Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - UNITIL CORP | d8k.htm |
| EX-99.1 - PRESS RELEASE - UNITIL CORP | dex991.htm |
Exhibit 99.2
STATE OF NEW HAMPSHIRE
PUBLIC UTILITIES COMMISSION
DE 10-055
UNITIL ENERGY SYSTEMS, INC.
Notice of Intent to File Rate Schedules
Order Approving Settlement Agreement
O R D E R N O. 25,214
April 26, 2011
APPEARANCES: Gary Epler, Esq., for Unitil Energy Systems, Inc.; Rorie E.P. Hollenberg, Esq., of the Office of Consumer Advocate on behalf of residential utility ratepayers; and Lynn Fabrizio, Esq., for the Staff of the Public Utilities Commission.
| I. | PROCEDURAL HISTORY |
This proceeding involves a request by Unitil Energy Systems, Inc. (Unitil) to raise its distribution rates. On March 16, 2010, Unitil filed a notice of intent to file rate schedules, followed by a petition for a general rate increase and request for temporary distribution rates filed on April 15, 2010. In support of its petition, Unitil submitted the testimonies of Mark H. Collin, Chief Financial Officer and Treasurer of Unitil Corporation (UC) and President of Unitil Service Corporation (USC); George E. Long, Jr., Vice President of Administration for USC; Thomas P. Meissner, Jr., Chief Operating Officer of UC and Senior Vice President of USC; Samuel C. Hadaway, a principal of FINANCO, Inc.; and Paul M. Normand, a principal of Management Applications Consulting, Inc. (MAC).
In its petition, Unitil requested an increase in annual distribution revenues of $6.7 million in temporary rates pursuant to RSA 378:27 for effect on July 1, 2010. The request for temporary rates represented a 19 percent increase above present distribution revenues, or 4.3 percent above present overall revenues, reflecting a 6.5 percent increase.1 Unitil’s temporary rate request was part of a broader filing in which Unitil requested a permanent increase of $10.1 million in annual distribution revenues.
| 1 | Overall revenues include distribution, default energy, transmission, and system benefits charge revenues. |
Exhibit 99.2
| DE 10-055 | - 2 - |
On April 19, 2010, the Office of Consumer Advocate (OCA) notified the Commission that it would be participating in this proceeding on behalf of residential ratepayers, consistent with RSA 363:28. On April 26, 2010, the Commission issued Order No. 25,093 suspending the proposed tariff and setting a prehearing conference, temporary rate hearing, and technical session for May 7, 2010, all of which took place as scheduled. On May 7, 2010, Staff submitted a report on the technical session proposing a procedural schedule and outlining basic rules of discovery, as agreed upon by the parties and Staff. The Commission issued a secretarial letter on May 13, 2010, establishing the procedural schedule for the temporary and permanent rate phases of this proceeding, including a hearing on temporary rates to be held on June 10, 2010.
The parties and Staff held a settlement conference on the temporary rate petition on May 27, 2010. A follow-up conference call including all parties was held on June 2, 2010, resulting in an agreed upon proposal on temporary rate issues, including a total annual temporary distribution service revenue level approximately $5.2 million above the test year revenue level. Of the increase, $500,000 was intended to permit Unitil to begin recovering expenses incurred during the December 2008 ice storm, approximately $2 million of which had been deferred for accounting purposes in Docket No. DE 09-155. Another $500,000 of the increase was earmarked to permit the Company to begin expanding its existing reliability enhancement and tree trimming efforts. On June 4, 2010, Staff filed a stipulation and settlement on temporary rates (Stipulation) signed by Unitil, the OCA and Staff. The Stipulation was presented to the Commission at hearing on June 10, 2010 and approved on June 29, 2010, by Commission Order No. 25,124 for effect July 1, 2010.
Exhibit 99.2
| DE 10-055 | - 3 - |
On November 4, 2010, Unitil filed an amendment to its rate petition with supplemental testimony of Mark H. Collin. On November 5, 2010, the OCA filed testimony of Kenneth E. Traum, and Staff filed testimony of witnesses Steven E. Mullen, George R. McCluskey, James C. Cunningham, Jr., and Jim Brennan; John W. Wilson, PhD, of J.W. Wilson & Associates, Inc.; and Michael D. Cannata, Jr., P.E., Senior Consultant of Accion Group, Inc.
The Audit Staff of the Commission conducted an investigation and audit of test year information supplied with Unitil’s request for a permanent rate increase, and expenses related to the December 2008 ice storm emergency restoration efforts. Unitil responded to several sets of data requests from the Audit Staff. The results of the audit review are included in final audit reports dated September 22, 2010 (test year audit) and May 10, 2010 (ice storm audit). The Audit Staff also conducted an investigation and audit of Unitil’s expenses related to the February 2010 wind storm emergency restoration efforts. A final audit report on that matter was released on January 18, 2011.
Staff and the OCA issued discovery requests concerning the request for a general rate increase, to which Unitil responded. The parties and Staff met in technical sessions in July, September, and December of 2010. Settlement discussions took place on multiple dates during December 2010 and January 2011, leading ultimately to a settlement agreement.
On January 28, 2011, Staff filed a letter requesting suspension of the approved procedural schedule, advising that the parties and Staff had reached agreement in principle and were jointly drafting a comprehensive settlement document. By secretarial letter dated February 4, 2011, the Commission granted Staff’s request and cancelled the hearing scheduled to begin on February 8,
Exhibit 99.2
| DE 10-055 | - 4 - |
2011. The Company, OCA, and Staff filed a joint settlement agreement on permanent distribution rates (Settlement) on February 23, 2011. By secretarial letter dated February 24, 2011, the Commission established a hearing date of March 10, 2011; the hearing took place as scheduled. Following the hearing, Unitil filed a motion on March 28, 2011, requesting confidential treatment of certain information contained in a report prepared by Unitil’s consultant Environmental Consultants Inc. (ECI) provided in response to Staff data request 1-29, which was entered into the record during the hearing as Exhibit No. 5.
On March 31, 2011, the Company submitted a rate case expense filing pursuant to the terms of the Settlement. The filing included a motion for confidential treatment of certain consultant and attorney billing information and the identification of RFP respondents and their cost proposals.
| II. | SETTLEMENT AGREEMENT ON PERMANENT DISTRIBUTION RATES |
On February 23, 2011, Unitil, the OCA, and Staff (collectively, the Settling Parties) entered into a Settlement intended to resolve all of the issues in this docket. The Settlement contained the recommendations of the Settling Parties with respect to approval by the Commission of new permanent distribution rate levels, storm emergency restoration cost recovery, and specific rate design modifications.
1. Settlement Term
The term of the Settlement is to begin on May 1, 2011, and will continue for a five-year period, ending on May 1, 2016,2 unless terminated sooner under the provisions of Section 5 of the Settlement or by mutual agreement of the Settling Parties, and approved by the Commission.
| 2 | Assuming that this Settlement Agreement remains in effect for the full term (i.e., until May 1, 2016), then, pursuant to the earnings sharing calculations in Section 5.1.3 of the Settlement Agreement, if a deferred liability and an associated deferred asset have been recognized by Unitil for the reporting calendar year of 2015, the refund to customers contemplated by that section shall occur over the 12-month period beginning May 1, 2016. |
Exhibit 99.2
| DE 10-055 | - 5 - |
The Settlement is attached and made a part of this Order.
2. Distribution Rate Changes (Section 2)
The Settlement provides for changes to Unitil’s permanent distribution revenues, beginning on May 1, 2011, with an increase of $4,991,314. The changes include a permanent increase in Unitil’s distribution rates to address the Company’s current distribution revenue deficiency, and a step adjustment for additional recovery of certain expenses. That rate change will be followed by three additional step adjustments to be implemented on May 1, 2012 (an increase of $1,509,376), May 1, 2013 (an increase of $1,865,624), and May 1, 2014 (an increase of $1,430,828). The May 1, 2011 distribution revenue increase is net of the temporary rates in effect since July 1, 2010, and will include other agreed upon adjustments to Unitil’s rates,3 as well as the recoupment of the difference between temporary and permanent rates, consistent with RSA 378:29 and the recovery of Unitil’s prudently incurred rate case expenses stemming from this proceeding, to be filed by March 31, 2011. The May 1, 2011 rate changes represent an increase of 3.3 percent of total revenues or 12.3 percent of distribution revenues.
The projected May 1, 2012 distribution revenue increase of $1,509,376 is net of the recoupment and rate case expense recovery, which will end on April 30, 2012, plus a step adjustment for 75 percent of changes in non-reliability enhancement program (REP) net plant in service for the period January 1, 2011, through December 31, 2011, plus an adjustment for the REP and the vegetation management program (VMP). This step increase represents an increase of 1.0 percent to total revenues or 3.3 percent to distribution revenues.
| 3 | $2,019,355 for net plant in service additions in 2010, $1,250,000 for the Vegetation Management Program (VMP), $320,088 for 2011 pension/PBOP, ($500,000) to move ice storm to a surcharge, ($161,446) to remove cash working capital associated with contract release payments, ($315,861) to move cash working capital associated with other flow-through operating expenses to the external delivery charge (EDC) mechanism, and ($283,907) to move non-distribution portion of Commission’s assessment to the EDC mechanism. |
Exhibit 99.2
| DE 10-055 | - 6 - |
The projected May 1, 2013 distribution revenue increase of $1,865,624 is a combination of a step adjustment of $1,556,224 attributable to 75 percent of changes to non-REP net plant in service for the period January 1, 2012, through December 31, 2012, plus a step adjustment of $309,400 attributable to the REP. This represents an increase of 1.2 percent to total revenues or 4.0 percent to distribution revenues.
The projected May 1, 2014 distribution revenue increase of $1,430,828 is a combination of a step adjustment of $1,121,428 attributable to 75 percent of changes to non-REP net plant in service for the period January 1, 2013, through December 31, 2013, plus a step adjustment of $309,400 attributable to the REP. This represents an increase of 0.9 percent to total revenues or 2.9 percent to distribution revenues.
3. Supply Rate Changes (Section 3)
In conjunction with the step adjustment occurring on May 1, 2011, Unitil agreed to reduce its distribution base revenues by: (i) $161,446 to remove the cash working capital associated with contract release payments,4 (ii) $315,861 to remove the cash working capital associated with other flow-through operating expenses,5 and (iii) $283,907 to remove the non-distribution portion of the annual Commission assessment from operating expenses included in distribution revenues.6
| 4 | $9,280,377 was included in the calculation of the cash working capital component of rate base for contract release payments. Unitil’s contract release payments are costs paid to Unitil Power Corp. related to certain long-term power contracts that are recovered through Unitil’s stranded cost charge, which will terminate in 2011. Thus, in the May 1, 2011 step adjustment, Unitil agreed to remove from distribution revenues $161,446 (the cash working capital associated with these payments). |
| 5 | In the calculation of the cash working capital component of rate base, $18,156,559 was included for Other Flow-Through Operating Expenses. In the May 1, 2011 step adjustment, Unitil agreed to remove from distribution revenues $315,861 (the cash working capital associated with other flow-through operating expenses). Instead, effective May 1, 2011, Unitil will recover cash working capital associated with other flow-through operating expenses in its external delivery charge (EDC). |
| 6 | In the May 1, 2011 step adjustment, Unitil will remove from distribution revenues $283,907 (the Non-Distribution Portion of the annual Commission assessment). Instead, effective May 1, 2011, the recovery of the Non-Distribution Portion of the annual Commission Assessment will occur in Unitil’s EDC. |
Exhibit 99.2
| DE 10-055 | - 7 - |
4. Cost of Capital and Capital Structure (Section 4)
In determining the annual changes to distribution rate levels, the Settling Parties utilized an overall capital structure as set forth below, including a 9.67 percent return on equity. Except as otherwise specified in the Settlement, return on any deferred assets or liabilities arising during the term of the agreement will be calculated utilizing the weighted cost of capital specified. The Settling Parties agreed that during the term of the agreement, Unitil will maintain a capital structure that is similar, in terms of debt and equity component percentages, to the capital structure in Section 4.1 of the Settlement.7
| Component Percentage |
Cost | Weighted Cost |
||||||||||
| Common Equity |
45.45 | % | 9.67 | % | 4.39 | % | ||||||
| Preferred Stock Equity |
0.16 | % | 6.00 | % | 0.01 | % | ||||||
| Long-Term Debt |
51.53 | % | 7.60 | % | 3.92 | % | ||||||
| Short-Term Debt |
2.86 | % | 2.50 | % | 0.07 | % | ||||||
| Total |
100.00 | % | 8.39 | % | ||||||||
5. Earnings Sharing Agreement (Section 5)
The Settling Parties agreed that during the term of the agreement, an earnings sharing agreement including the use of an average return on equity (ROE) collar would be in effect, which would limit Unitil’s ability to propose changes to its permanent distribution rate level, and would result in the sharing of earnings if Unitil’s earned ROE for distribution is greater than ten percent for the five reporting calendar years (2011, 2012, 2013, 2014 or 2015).8 The initial period for the annual earnings sharing calculations is the calendar year ending December 31, 2011; thereafter, the annual earning sharing calculation shall be performed for the reporting
| 7 | The capital structure in Section 4.1 excludes short-term debt associated with flow through mechanisms (i.e., working capital associated with DS and EDC) and long-term debt associated with the December 2008 ice storm and the February 2010 wind storm. |
| 8 | During the term of the Settlement the calculation of Unitil’s earned ROE for distribution will utilize, in terms of debt and equity component percentages, the capital structure set forth in Section 4.1 of the agreement. |
Exhibit 99.2
| DE 10-055 | - 8 - |
calendar years of 2012, 2013, 2014 and 2015. Unless Unitil’s earned ROE for distribution is less than seven percent for a reporting calendar year, Unitil will not be allowed to propose a change to its permanent distribution rates for the term of the Agreement, except as otherwise provided for in the Settlement, or under RSA 374-G. If Unitil’s earned ROE for distribution is greater than ten percent for a reporting calendar year, then revenues equaling 75 percent of such difference will be recognized by Unitil as a deferred liability and an associated deferred asset, and refunded to customers over the 12-month period beginning on May 1 following the reporting calendar year (including May 1, 2016). The refund will be made through demand or energy usage charges, as applicable, for all rate classes. Finally, all calculations made under Section 5 of the Settlement will exclude the recoupment (pursuant to RSA 378:29).
6. Step Adjustments and Reporting Requirements (Section 6)
The rate changes specified under the Settlement reflected four distinct step adjustments and associated distribution revenue changes to take place on May 1st for four consecutive years beginning in 2011. In addition to adjustments to distribution revenues, the May 1, 2011 step adjustment includes 1) the first year phase-in of a VMP that was based in large part on the ECI study; 2) a $1,250,000 phase-in of additional expenditures for tree-trimming; and 3) an adjustment for increased pension and post-retirement benefits other than pension (PBOP) costs of about $320,000.
The three step adjustments proposed for implementation in 2012, 2013 and 2014 are based on Unitil’s forecasted increases to non-REP net plant in service of $6,430,668, $9,016,336 and $5,929,492 for the years 2011, 2012 and 2013, respectively. The revenue requirement for each of the 2012, 2013 and 2014 non-REP net plant in service calculations shall be subject to: 1) an annual maximum change in 75 percent of non-REP net distribution utility plant in service of $8 million, and 2) a cumulative change in 75 percent of non-REP net distribution utility plant in service of $20 million.
Exhibit 99.2
| DE 10-055 | - 9 - |
7. Reliability Enhancement Program and Vegetation Management Program (Section 7)
The Settling Parties agreed that Unitil would implement a reliability enhancement program. Beginning in calendar year 2011, Unitil will spend $1,750,000 annually in REP capital expenditures during the term of the Settlement. Unitil will also increase its annual REP operation and maintenance expense by $300,000 effective May 1, 2012. Additionally, each of the step adjustments for years 2012, 2013 and 2014 include $309,400 to recover the revenue requirements attributable to REP capital expenditures of $1,750,000 in the immediately preceding calendar year. The actual revenue requirements will be based on actual REP capital expenditures and will be subject to a cap of $2,000,000 on REP capital spending in any calendar year.
The
Settling Parties also agreed that Unitil will implement an augmented vegetation management program to incorporate a
5-year trim cycle on its multi-phase and single phase distribution systems, including 8-foot side and 15-foot top trim zones. The
revenue requirement for the permanent rates effective May 1, 2011, includes $200,000 of augmented VMP spending above the test year amount. The step adjustment effective May 1, 2011, provides for an additional increase of $1,250,000 to the
revenue requirement for annual VMP spending. The step adjustment effective May 1, 2012, provides for a further increase of $950,000 to the revenue requirement for annual VMP spending.
Unitil will provide an annual report to the Commission, Staff and OCA showing actual REP and VMP activities and costs for the previous calendar year and its planned activities and costs for the current calendar year. In addition, the Company will complete a number of fuse and
Exhibit 99.2
| DE 10-055 | - 10 - |
re-closer studies and reviews. The parties agreed that Staff will engage the services of a consultant to conduct a review of Unitil’s engineering and operations practices and procedures as they pertain to system reliability and operational efficiency improvement in various areas, funded by Unitil in an amount not to exceed $50,000, unless otherwise agreed to by the parties, which will be recoverable by the Company through the REP.
8. Storm Reserve Accrual and Recovery of Certain Other Storm Restoration Costs (Section 8)
The rate levels resulting from the distribution revenue changes specified in Section 2 of the Settlement include $400,000 annually for the major storm cost reserve, which will be used to recover costs associated with responding to and recovering from qualifying major storms.
Qualifying major storms include severe weather events causing 16 concurrent troubles (interruption events occurring on either primary or secondary lines) and 15 percent of customers interrupted, or 22 concurrent troubles, in either the Capital or Seacoast regions, as well as costs associated with planning and preparation activities in advance of severe weather if a qualifying major storm is likely occur. A qualifying major storm will be considered likely to occur if the power disruption index (“PDI”)9 from the Company’s professional weather forecaster reaches a PDI level of 210 or greater with a “high” (greater than 60 percent) level of confidence.
The Settling Parties agreed that the major storm cost reserve shall be effective for the recovery of costs associated with qualifying major storms occurring on or after July 1, 2010, the effective date of temporary rates. The Settling Parties also agreed that the major storm events of
| 9 | PDI levels are indices developed by Unitil’s weather forecast provider, WSI Corporation of North Andover, MA. A PDI level is a qualified indicator of both the possibility and severity of a particular weather event that results in the potential for customer outages. |
| 10 | A PDI level of 2 is defined by weather conditions meeting any combination of the following criteria – strong storms where isolated yet severe pockets are possible with moderate to severe lightning; icing between 3/8 to 3/4 inch accretion; less than 6 inches of heavy wet snow; soil moisture greater than 6 g/kg; sustained winds of 30 to 40 mph with many wind gusts between 40 to 50 mph, and with a few in excess of 50 mph. |
Exhibit 99.2
| DE 10-055 | - 11 - |
September 3-4, 2010 (Hurricane Earl) and December 26, 2010 (December 2010 Snow Event) qualify as events for which the reasonably incurred costs may be charged. The May 1, 2011 step adjustment removes $500,000 of December 2008 ice storm emergency restoration cost recovery from permanent rates which, together with the February 2010 wind storm costs, will be accounted for in a storm recovery adjustment factor (SRAF) surcharge. The $7,651,723 combined cost, inclusive of carrying charges, of the December 2008 ice storm and the February 2010 wind storm will be recovered on a levelized basis of $1,132,686 over a period of eight years. Based on test year unit sales, the SRAF surcharge will be set at $0.00096 per kWh until all storm costs have been fully recovered.
9. Rate Design (Section 9)
The rate design recommended by the Settling Parties and agreed upon in the Settlement approximates the marginal costs to serve as calculated by the Company and Staff. Although not all Settling Parties agreed on the use of this methodology for the purpose of allocating class revenue requirements, they agreed on the overall rate design as follows.
Regarding recovery of the permanent revenue deficiency, the Settling Parties agreed that the revenue requirement for the residential rate class, Rate D, shall be capped at 115 percent of Unitil’s overall average increase. The remainder of the permanent revenue deficiency shall be allocated to the commercial and industrial rate classes based on class marginal costs, up to their capped revenue target. The increase for residential Rate D shall be applied on an equal percentage basis between the existing customer charge and total energy charges. The customer charge for G2, G2 – kWh meter, G2 – quick recovery water heating and/or space heating shall be increased by approximately 50 percent to $16.50, $12.50, and $5.60, respectively, while the customer charges for G1 secondary and G1 primary shall be reduced by 20 percent to $87.09 and $51.61, respectively. The remaining revenue requirement shall be collected from demand or energy charges as applicable.
Exhibit 99.2
| DE 10-055 | - 12 - |
With respect to step adjustments, the Settling Parties agreed that the revenue requirement increase for the residential rate class, Rate D, shall be set at 115 percent of the Company’s overall average increase. The revenue requirement increase for all other rate classes shall be based on an equal percentage increase. The increases shall be collected through customer, demand or energy charges as applicable for all rate classes, except a) for the residential class where there will be no changes to the customer charge, and b) for outdoor lighting, where the increase shall applied on an equal percentage basis to all luminaire charges.
10. Other Tariff Changes (Section 10)
The Settling Parties agreed to recommend that the Commission approve Unitil’s proposed midnight outdoor lighting service and metal halide lighting service options.
11. Exogenous Events (Section 11)
During the term of the Settlement, the parties and Staff agreed that Unitil may adjust distribution rates upward or downward as a result of certain exogenous events, defined as a state initiated cost change,11 federally initiated cost change,12 regulatory cost reassignment,13 or
| 11 | State initiated cost change means any externally imposed changes in state or local law or regulatory mandates or changes in other precedents governing income, revenue, sales, franchise, or property or any new or amended regional, state or locally imposed fees, which impose new obligations, duties or undertakings, or remove existing obligations, duties or undertakings, and which individually decrease or increase Unitil’s distribution costs, revenue, or revenue requirement. |
| 12 | Federally initiated cost change means any externally imposed changes in the federal tax rates, laws, regulations, or precedents governing income, revenue, or sales taxes or any changes in federally imposed fees, which impose new obligations, duties or undertakings, or remove existing obligations, duties or undertakings, and which individually decrease or increase Unitil’s distribution costs, revenue, or revenue requirement. |
| 13 | Regulatory cost reassignment means the reassignment of costs and/or revenues now included in the generation, transmission, or distribution functions to or away from the distribution function by the Commission, FERC, NEPOOL, the ISO or any other official agency having authority over such matters. |
Exhibit 99.2
| DE 10-055 | - 13 - |
externally imposed accounting rule change,14 where the total distribution revenue impact (positive or negative) of all such events exceeds $200,000 in any calendar year beginning with 2011. Other exogenous events contemplated by the Settlement include excessive inflation.15 Each term year, Unitil shall file with the Commission, Staff and OCA a certification of exogenous events for the prior calendar year. Any exogenous event adjustment made during the term of the Settlement will remain in rates only until the effective date of the new rates determined in the Company’s first distribution rate proceeding following the end of the term of the Settlement.
| III. | SETTLEMENT POSITIONS OF THE PARTIES AND STAFF |
During the March 10, 2011 hearing, the Settling Parties offered testimony jointly through a panel of witnesses that included Mark H. Collin and Thomas P. Meissner, Jr. on behalf of Unitil, Kenneth E. Traum on behalf of the OCA, and Steven E. Mullen on behalf of Staff. To the extent the members of the panel testified to joint positions of the Settling Parties, that testimony is designated here as a position of the Settling Parties. Any positions or comments provided outside the joint presentation are attributed to the commenting party.
A. Settling Parties
Mr. Collin first addressed the highlights of the procedural history of this docket, then summarized the Settlement. Tr. at 14-16. According to Mr. Collin, Section 2 of the Settlement provides for a series of changes to Unitil’s permanent distribution revenues under a five-year rate plan and an earnings sharing agreement that will begin on May 1, 2011, and end on May 1, 2016. Members of the panel clarified that May 1, 2016 was designated the target date, rather than April 30, 2016, because there could be a potential rate adjustment under the earnings sharing mechanism that would result in an adjustment on May 1, 2016, in the event there were overearnings during the prior year period.
| 14 | Externally imposed accounting rule change shall be deemed to have occurred if the Financial Accounting Standards Board or the Securities and Exchange Commission adopts a rule that requires utilities to use a new accounting rule that is not being utilized by Unitil as of January 1, 2011. |
| 15 | Excessive inflation will be deemed to have occurred if the average rate of inflation for calendar years 2012, 2013 or 2014, measured by annual changes in the “Gross Domestic Product Implicit Price Deflator,” exceeds 4 percent. |
Exhibit 99.2
| DE 10-055 | - 14 - |
Mr. Collin noted that the initial change to Unitil’s permanent rates of approximately $5 million will occur on May 1, 2011, and that that amount will be adjusted based on a filing Unitil will make at the end of March seeking recovery of rate case expenses. In addition to the 2011 rate change, there are three additional step adjustments contemplated by the Settlement to occur on May 1, 2012 (just over $1.5 million), May 1, 2013 (almost $1.9 million), and May 1, 2014 ($1.4 million).16 Mr. Collin stated that the calculation of the initial increase in permanent distribution rates includes reconciliation to the recoupment of temporary rates currently in place, and a 2011 step adjustment.17 The initial increase currently represents about a 3.3 percent increase in total revenues that addresses a permanent revenue deficiency of a little over $6.6 million. Unitil initially requested an increase of $10.1 million. Of that amount, $6.6 million represents an agreed-upon compromise of approximately two-thirds of the initial request. Tr. at 17-19. The May 1, 2012 step adjustment includes removal of both the temporary rate recoupment and the recovery of rate case expenses from distribution revenues going forward, as the recovery of these costs will be completed in the first year. The 2012, 2013, and 2014 step adjustments represent a projected average annual increase of about 1.1 percent of total revenues in each year.18 Tr. at 20.
| 16 | Settlement at 5. |
| 17 | Settlement at 6. |
| 18 | Settlement at 12-14. |
Exhibit 99.2
| DE 10-055 | - 15 - |
Mr. Collin continued his summary on behalf of the parties and Staff by stating that Section 4 of the Settlement provides that Unitil will make a reduction of approximately $162,000 to distribution revenues, in conjunction with the first step adjustment on May 1, 2011, to reflect that it has completed the recovery of stranded costs related to industry restructuring and, as a result, no longer requires working capital associated with these obligations. In addition, there are certain working capital-related costs and Commission assessment-related costs totaling approximately $600,000, currently recovered in distribution rates that are associated with supply functions. The Settling Parties agreed to unbundle those costs from the distribution rates and move them into its existing supply-related recovery mechanism called the “external delivery charge” on a going forward basis.19 Tr. at 21. In determining the annual changes to distribution rate levels, the Settling Parties utilized a 9.67 percent return on equity,20 the same as that authorized for Unitil in its last distribution rate proceeding. Tr. at 22.
Mr. Collin reported that the earnings sharing agreement set forth in Section 5 is a core component of the Settlement and includes the use of an average return on equity collar that will remain in place during the entire five-year rate plan. The earnings sharing mechanism limits the Company’s ability to propose changes to distribution rates and will result in a sharing of earnings with customers if Unitil’s earned ROE for distribution exceeds 10 percent. If Unitil’s earned ROE for distribution exceeds 10 percent, then revenue equaling 75 percent of such difference will be refunded to customers over the following 12-month period beginning May 1st of that year. The refund will be applied proportionally to all customer classes.21 Finally, unless Unitil earns less than 7 percent, it will not propose a change to its permanent distribution rates for effect prior to May 1, 2016. Tr. at 23.
| 19 | Settlement at 8-9. |
| 20 | Settlement at 9-10. |
| 21 | Settlement at 10-12. |
Exhibit 99.2
| DE 10-055 | - 16 - |
Mr. Collin represented that Section 6 of the Settlement provides for four step adjustments to take place on May 1st in four consecutive years beginning in 2011. In addition to adjustments to distribution revenues, the May 1, 2011 step adjustment includes: 1) the first year phase-in of a VMP that was based on the ECI study; 2) a $1,250,000 phase-in of additional expenditures for tree-trimming; and 3) an adjustment for increased pension and PBOP costs of about $320,000. Additionally, the storm cost recovery, which had initially been included in distribution rates, was removed and replaced with a specific ratemaking reconciling mechanism that addresses storm costs.
Finally, adjustments are proposed where certain costs were reallocated from distribution rates to the supply function. Mr. Mullen pointed out that the “75 percent of non-REP net plant” provision refers to the non-revenue-producing portion of capital additions that are expected in each of those years. Mr. Collin emphasized that that provision applies to the 2012, 2013, and 2014 step adjustments. The projected step adjustments reflect projected increases for the net plant at 75 percent of non-REP, additional VMP, and REP O&M spending, including an additional $900,000 dedicated to vegetation management; a $300,000 increase in O&M spending related to the REP spending; and an annual increase in capital spending of $1,750,000 for a REP in 2012, 2013 and 2014. Mr. Traum pointed out that the Settlement recognizes roughly $735,000 in test year tree-trimming expenses for the REP and the VMP.22 Tr. at 24-26.
Mr. Collin stated that Section 7 of the Settlement provides for implementation of a REP. Beginning in 2011, the Company will spend $1,750,000 annually in capital spending in the REP and will increase annual REP O&M spending by $300,000 on an annual basis beginning in 2012. The Settlement also provides that Unitil will augment its existing VMP based upon the program by Unitil’s consultant, ECI, as modified and agreed to by the Settling Parties during the course of
| 22 | Settlement at 12-14. |
Exhibit 99.2
| DE 10-055 | - 17 - |
this proceeding. Mr. Mullen added that the components of these programs and the activities to be performed are similar to programs currently in existence at Granite State Electric Company and Public Service Company of New Hampshire. Mr. Collin noted that the phase-in of the VMP spending reflects $200,000 of augmented VMP spending above test year amounts included in the base revenue effective May 1, 2011. The initial 2011 increase is a $200,000 phase-in of VMP, followed by additional increases of $1,250,000 and $950,000 included in the step adjustments for May 1, 2011 and 2012, respectively. Tr. at 27. These increases account for Unitil moving to a five-year trim cycle on both its multi-phase and single-phase plant, hiring professional arborists, and implementing a comprehensive hazard tree removal program. Tr. at 38. Once fully phased in, the augmented VMP spending will reflect a level of about a $2.4 million increase over test year distribution tree-trimming expenses of approximately $736,000, or approximately three times the current VMP expenditure. Finally, Section 7 of the Settlement requires the Company to complete a number of engineering and operations studies and proposes that Staff engage the services of a consultant to conduct a review of the Company’s engineering and operations practices as they pertain to system reliability and operation efficiency improvements. Funding for a Staff consultant is capped at $50,000, to be paid for by Unitil and recovered through REP O&M expenses in the step adjustments.23 Tr. at 28.
According to Mr. Collin, under Section 8 of the Settlement, Unitil will be authorized to establish a major storm cost reserve funded at a level of $400,000 annually. Similar storm reserve mechanisms are currently authorized for Public Service Company of New Hampshire and Granite State Electric. The storm reserve will be used to recover costs, including pre-storm preparation costs, associated with qualifying major storms occurring on or after July 1, 2010.
| 23 | Settlement at 14-16. |
Exhibit 99.2
| DE 10-055 | - 18 - |
The Settling Parties agreed that the major storm event of September 3 and 4, 2010 (Hurricane Earl) and the December 26, 2010 snow event qualify for reasonable cost recovery through the major storm reserve. The Settlement also provides for recovery of costs incurred from the December 2008 ice storm and the February 2010 wind storm through a storm cost recovery adjustment surcharge. Approximately $7.6 million of combined costs for these two storms, inclusive of carrying charges, will be recovered on a levelized basis of $1.1 million a year over a period of eight years. Mr. Mullen pointed out that the return accruing on those costs is at Unitil’s cost of debt and does not include any equity return.24 Tr. at 29-30.
Mr. Traum presented Section 9 of the Settlement concerning Rate Design, covering two components: 1) interclass revenue allocation, and 2) intra-class allocation of costs for customer charges, energy, and demand charges. The Settlement provides that increases to the residential class will be capped at 115 percent of the average increase for the permanent rate increase and for each step adjustment. The remainder of the revenue deficiencies will be allocated to the C&I classes based on class marginal costs up to their capped revenue targets for permanent rate purposes. For the step adjustments, the increases to C&I rates will be based on equal percentage allocation. The permanent increase for the residential class will be applied as an approximately equal percentage increase of 22 percent to the customer charge and the energy charges effective on May 1, 2010. According to Mr. Traum, another objective of the Settling Parties was to retain the one-half cent per kilowatt-hour spread between the initial and tail blocks, with the tail block being higher than the initial block, as it is now. For the step adjustments, residential increases will be applied only to usage charges. The remaining revenue requirements for the C&I classes will be collected from demand and energy usage charges. Recoupment of the difference between temporary rates and permanent rates will be included in the 2011 step adjustment and will be collected on a per kWh basis from the residential class.25 Tr. at 30-33.
| 24 | Settlement at 17-18. |
| 25 | Settlement at 19-20. |
Exhibit 99.2
| DE 10-055 | - 19 - |
Mr. Collin discussed additional tariff changes proposed in Section 10 for outdoor lighting service options. One proposal is to offer a midnight outdoor lighting service option that would allow Unitil to implement a photocell-type lighting option that would turn lights off at midnight, resulting in lower energy usage, and bring the Company in compliance with the New Hampshire Dark Sky policy. A second change concerns a proposed metal halide lighting service option. According to Mr. Collin, the federal Energy Policy Act of 2005 now prohibits the manufacture or import into the United States of mercury vapor for use in outdoor lighting applications. As a result, the Company proposes to offer metal halide lighting as a viable alternative white light option.26 Tr. at 33.
Mr. Collin continued his summary of the Settlement by stating that the exogenous events contemplated in Section 11 would allow Unitil to adjust its distribution rates upward or downward during the five-year term of the rate plan and earnings sharing agreement. Exogenous events are defined to include externally-imposed changes (such as changes in state tax law or assessments; federal regulatory, tax law, or assessment changes; and externally imposed accounting rule changes) that cause a significant change in the Company’s costs. The Company would be required to make a filing and demonstrate that the exogenous event(s) had an impact on its cost structure, that the cost impact exceeds a threshold level of $200,000, and that distribution rates should be adjusted as a result. Mr. Mullen pointed out that the exogenous events provision contemplated under the Settlement is similar to those included in multi-year rate agreements the Commission has approved with Public Service of New Hampshire and Granite State Electric
| 26 | Settlement at 20. |
Exhibit 99.2
| DE 10-055 | - 20 - |
Company. Mr. Traum clarified that under the terms of the Settlement, Unitil will not seek a rate increase under this section during any period of time it is required to return overearnings to customers pursuant to Section 5.1.3 of the Settlement. Mr. Collin added that there is also a provision that would allow Unitil to file for a change in its distribution rates if there is a period of “excess inflation.” Excess inflation is measured by annual changes in the gross domestic product implicit price deflator and defined as inflation that exceeds 4 percent. The amount of increase to distribution revenue shall be equal to the amount by which the average inflation rate exceeds 4 percent, multiplied by actual O&M expense in the calendar year to which it applied, beginning in calendar year 2012. Actual adjustment to rates, therefore, would not take place until 2013. Any adjustment would exclude O&M expenses recovered under Unitil’s REP.27 Tr. at 34-36.
Unitil, OCA and Staff witnesses each stated that they believe the Settlement is just and reasonable and serves the public interest. Tr. at 47.
B. OCA
The OCA requested that the Commission approve the Settlement, noting that the agreement is the result of very productive and cooperative settlement discussions in this docket. Tr. at 67
C. Staff
Staff stated that it had reviewed Unitil’s filing and discovery responses to assess the Company’s revenue requirements and the need for adjustments to current rates, and believes the proposed Settlement represents a just and reasonable resolution of the issues raised in this docket. Staff added that the proposed adjustments are intended to enable the Company to meet its obligation to improve its vegetation management and reliability enhancement programs, continue investments in its electrical system, account for certain changes in pension and PBOP
| 27 | Settlement at 21-22. |
Exhibit 99.2
| DE 10-055 | - 21 - |
discount rates and actuarial estimates, and address the fact that sales have not been keeping up with the increase in operational expenses in the five years since Unitil’s last rate case. Staff affirmed that the proposed rate design results in fair and reasonable adjustments to current rates for the various customer classes, particularly as the Settlement provides some limits on those adjustments. Staff noted that the Settlement covers a range of issues, including normal rate case issues, such as revenue requirements and reliability issues, including the follow-up obligations stemming from the Commission’s 2008 ice storm review. The Settlement also provides for rate stability and a sharing of potential risks due to changes in Company earnings, since Unitil cannot petition for a new rate case during the five-year term of the agreement. The Settlement also allows Unitil to recover costs for certain non-revenue-producing capital investments that may be needed during those five years. Staff maintained that what the parties tried to accomplish through the Settlement is the creation of a realistic and practical opportunity for Unitil to earn a reasonable return over a five-year period by providing for some minimal step adjustments to rates for certain expenses, such as improvements in the reliability enhancement and vegetation management programs, while setting parameters in the event earnings increase or decrease beyond forecasted expectations. Tr. at 68-69.
D. Unitil
Unitil stated that the Company concurred and appreciated the comments of the OCA and Staff, and the efforts of all parties to reach a fair and equitable agreement. Unitil recommended that the Commission approve the Settlement.
Exhibit 99.2
| DE 10-055 | - 22 - |
| IV. | COMMISSION ANALYSIS |
RSA 378:5 authorizes the Commission to approve new and higher utility rates upon determining that the proposed rates, fares, and charges are just and reasonable. To make such a determination, the Commission must balance the customers’ interest in paying no higher rates than are required with the investors’ interest in obtaining a reasonable return on their investment. Eastman Sewer Company, Inc., 138 N.H. 221, 225 (1994). In this way the Commission meets its obligation to serve as arbiter of the interests of customers and those of regulated utilities. See RSA 363:17-a; see also Public Service Company of New Hampshire, Order No. 24,919 (Dec. 5, 2008) at 7-8; and Public Service Company of New Hampshire, Order No. 25,123 (June 28, 2010) at 28.
Pursuant to RSA 541-A:31, V(a), informal disposition may be made by stipulation, agreed settlement, consent order or default, of any contested case at any time prior to the entry of a final decision. New Hampshire Code of Administrative Rules Puc 203.20(b) requires the Commission to approve disposition of a contested case by settlement “if it determines that the result is just and reasonable and serves the public interest.” In general, the Commission encourages parties to attempt to reach a settlement of issues through negotiation and compromise as it is an opportunity for creative problem solving, allows the parties to reach a result more in line with their expectations, and is often a more expedient alternative to litigation. See Unitil Energy Systems, Order No. 24,677 (Oct. 6, 2006) at 17 (citations omitted); see also EnergyNorth Natural Gas, Inc. d/b/a National Grid NH, Order No. 24,972 (May 29, 2009) at 48. However, even where all parties join a settlement agreement, the Commission must independently determine that the result comports with applicable standards. Unitil Energy Systems, supra at 18. The issues must be reviewed, considered and ultimately judged according to standards that provide the public with the assurance that a just and reasonable result has been reached. Concord Electric Company, 87 NHPUC 694, 708, Order No. 24,072 (2002), quoting from Concord Electric Company, 87 NHPUC 595, 605, Order No. 24,046 (2002), and orders cited therein. Since this is a rate case, the underlying standard to be applied is whether the resulting rates are just and reasonable, as required by RSA 378:7.
Exhibit 99.2
| DE 10-055 | - 23 - |
We note, as we have previously, that the process leading up to a proposed settlement is a relevant factor in determining whether the settlement should be approved. EnergyNorth Natural Gas, Inc. d/b/a National Grid NH, Order No. 24,972 (May 29, 2009) at 48; see also National Grid plc, Order No. 24,777 (July 12, 2007) at 65. Specifically, a basis for concluding that the results of the settlement are reasonable and in the public interest is established where the parties involved in a docket leading to a settlement agreement represented a diversity of interests, and there is a demonstration that issues were diligently explored and negotiated at length. EnergyNorth Natural Gas, Inc. d/b/a National Grid NH, Order No. 24,972 (May 29, 2009) at 48.
A. Petition for General Distribution Rate Increase
The Company’s petition for a general distribution rate increase indicates that prior to the April 15, 2010 filing, its return on equity was 5.98 percent in 2008 and 5.35 percent in 2009, well below the Company’s last authorized return of 9.67 percent. According to the petition, the Company’s return would have eroded further, absent some form of rate relief, as customer and revenue growth have not kept pace with operating expenses and rate base additions have been incurred since the Company’s last distribution base rate case was decided in 2006.
We note that both Staff and the OCA recommended rate increases for the Company in their pre-filed testimony, recognizing that the Company needed an increase in its revenue requirement in order to have a reasonable opportunity to earn its authorized return.
We find that the Company has demonstrated in its petition a need for a general rate increase in order to earn a reasonable return. We turn now to the merits of the Settlement reached in this case among the Company, Staff and the OCA to resolve the issues raised by the petition and achieve a negotiated result that addresses the Company’s need for a rate increase.
Exhibit 99.2
| DE 10-055 | - 24 - |
B. Overall Distribution Revenue Increase
The Settlement states that while the parties were unable to agree on each individual component in the overall distribution revenue level, they were able to agree on an overall distribution revenue level and rate design. Specifically, the parties agreed to a distribution revenue increase of approximately $5.0 million on May 1, 2011, and further adjustments through step increases as outlined below. The amount of the initial increase represents a negotiated compromise encompassing various components intended to establish a rate base that will enable the Company to earn a reasonable return. The proposed increase covers a number of cost categories, demonstrating that the Settling Parties were attempting to address a variety of needs through the terms of the Settlement.
The Settlement calls for an overall initial distribution revenue increase of approximately $5 million, effective on May 1, 2011, including reconciliation back to July 1, 2010, the date on which temporary rates were implemented pursuant to Order No. 25,124 (June 29, 2010). The Settlement further proposes a series of three annual step adjustments following the initial increase, by which distribution revenues would increase by an additional approximately $4.8 million, cumulatively, by May 1, 2014. Thus, by that date, the increase to 2009 test year revenues would total approximately $9.8 million, introduced on a stepped basis over a four-year period ending April 2014, compared to the Company’s request in its updated filing of April 6, 2010, as supplemented on November 4, 2010, of $10.1 million in distribution base revenues plus a series of additional adjustments totaling $7.2 million, for an overall increase of $17.3 million.
Exhibit 99.2
| DE 10-055 | - 25 - |
The distribution revenue increase to take effect of May 1, 2011 consists of the following components:
| Permanent Revenue Deficiency |
$ | 6,611,437 | ||
| Temporary Rates |
(5,158,845 | ) | ||
| Step Increase |
2,328,228 | |||
| Temporary Rate Recoupment (back to July 1, 2010) |
1,210,494 | |||
| Total |
$ | 4,991,314 | ||
Further discussion of some of the above components is provided in the sections that follow.
C. Step Adjustments
The Settlement includes a series of four step adjustments proposed for implementation over the course of four years and intended to allow recovery of certain discrete capital costs that generally fall outside the scope of normal operating expenses.
We have previously approved step adjustments to base rates as a means of ensuring that a regulated utility retains its ability to earn a reasonable rate of return after implementing large capital projects that increase the utility’s rate base after a test year. See, e.g., Eastman Sewer Company, Inc., Order No. 24,989 (July 24, 2009) at 7-8; Forest Edge Water Co., Order No. 25,017 (Sept. 23, 2009) at 8. We also have approved a method for a utility to seek annual increases based on additions to its plant in service without filing for a base rate increase. See Aquarion Water Company of New Hampshire, Order No. 25,019 (Sept. 25, 2009).
The initial step adjustment of $2,328,228 is proposed to take effect simultaneously with the general revenue increase on May 1, 2011, and is intended to provide for additional cost recovery for net plant in service additions for the period January 1 through December 31, 2010, enhancements to the Company’s vegetation management program, increased 2011 pension/PBOP costs resulting from a decrease in discount rates and increased amortization of actuarial losses, and certain storm costs. Also included in the initial step increase are certain
Exhibit 99.2
| DE 10-055 | - 26 - |
accounting adjustments addressing contract release payments, flow-through operating expenses and the Commission utility assessment. The subsequent three step adjustments proposed for implementation in 2012, 2013 and 2014 are based on the Company’s forecasted increases to Non-REP Net Plant in Service in the amounts of $6,430,668, $9,016,336, and $5,929,492 for the years 2011, 2012 and 2013, respectively. Each step will be subject to detailed reporting requirements and reconciliation under the terms of the Settlement. In addition, the revenue requirement for each of the 2012, 2013 and 2014 non-REP net plant in service calculations shall be subject to: 1) an annual maximum change in 75 percent of non-REP net distribution utility plant in service of $8 million, and 2) a cumulative change in 75 percent of non-REP net distribution utility plant in service of $20 million.
We note that we do not, at this time, approve the amount of the step adjustments identified in the Settlement for 2012, 2013 or 2014, as each is subject to detailed accounting and reconciliation based on future filings. The Settlement contemplates that the Company will file by the last day of February of the years 2012, 2013 and 2014 financial documentation supporting the actual changes to its net plant in service in the preceding calendar year, as well as the net plant in service as of December 31 for each year, and will exclude capital additions made under the REP. The information filed by the Company will be subject to review by the Staff and the OCA and Commission approval to ensure that the plant additions claimed by the Company are, in fact, used and useful and in service. The Settlement also provides that, in the event Staff or the OCA are not in agreement with the Company’s calculations or any input to the calculations, they may request that we hold a hearing to determine whether the step adjustment should take effect as scheduled and as calculated by the Company.
Exhibit 99.2
| DE 10-055 | - 27 - |
We find that this process is a reasonable method to allow for a more timely recovery of assets in service without resort to a full rate proceeding. We also find, as we have found in prior cases, that the process as outlined complies with RSA 378:30-a, which prohibits recovery on those items not yet in service, as it requires review of plant additions actually completed and in service. See, e.g., Aquarion Water Company of New Hampshire, Order No. 25,019 (Sept. 25, 2009) at 17; Public Service Company of New Hampshire, Order No. 25,123 (June 28, 2010) at 32. We further note that the step adjustment approach permits review of the Company’s actual implementation of capital additions and related cost recovery over the course of a five-year period, thus ensuring that any changes in economic or operational circumstances during the term of the Settlement can be taken into account in a timely manner.
D. Cost of Capital and Capital Structure
The proposed increases, according to the Settlement, were calculated using an overall rate of return of 8.39 percent, based on an overall capital structure that includes approximately 46 percent equity and 54 percent debt, embedded cost rates for debt and preferred stock, and a 9.67 percent return on equity. The return on equity appears reasonable when compared to the range of return on equity estimates provided by Staff and OCA (9.0%) and the Company (10.70%). See Wilson Testimony at 41-42; Traum Testimony at 5; and Hadaway Testimony at 3. We also note that the ROE is the same as that authorized for the Company in its last base rate case, and the same as that authorized in recent settlements covering the Public Service Company of New Hampshire electric distribution rates and EnergyNorth gas distribution rates. See Public Service Company of New Hampshire, Order No. 25,123 (June 28, 2010) at 9, 17; EnergyNorth Natural Gas, Order No. 25,202 (March 10, 2011) at 19. We find that the component percentages of debt and equity along with their respective cost rates provide a reasonable overall cost of capital for purposes of this agreement.
Exhibit 99.2
| DE 10-055 | - 28 - |
E. Reliability Enhancement and Vegetation Management Programs
A substantial portion of the step adjustments proposed in the Settlement is intended to enable the Company to recover capital expenditures toward an expanded reliability enhancement program (REP) and an augmented vegetation management program (VMP). Revenue requirements will be based on actual REP capital expenditures and subject to a cap of $2,000,000 on REP capital spending in any of the 2012, 2013 and 2014 calendar years. The augmented VMP will incorporate a 5-year multi-phase and 5-year single phase trim cycle with 8-foot side and 15-foot top trim zones, and will provide that deadwood be removed outside the trim zone where service could be impacted. The revenue requirement for the permanent rates effective May 1, 2011, includes $200,000 of augmented VMP spending above the test year amount while the step adjustments effective May 1, 2011 and May 1, 2012, provide for additional increases to the revenue requirement of $1,250,000 and $950,000, respectively. The parties noted at hearing that the augmented REP and VMP stem, in part, from the Commission’s December 2008 ice storm review and recommendations for improved reliability and vegetation management.
On or before the last day of February of each year, the Company will provide an annual report to the Commission, Staff and the OCA showing actual REP and VMP activities and costs for the previous calendar year and planned activities and costs for the current calendar year. Actual and planned costs will be reconciled along with the revenue requirements associated with actual and planned capital additions and expenses, and subject to Commission approval.
Exhibit 99.2
| DE 10-055 | - 29 - |
The Settlement further provides that the Company will complete certain fuse and recloser studies and reviews on its distribution circuits, funded as part of the Company’s ordinary operations and maintenance expenses. Any resulting fuse and recloser changes or additions will be charged to the REP. At hearing, the Company testified that the studies and reviews are intended to establish a baseline with respect to the causes of, and solutions to, reliability issues.
The Settlement also provides that Staff will engage the services of a consultant to conduct a review of the Company’s engineering and operations practices and procedures as they pertain to system reliability and operational efficiency improvement. The agreement sets out specific areas to be reviewed, including, inter alia, engineering practices, procedures, and standards; load forecasting; planning criteria, and inspection and corrective process and practices. The review is intended to be conducted as an informal dialogue exchange between the Company, the consultant and Staff. The consultant’s portion of the study will be funded by Unitil in an amount not to exceed $50,000, unless otherwise agreed to by the parties, and will be recoverable through the REP. Upon completion of the study, Staff will submit a report to the Commission.
Similar to the proposed distribution revenue step adjustments, we find that the proposed recovery mechanisms and review process for the anticipated REP and VMP enhancements are reasonable for ensuring effective reliability and vegetation management, although we do not at this time approve the amounts of the increases called for in the Settlement.
F. Major Storm Cost Reserve
The Settlement sets out provisions for a major storm cost reserve that will enable the Company to recover costs associated with responding to and recovering from qualifying major storms occurring on or after July 1, 2010, through the term of the Settlement. The agreement specifies the criteria for qualifying storms and the planning and preparation activities that may lead to recoverable costs. In the event the Company incurs extraordinary expenditures to prepare for or recover from a storm or natural disaster that does not meet the major storm criteria, the
Exhibit 99.2
| DE 10-055 | - 30 - |
Company may petition the Commission for cost recovery through the major storm cost reserve. According to the agreement, the major storm events of September 3-4, 2010 (Hurricane Earl) and December 26, 2010 (December 2010 Snow Event) qualify as events for which reasonably incurred costs may be charged to the major storm reserve. The specific amount of recovery was not agreed upon, however, and the Company acknowledges that it has the burden to demonstrate the reasonableness of its expenditures.
The Settlement further provides that the May 1, 2011 step adjustment will remove from permanent rates $500,000 of the emergency restoration costs stemming from the December 2008 ice storm. Instead, recovery of the $7,651,723 combined costs of the December 2008 ice storm and February 2010 wind storm will be recovered on a levelized basis over an eight-year period through a storm recovery adjustment factor (SRAF) surcharge. Any unamortized balance will accrue carrying charges at an annual rate of 4.52 percent (equaling Unitil’s cost of debt of 7.60 percent, net of deferred taxes). Based on test year unit sales, the SRAF surcharge will be set at $0.00096 per kWh until all storm costs have been fully recovered.
The Company will reconcile revenue billed through the surcharge and the amount subject to recovery and file the results with the Commission no later than 60 days after the conclusion of the recovery period. The disposition of any remaining balance will be subject to Commission review and approval.
Given the increase in recent years of major storm events affecting electric customers in New Hampshire, we find the proposed mechanism and review process pertaining to storm cost recovery to be reasonable.
Exhibit 99.2
| DE 10-055 | - 31 - |
G. Earnings Sharing
The Settlement includes an earnings sharing agreement that limits the Company’s ability to propose changes to its permanent distribution rate level prior to May 1, 2016, and will permit it to retain any earnings it achieves between the allowed ROE of 9.67 percent and 10 percent. In the event the Company’s ROE exceeds 10 percent, revenues equaling 75 percent of the difference will be recognized as a deferred liability and an associated deferred asset, and refunded to customers over the 12-month period beginning on May 1 following the reporting calendar year. The refund will be applied proportionally to all customer classes through demand or energy usage charges, as applicable, except for outdoor lighting, where the decrease will be applied on an equal percentage basis to all luminaire charges. Conversely, if the Company’s earned ROE for distribution falls below 7 percent for a reporting calendar year, it may petition for a change to its permanent distribution rates.
We find that the earnings sharing provision provides important protections to both customers and the Company. We note that the agreed-upon ROE of 9.67 percent continues to represent an appropriate return for investors facing the risks associated with a franchised electric distribution utility. See, e.g., Public Service Company of New Hampshire, Order No. 25,123 (June 28, 2010) at 33-34. Furthermore, by operation of the earnings sharing provision, the Company is allowed the opportunity to earn and retain more than 9.67 percent, thus enhancing its ability to attract investment. Customers, however, are protected from over-earning because the Company will be required to share any earnings over 10 percent. The Company is likewise protected from sustained under-earning by being permitted to petition for new rates if its earnings fall below seven percent for a reporting calendar year.
Exhibit 99.2
| DE 10-055 | - 32 - |
H. Rate Design
The rate design called for during the term of the Settlement will cap the revenue requirement and step adjustments for the residential rate class, Rate D, at 115 percent of the Company’s overall average increase. The remainder of the permanent revenue deficiency will be allocated to the commercial and industrial rate classes based on class marginal costs, up to their capped revenue target, while the remainder of the step adjustment increases will be allocated on an equal percentage basis. The step adjustment increases shall be collected through customer, demand or energy charges as applicable for all rate classes, except a) for the residential class where there will be no changes to the customer charge, and b) for outdoor lighting, where the increase shall be applied on an equal percentage basis to all luminaire charges.
We find the proposed rate design to be reasonable. Residential customers are protected from a dramatic increase in their rates, while commercial and industrial customers are not being asked to unduly subsidize residential customers. The overall impact of the proposed changes in the distribution rates stemming from the Settlement is an increase of approximately 6.1 percent (inclusive of the initial step adjustment), effective May 1, 2011, for an average residential customer using 629 kilowatt-hours a month. Increases associated with the step adjustments to be effective May 1, 2012, 2013 and 2014 are estimated to be 1.5%, 1.2% and 1.2%, respectively. See Settlement at Attachment 5 for these percentages as well as for impacts to other rate classes. We conclude these are reasonable increases.
I. Exogenous Events
As with other multi-year settlements we have approved in the past, the one at issue here allows for certain future rate adjustments as a result of changes beyond the control of the parties to the agreement. We understand that this provision is intended to allow Unitil to adjust its rates
Exhibit 99.2
| DE 10-055 | - 33 - |
as a result of an event or series of events that has a total distribution revenue impact in a given year of $200,000 or more. We further understand that while only Unitil may request an increase in its rates, any of the Settling Parties may contest an increase sought by the Company or request a decrease in rates as a result of exogenous events. Thus, the Settlement properly places the burden on Unitil to monitor the effects of events that cause its costs to rise, though it may have little or no direct control over those costs. Moreover, Unitil is not permitted to request an increase in its rates due to an exogenous event or events if it is earning an ROE of more than 10 percent. As a result, customers are protected from any over-earning by the Company being compounded by external changes. We find this provision reasonable and appropriate.
J. Other Tariff Changes
The Settlement includes a recommendation that the Commission approve Unitil’s proposed midnight outdoor lighting and metal halide lighting service options, as presented in Attachment 3 to the Settlement. The Company testified at hearing that the proposed midnight outdoor lighting option would bring it into compliance with the New Hampshire Dark Sky policy by allowing it to implement a photocell type lighting option that would turn lights off at midnight. As a result, the proposed tariff changes would reflect lower energy usage. With respect to the metal halide lighting option, the Company testified that the Energy Policy Act of 2005 no longer permits manufacture or import of mercury vapor, so the Company proposes to add metal halide lighting service as an alternative white light option for customers.
We observe that while there was no testimony provided on the record with respect to the reasonableness of the proposed metal halide lighting rates, neither were there any objections to the Company’s proposal, which we note is an optional lighting choice for commercial and industrial customers. We find that both proposals are reasonable and consistent with the State’s energy policies, including compliance with federal requirements.
Exhibit 99.2
| DE 10-055 | - 34 - |
K. Recovery of Rate Case Expenses
On March 31, 2011, in accordance with the terms of the Settlement, Unitil filed for Commission review and approval its rate case expenses incurred in connection with this proceeding. In its filing, the Company requests recovery of $406,031 in expenses over a one-year recovery period at a rate of $0.00034 per kilowatt-hour. On April 22, 2011, Staff filed a memorandum notifying the Commission that Staff audit results are still pending and recommending that the Company be granted permission to start recovering its rate case expenses at the requested rate, effective May 1, 2011. Staff further recommended that the recovery rate and period be deemed preliminary, pending the final result of the Staff audit and any further discussions among Staff, Unitil and the OCA regarding the expenses. Staff notes in its memorandum that the OCA consented to the recommended approach because it provides a full opportunity for parties to review the Company’s filing and Staff’s audit and to take any position on the filing at a future time.
We find Staff’s recommended approach to preliminary recovery with reconciliation as necessary upon completion of Staff’s audit to be reasonable.
L. Motions for Confidential Treatment
The Right-to-Know Law provides each citizen with the right to inspect public information in the possession of the Commission. See RSA 91-A:4, I. The statute contains an exception, invoked here, for “confidential, commercial or financial information.” RSA 91-A:5, IV. To determine whether information should be protected from public disclosure, we apply a three-step analysis. See Lambert v. Belknap County Convention, 157 N.H. 375 (2008); and Lamy v. New Hampshire Public Utilities Commission, 152 N.H. 106 (2005).
Exhibit 99.2
| DE 10-055 | - 35 - |
First, we determine whether the information is confidential, commercial or financial information “and whether disclosure would constitute an invasion of privacy.” Union Leader Corp. v. New Hampshire Housing Finance Authority, 142 N.H. 540 (1997) at 552 (emphasis in original, citations omitted). If no privacy interest is at stake, our analysis is complete and disclosure is required. If a privacy interest is at stake, the “asserted private confidential, commercial, or financial interest must be balanced against the public’s interest in disclosure … since these categorical exemptions mean not that the information is per se exempt, but rather that it is sufficiently private that it must be balanced against the public’s interest in disclosure.” Id. at 553. Disclosure that informs the public of the conduct and activities of its government is in the public interest; otherwise disclosure is not warranted.
The Commission’s administrative rule Puc 203.08 is designed to facilitate the balancing test required by New Hampshire case law. The rule requires petitioners to: (1) provide the material for which confidential treatment is sought or a detailed description of the types of information for which confidentiality is sought; (2) reference specific statutory or common law authority favoring confidentiality; and (3) provide a detailed statement of the harm that would result from disclosure to be weighed against the benefits of disclosure to the public. Puc 203.08(b).
1. Exhibit No. 5.
On March 28, 2011, Unitil filed a motion for confidential treatment with respect to its response to a Staff data request that was offered as an exhibit at the March 10, 2011 hearing. See Exhibit 5. With its motion, the Company attached a redacted copy of the document. The
Exhibit 99.2
| DE 10-055 | - 36 - |
document for which the Company seeks confidential treatment is the final report prepared by the Company’s consultant ECI regarding Unitil’s vegetation management practices in New Hampshire and strategic planning recommendations. In its motion, Unitil asserts that the methodology, forms and techniques used to complete the report are proprietary and confidential to ECI, and that the results of the study, including all data and reports, are considered proprietary to ECI. On behalf of ECI, Unitil seeks confidential treatment under RSA 91-A:5(IV) for records pertaining to “confidential, commercial or financial information.” Specifically, Unitil seeks confidential treatment of certain tables contained within the ECI report that depict results that ECI obtained from its analysis, stating that the tables at issue were developed by ECI for the purpose of efficiently serving all of its clients and, in this instance, performing its assigned responsibilities in its engagement with UES, thus representing its proprietary intellectual property. Unitil further asserts that disclosure of the information would harm ECI’s ability to protect its work produce and the Company’s ability to contract for and obtain consulting services at a competitive price in the future.
We note that while the Company has requested confidential treatment of certain tables contained in the ECI report, the request does not extend to protection of the text of the report itself. Based on our review, the text provides a substantial amount of information pertaining to the vegetation management principles supporting the conclusions that are incorporated into the Settlement in this proceeding. In the absence of any objection to the motion for confidential treatment that might assert a benefit of disclosure to the public and applying the standards outlined above, we grant the motion with respect to Exhibit 5, as submitted at the March 10, 2011 hearing.
Exhibit 99.2
| DE 10-055 | - 37 - |
2. Rate Case Expense Filing.
On March 31, 2011, Unitil filed a motion for confidential treatment of certain information contained in its rate case filing. Specifically, Unitil seeks protection of billing information for consultants and attorneys who performed work for the Company in the course of this proceeding; the identification of bid responders and their cost proposals as presented in Attachment 5 to the Settlement; and the billing rates and cost projections contained in Attachment 6 to the Settlement.
Upon review of the information submitted, we note that redacted versions of all the documents are available in the public file and contain much information concerning the underlying matters, including details of the hours billed to the Company for various services, and that the information for which confidential treatment is sought contains competitively sensitive billing information not otherwise publicly available. In the absence of any objection to the motion for confidential treatment that might assert a benefit of disclosure to the public and applying the standards outlined above, we grant the motion with respect to Unitil’s rate case expense filing.
Consistent with our practice, the confidential treatment provisions of this Order are subject to the on-going authority of the Commission, on its own motion or on the motion of Staff, any party or any other member of the public, to reconsider the protective order in light of RSA 91-A, should circumstances so warrant.
M. Conclusion
Having reviewed the testimony, evidence and other information submitted in this docket, we conclude that the Settlement filed on February 23, 2011, is just and reasonable and in the public interest and that it produces rates that are just and reasonable. The agreement provides for
Exhibit 99.2
| DE 10-055 | - 38 - |
an initial rate increase that resolves a revenue deficiency and brings the Company’s rate base up-to-date. Moreover, it provides for a series of rate increases intended, among other things, to ensure recovery of the capital expenditures needed to enhance and augment its REP and VMP, as well as to address major storm restoration efforts will not compel the Company to seek another rate increase in the immediate future. The Settlement offers this protection without unduly burdening customers and without removing all risk from the Company and its shareholders to operate an efficient business. Further, the term of the agreement is sufficient to allow the rate changes to be meaningful, without locking in the Company or its customers to a losing strategy for an unreasonable period. It also provides some protection for both customer and the Company from over- or under-earning. We conclude that the Settlement, including its requirements relating to reliability enhancements and tariff changes, as well as the rate design it contains, represents a fair and just compromise and that our approval of the agreement is in the public good.
Based upon the foregoing, it is hereby
ORDERED, that the Settlement is approved; and it is
FURTHER ORDERED, that the motions for confidential treatment are granted; and it is
FURTHER ORDERED, that Unitil shall file a compliance tariff with the Commission on or before April 28, 2011, in accordance with N.H. Code Admin. Rules Puc 1603.02(b).
Exhibit 99.2
| DE 10-055 | - 39 - |
By order of the Public Utilities Commission of New Hampshire this twenty-sixth day of April, 2011.
| /s/ Thomas B. Getz |
/s/ Clifton C. Below |
/s/ Amy L. Ignatius | ||
| Thomas B. Getz Chairman |
Clifton C. Below Commissioner |
Amy L. Ignatius Commissioner |
Attested by:
| /s/ Lori A. Davis |
| Lori A. Davis Assistant Secretary |