% | 0.0 | % | If Line 32 >0, Line 32; Else 0.0% | ||||
| 35 | 100% Sharing Between Company and Ratepayers | 100.0 | % | Portion Shared Between Company and Ratepayers | ||||
|
|
|
|||||||
| 36 | Net Income to be Credited to Ratepayers |
$ | 0 | Line 33 * 34 * 35 | ||||
| 37 | Tax Effect | 0 | Line 38 - 36 | |||||
|
|
|
|||||||
| 38 | Revenue to be Credited to Ratepayers |
$ | 0 | Line 36 * 1 / (1 - 0.3989) | ||||
|
|
|
|||||||
| 39 | Total Revenue to be Credited to Ratepayers |
$ | 0 | Line 29 + 38 | ||||
|
|
|
|||||||
(FOR ILLUSTRATIVE PURPOSES)
Northern Utilities, Inc. - Maine
SQP Measures, Weights and Penalty
| Current Benchmark |
Weight | Settlement Benchmark |
Weight | |||||||||||||
| Field Operations |
||||||||||||||||
| Service Appointments Met |
92 | % | 10.00 | 92 | % | 20.00 | ||||||||||
| Odor Calls (one hour response) |
95 | % | 20.00 | 97 | % | 20.00 | ||||||||||
| Meter Reading |
||||||||||||||||
| On-Cycle Meter Reading |
98 | % | 10.00 | 98.50 | % | 10.00 | ||||||||||
| Long No Reads |
0 | 10.00 | Eliminate | |||||||||||||
| Billing |
||||||||||||||||
| Meter Reads Used |
99.40 | % | 10.00 | Eliminate | ||||||||||||
| Customer Service |
||||||||||||||||
| TSF 30 seconds - Emergencies |
95 | % | 10.00 | 97 | % | 15.00 | ||||||||||
| TSF 30 seconds - Non-Emergencies |
75 | % | 10.00 | 75 | % | 15.00 | ||||||||||
| Abandoned Call Rate |
5 | % | 5.00 | 5 | % | 5.00 | ||||||||||
| Network Busy Outs |
2 | % | 5.00 | Eliminate | ||||||||||||
| Overall Service |
||||||||||||||||
| Consumer Division Cases/1,000 |
3.0 | 10.00 | 2.5 | 15.00 | ||||||||||||
| Customer Satisfaction |
NA | Eliminate | ||||||||||||||
| Maximum Annual Penalty |
$ | 300,000 | $ | 500,000 | ||||||||||||
NOTE: A metric for tracking New Customer Service Requests will be designed according to the Stipulation.