8-K

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 of 1934

Date of Report (Date of earliest event reported)     March 29, 2005    

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
(Exact name of registrant as specified in its charter)

               Vermont                
(State of other jurisdiction
of incorporation)       1-8222       
(Commission
File Number)           03-0111290         
(IRS Employer
Identification No.)

       77 Grove Street, Rutland, Vermont               05701       
(Address of principal executive offices)          (Zip Code)

Registrant's telephone number, including area code (802) 773-2711

                                      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 8.01 Other Events.

           On March 29, 2005, Central Vermont Public Service Corporation issued a press release regarding the Vermont Public Service Board's ("PSB") Order entered March 29, 2005 in Docket Nos. 6946 and 6988, Investigation into the existing rates of Central Vermont Public Service Corporation and Tariff filing of Central Vermont Public Service Corporation requesting a 5.01% increase in its rates, effective August 29, 2004, for implementation as of April 1, 2005. The VTPSB also issued a press release concurrently with its Order. The aforementioned documents are attached hereto as Exhibits 99.1, 99.2, and 99.3.

Item 9.01 Financial Statements and Exhibits.

            (c)   Exhibits.

            99.1     Central Vermont Public Service Corporation Press Release
                       dated March 29, 2005.

            99.2     Vermont Public Service Board Press Release dated March 29, 2005.

            99.3     Vermont Public Service Board Docket Nos. 6946 and 6988,
                       Order dated March 29, 2005.

Forward-Looking Statements Statements contained in this report that are not historical fact are forward-looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Reform Act of 1995. Statements made that are not historical facts are forward-looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

SIGNATURE

      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.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By	/s/ Dale A. Rocheleau                                       Dale A. Rocheleau, Senior Vice President for Legal and Public Affairs, and Corporate Secretary

March 31, 2005

EXHIBIT INDEX

Exhibit Number	Description of Exhibit
99.1 99.2 99.3	Central Vermont Public Service Corporation Press Release dated March 29, 2005. Vermont Public Service Board Press Release dated March 29, 2005. Vermont Public Service Board Docket Nos. 6946 and 6988, Order dated March 29, 2005.

EX-99

EXHIBIT 99.1

Central Vermont Public Service

NEWS RELEASE

Contact: Steve Costello (802) 747-5427     (802) 775-0486 (home)     (802) 742-3062 (pager)
For Immediate Release: March 29, 2005

PSB orders rate reduction, refund
Central Vermont Public Service is reviewing a Vermont Public Service Board order issued today in the company's rate case. The board ordered a 1.88 percent rate decrease effective April 7, and refunds equivalent to 1.25 percent for the previous 12 months.

"We're disappointed, but we want to digest the order, and develop an appropriate plan for moving forward," CVPS spokesman Steve Costello said.

"Regardless of this order, we have and will continue to work hard, with our regulators, to control costs and ensure customers receive the service they expect," Costello said. "We are committed to continually improving service while managing costs."

CVPS applied for an increase of 5.01 percent last year, while the Department of Public Service sought a 6 percent rate decrease retroactive to April 7, 2004, along with a decrease of 7.16 percent this year.

During the proceedings, the company asked for and received permission to carry over 2004 earnings in excess of an 11 percent return on equity to 2005. That, along with a power cost settlement with the Department of Public Service and some corrections in the cost of service filing, reduced the increase the company sought to 2.9 percent.

CVPS has had just one rate increase in the past five years, 3.95 percent, on July 1, 2001. In the past five years, the CPI has increased by 15.6 percent.

EX-99

EXHIBIT 99.2

PRESS RELEASE

Vermont Public Service Board   112 State Street, Drawer 20   Montpelier, VT 05620-2701

FOR IMMEDIATE RELEASE

VERMONT PUBLIC SERVICE BOARD
REQUIRES $3.3 Million REFUND
AND 1.88% RATE DECREASE
FOR CENTRAL VERMONT PUBLIC SERVICE CORP.

Montpelier, Vermont -- March 29, 2005

The Vermont Public Service Board ("Board") today determines that Central Vermont Public Service Corporation's ("CVPS") present rates are not just and reasonable and must be reduced. The Board reaches this conclusion in today's order issued in two related cases, one of which looked at CVPS's rates for the last twelve months, and the other which set CVPS's rates on a going-forward basis. As a result of the Board's Order, CVPS's ratepayers will receive refunds of the extra collections over the last twelve months and will pay lower rates in the future. Specifically, the Board requires CVPS to refund to customers the amount by which the Company's rates were excessive over the past year (approximately $3.3 million or 1.25 percent). In addition, the Board requires CVPS to reduce its current rates by approximately 1.88 percent commencing April 1, 2005.

The first case decided in today's Order was opened in response to a request from the Vermont Department of Public Service ("DPS"), the agency responsible for representing the interests of the people of the state. This case reviewed CVPS's rates for the last twelve months. The DPS asked that the Board reduce CVPS's rates for this time period by 6 percent. CVPS did not request that the Board modify its rates for this period, even though it claimed that the evidence supported a 0.3 percent rate increase.

The second case decided in today's Order is an investigation of a proposal filed by CVPS to increase its rates, beginning April 1, 2005. CVPS originally requested a 5.0 percent rate increase, although it later reduced its requested increase to 2.9 percent. The DPS originally argued that CVPS's rates should be reduced by 7.16 percent, although it later requested a smaller decrease.

Today's decision also addresses concerns that the Board raised in two prior orders. First, when the Board approved the sale of the Vermont Yankee Nuclear Generating Station ("Vermont Yankee") in 2002, it required CVPS to file information regarding its costs and revenues so the Board could consider whether CVPS's rates should be adjusted based on the results of the sale.

Second, in 2004, when the Board reviewed a settlement agreement between CVPS and the DPS that would have frozen CVPS's rates, the Board concluded that the settlement did not adequately address CVPS's rapidly-growing deferral accounts. The Board was concerned that cost deferrals could require future ratepayers to pay costs that should have been paid by current ratepayers. As a result, the Board's approval of the settlement was conditioned upon CVPS's agreement to begin reducing the amount of its deferred costs. CVPS did not agree to accept this condition, so the settlement did not take effect and the amount of CVPS's deferred costs continued to grow. Today's Order stops this trend by requiring CVPS to begin reducing the balances in its outstanding deferral accounts as of April 2004.

The rate reductions approved by the Board today present a sharp contrast to the large rate increases occurring in other states in New England. Several factors contributed to the rate decreases. First, CVPS had substantial overearnings in 2001, 2002, and 2003, which, pursuant to a previous agreement between CVPS and the DPS, are returned to ratepayers starting in these cases. Second, in 2002, the terms of the sale of Vermont Yankee reduced CVPS's costs noticeably. Third, CVPS has been able to take advantage of higher market prices to sell excess power (including power saved due to energy efficiency measures) on favorable terms. Fourth, CVPS's capital costs have declined, largely because of lower interest rates, but also due to investors' perception that the sale of Vermont Yankee reduced risks. Finally, Vermont's decision not to pursue electric retail choice has allowed the state to avoid some of the cost effects of higher wholesale market prices and avoid the risk premium demanded by investors in ot her states because of uncertainties associated with retail choice.

For more information contact:                       Susan M. Hudson, Clerk of the Board
                                                                           (802) 828-2358

EX-99

EXHIBIT 99.3

STATE OF VERMONT
PUBLIC SERVICE BOARD

Docket Nos. 6946 and 6988

Investigation into the existing rates of Central Vermont
Public Service Corporation

and

Tariff filing of Central Vermont Public Service
Corporation requesting a 5.01% increase in its rates,
effective August 29, 2004, for implementation as of
April 1, 2005 )
)
)
)
)
)
)
)
)

Hearings at
Montpelier, Vermont
See Appendix A

		Order entered: 3/29/2005
PRESENT:	Michael H. Dworkin, Board Chairman David C. Coen, Board Member John D. Burke, Board Member
APPEARANCES:	Geoffrey Commons, Esq. June Tierney, Esq.         for Vermont Department of Public Service Morris L. Silver, Esq.         for Central Vermont Public Service Corporation Kenneth C. Picton, Esq. Helen M. Fitzpatrick, Esq. Kimberly A. Pritchard         for Central Vermont Public Service Corporation James A. Dumont, Esq.         for AARP

Table of Contents
I.	Introduction	4
II.	Positions of the Parties and Concerns of the General Public	8
III.	Earnings Cap	10
IV.	Deferred Costs and Revenues      A.   Deferred Accounts Included in Test-Year Rates      B.   Deferred Accounts That Will Be Amortized Beginning Rate Year 1             1.  Regulatory Assets             2.  Deferred Debits             3.  Regulatory Liabilities      C.   Deferred but Not Subject to Rate Recovery      D.   Deferred for GAAP Purposes	32 33 34 34 35 38 43 44
V.	Rate Base      A.   Plant Adjustments      B.   Accumulated Depreciation      C.   Distributed Utility Planning Demand-Side Management      D.   Distributed Utility Planning Account Correcting for Efficiency ("ACE")	56 56 69 83 87
VI.	Cost of Service      A.   Power Costs      B.   Sale of Connecticut Valley Electric Company      C.   Regulatory Commission Expense      D.   Depreciation Expense      E.   Payroll-Related Items             1.  Number of Employees             2.  Employee Incentive Plan             3.  Officers' Compensation             4.  Other Payroll Adjustments             5.  Payroll Tax Expense             6.  401(k) Expense      F.   Medical Insurance      G.   Director and Officer Liability Insurance      H.   Tree-Trimming      I.   Cost Savings from Capital Additions      J.   Revenues             1.  Unbilled Revenues             2.  Cable Television Pole Attachment Revenues      K. Agreed-Upon Adjustments	90 90 101 111 112 118 118 122 127 129 129 131 132 135 136 138 140 140 142 145
VII.	Cost of Capital	146
VIII.	Other Issues      A.   Treatment of Regulated Affiliates      B.  Customer Service Agreement      C.  Rate Design	159 159 167 169
IX.	Conclusion	170
X.	Order	171
Appendix A:  Hearing Schedule		175
Appendix B:  Procedural History		176

I.  INTRODUCTION

              These proceedings examine the appropriate rate levels for Central Vermont Public Service Corporation ("CVPS" or "Company"), our state's largest electric utility, both for the last twelve months, and on a prospective basis. The Vermont Department of Public Service ("Department" or "DPS"), the agency responsible for representing the interests of the people of the state, asks us to reduce CVPS's rates by 6 percent, retroactive to April 7, 2004, and by 7.16 percent, effective April 1, 2005.¹ CVPS has presented evidence that it argues supports the need for a 0.3 percent rate increase during the period from April 7, 2004, through April 6, 2005, (although CVPS does not request that we modify its rates for this period) and a 2.9 percent increase commencing April 1, 2005. AARP has no specific recommendation on rates.

              In today's Order, the Vermont Public Service Board ("Board") finds that CVPS does not have a revenue deficiency. Instead, we conclude that CVPS's present rates are higher than is just and reasonable, and must be reduced (although by considerably less than advocated by the Department). Accordingly, we direct that CVPS return to ratepayers the amount by which its rates were excessive (approximately 1.25 percent), for the period April 7, 2004, through April 6, 2005, and reduce its rates by approximately 1.88 percent (relative to the rate levels in existence today) commencing April 1, 2005.² For the past period, this will mean that CVPS must provide its customers with refunds of the difference between the rates we set and those now in effect.

              The rate reductions we find just and reasonable today present a sharp contrast to the large rate increases occurring in other states in New England. Several factors contribute to the rate decreases. First, CVPS had substantial overearnings in 2001, 2002, and 2003, which, pursuant to CVPS's previous agreement, are returned to ratepayers starting in these cases. Second, in 2002, the Board approved the sale of the Vermont Yankee Nuclear Generating Station ("Vermont Yankee") to Entergy Nuclear Vermont Yankee. The terms of the sale had the effect of reducing CVPS's costs noticeably. Third, CVPS has been able to take advantage of higher market prices to sell excess power (including power saved due to energy efficiency measures) on favorable terms. Fourth, CVPS's capital costs have declined, largely because of lower interest rates, but also due to investors' perception that the sale of Vermont Yankee reduced risks. Finally , Vermont's decision not to pursue electric retail choice has allowed us to avoid some of the cost effects of higher wholesale market prices and the risk premium demanded by investors because of uncertainties about retail choice.

              This proceeding is in fact two separate rate investigations -- covering two sequential periods. The first case, Docket 6946, has its origins in the sale of Vermont Yankee, of which CVPS owned 35 percent, and an associated Power Purchase Agreement.³ At the time we approved the sale of Vermont Yankee in 2002, we were concerned that the benefits of the sale might not flow through to ratepayers. We found that, in addition to the proceeds of the sale, one benefit of the sale would be the reduced power costs from Vermont Yankee beginning in 2004. This was due to the fact that the prices in the Power Purchase Agreement were below the cost of that power if CVPS had retained ownership. Our Order, therefore, directed CVPS and Green Mountain Power Corporation ("GMP") to file cost-of-service studies in April 2003.⁴

              After the filing of those studies, CVPS and the Department entered into a settlement agreement which we reviewed in Docket 6866. On January 27, 2004, we approved the settlement, but only if CVPS and the Department affirmatively agreed to a series of conditions. CVPS asked us to reconsider that decision, stating that without changes, CVPS did not believe it could reasonably accept the conditions. Prior to our ruling on reconsideration, the Department filed a letter stating that a further modification of the settlement agreement would not be feasible or appropriate and asking us to immediately open this investigation. Accordingly, on April 7, 2004, we opened Docket 6946 pursuant to 30 V.S.A. Section 227(b). The rates we now establish in Docket 6946 cover the twelve months ending March 31, 2005, and will be retroactive to April 1, 2004, the start of that investigation. On July 15, 2004, CVPS filed a proposal to increase rates by 5.01 percent; we opened Docket 6988 to consider that proposed rate increase.⁵ Our decision in that docket will apply prospectively, taking effect on April 1, 2005.

              This Order addresses both proceedings. As noted, we find that CVPS must reduce its rates in both Rate Year 1 and Rate Year 2. There are many individual rulings, described below, that explain the differences between CVPS's position and what we find just and reasonable after consideration of the evidence. The largest single issue, however, relates not to costs that CVPS incurred in Rate Year 1 or will incur in Rate Year 2, but rather to accounting for CVPS's overearnings during 2001, 2002, and 2003. In 2001, CVPS and the Department had agreed to a Memorandum of Understanding resolving two CVPS rate increase requests. As part of that agreement, CVPS agreed that it would book for future return to ratepayers all earnings in excess of an 11 percent return on equity. CVPS booked some excess earnings in 2002 and 2003. The Department contests the calculation methodology CVPS employed and asserts that CVPS had overearnings in all three years -- with a total more than $14 million in excess of CVPS's calculation (before adding carrying costs). We find here that the Department's proposal is consistent with our approval of the MOU and is reasonable. Due to the magnitude of the recalculation of overearnings, we will allow CVPS to amortize the return to ratepayers over four years.

              CVPS also raised a broad challenge to the Department's approach to these proceedings, arguing that a significant portion of the Department's proposed cost-of-service reductions are not based upon the application of traditional ratemaking policies. CVPS characterizes the Department position as advocating a "new regulatory paradigm" which "creates substantial uncertainty as to the predictability of the Vermont ratemaking system."⁶ Our review of the record does not lead us to the same conclusion. The number and extent of these new proposals is much less than the Company's claim of a "new regulatory paradigm" would suggest, although the Department has advocated some adjustments that it had not previously recommended. Most of the Department's proposals are consistent with positions it has advocated for many years in many cases involving Vermont utilities. CVPS's assertion that they represent changes may stem from the fact that this is the first fully litigated rate case for CVPS in more than 10 years.⁷

              For the adjustments that the Department had not sought in prior cases, we have evaluated each of these on its own merits, applying the regulatory principles that we typically use. For reasons that we explain below, we have not adopted some of these proposals, not because they are new, but because the adjustments are inconsistent with our fundamental ratemaking standards. We have accepted other "new" adjustments, based upon our conclusion that, based on the evidence and the law, the change was necessary to produce just and reasonable rates. This is consistent with basic principles of administrative law that we may need to modify past rulings when necessary to set just and reasonable rates C a policy routinely followed by American courts and commissions and which we explained in detail in a CVPS rate proceeding nearly 18 years ago.⁸

              Moreover, we find that in numerous instances, such as proposed plant additions, it is CVPS (rather than the Department) that seeks changes to the standards we have previously enunciated. Indeed, CVPS made arguments here concerning the application of the known and measurable standard to plant additions that we rejected in CVPS's last fully-litigated rate cases in 1994. Similarly, CVPS sought to update its filing even though we ruled in the 1994 cases that such updates were impermissible.

              We have also considered the Company's financial stability. In fact, our rulings reflect the fundamental financial health of the Company in recent years, and clear record evidence that such health is likely to continue.

              Finally, today's Order addresses the concerns we expressed in our January 27, 2004, Order in Docket 6866 that CVPS has a large amount of deferred costs. CVPS will begin amortizing these costs April 1, 2004, so that by early 2007, the deferrals will have been fully recovered. Even with these amortizations, we find that a small rate decrease is appropriate in both rate years.

II.  POSITIONS OF THE PARTIES AND CONCERNS OF THE GENERAL PUBLIC

              This section describes the parties' overall rate recommendations. The parties' positions on individual issues are discussed in the sections of this Order related to those issues.

Central Vermont Public Service Corporation

              CVPS argues that a rate reduction for Rate Year 1 is not justified because it has an alleged revenue deficiency of $0.881 million, or 0.3 percent. CVPS originally filed for an increase of 5.0 percent in rates, and now asserts that the record supports a rate increase of $7.655 million, or 2.9 percent, in Rate Year 2. These positions take into account the Company's agreement with the DPS on power cost issues,⁹ and the reduction of regulatory asset amortizations by application of the $3.8 million in deferred 2004 earnings.¹⁰ CVPS argues that its return on equity should be 11.0 percent.

Vermont Department of Public Service

              The DPS argues that the Board should reduce CVPS's rates for Rate Year 1 by 6 percent, and order refunds in the amount of $15.818 million. The DPS asserts that the Board should reduce CVPS's rates for Rate Year 2 by 7.16 percent (a reduction of $18.858 million from CVPS's claimed cost of service). However, the DPS states that these amounts should be adjusted to reflect its power cost agreement with CVPS, its revised recommendation regarding incentive compensation,¹¹ and perhaps for the disallowance of unsupported plant costs.¹² The DPS argues that CVPS's return on equity should be 8.75 percent.

AARP

              AARP did not provide a specific cost-of-service calculation for either rate year. Instead, AARP supports the recommendations of the DPS, except that AARP recommends a return on equity of 10.0 percent, an amortization period of 6 years for deferred debits, and that no costs associated with, or resulting from, the sale of Connecticut Valley Electric Company be charged to ratepayers.

Members of the General Public

              In addition to hearing from formal parties in Dockets 6946 and 6988, we held a public hearing in both dockets on September 14, 2004, at eight locations in or close to CVPS's service territory via the Vermont Interactive Television Network. The purpose of the public hearing was to gather information from, and the opinions of, the public at large.¹³ Three members of the public spoke in support of a rate decrease for Rate Year 1, or against a rate increase in Rate Year 2. For example, one citizen stated in response to a recent bill insert he received from CVPS (which stated that absent a rate inquiry initiated by the Board, and the threat of a rate decrease, CVPS would not have sought an increase):

The disingenuousness of this position is beyond belief or comprehension. CV has stated in so many words that there is no actual need for a rate increase at this time. I don't know whether this is intended as leverage against a decrease or an attempt to shift blame for higher electrical rates in the public's eye to the Board. It is, however, a statement by CVPS that there is no immediate need for an increase, and I for one do not wish to be burdened with an elective rate increase . . . ¹⁴

No members of the public at the public hearing opposed a rate decrease for Rate Year 1, nor did any support a rate increase in Rate Year 2. The Board also received some letters from the general public, largely in opposition to CVPS's requested rate increase for Rate Year 2.

III.  EARNINGS CAP

              Dockets 6120 and 6460 were investigations into rate increases requested by CVPS. On June 26, 2001, the Board issued an order in those dockets approving a Memorandum of Understanding between CVPS and the DPS ("2001 MOU"). This settlement agreement recommended a rate increase for CVPS, and required ratepayers to pay rates that provided for full recovery of the costs of CVPS's purchases of power from Hydro-Québec pursuant to the contract between Hydro-Québec and the Vermont Joint Owners, despite CVPS's imprudent decision to commit to that contract and the fact that the power was not economically used and useful. In other words, pursuant to the 2001 MOU, CVPS was allowed to recover costs from ratepayers that would not have been allowed if the Board had based its decision in those cases on traditional cost-of-service methodologies.¹⁵ The 2001 MOU also provided ratepayers with several benefits includ ing, among others, CVPS's write-down of $9 million in regulatory assets, and a cap on CVPS's earnings in 2001, 2002, and 2003.¹⁶

              The specific language in the 2001 MOU regarding this earnings cap is at the heart of one of the key issues in the proceedings before us today. The MOU does not specify an exact calculation methodology for implementing the earnings cap provisions of the 2001 MOU. CVPS and the DPS have proposed significantly different calculation methodologies. The different calculation methodologies lead to very different amounts of overearnings in 2001, 2002, and 2003. According to CVPS, using its recommended methodology, the Company's total overearnings over the three-year period the earnings cap was in effect were $3,156,050;¹⁷ CVPS has proposed to return this amount, plus carrying costs, to ratepayers in the instant proceedings. According to the DPS, using its recommended methodology, CVPS's total overearnings over the three-year period the earnings cap was in effect were $17,385,000;¹⁸ the DPS argues tha t, in these proceedings, we should order the return of this amount, plus carrying costs, to ratepayers. The difference between the two amounts is $14,228,950.

Findings

1. Paragraph 29 of the 2001 MOU states: "The Company's allowed rate of return on common equity shall be 11.00%." Dockets 6120/6460, Order of 6/26/01 at appendices page xxi.

2. Paragraph 30 of the 2001 MOU states:

To the extent that CVPS's calendar year earned return on equity on its Vermont jurisdictional electricity utility operations in 2001 exceeds 11.0%, the dollar amount of such excess shall be applied (a) to reduce regulatory asset accounts as specified by the DPS and approved by the Board at the time of any such excess, or (b) as otherwise agreed by CVPS and the DPS. Any such dollar amount of excess in 2002 and 2003 over CVPS's allowed return on equity in effect in such calendar year also shall be credited as provided herein, unless a superseding approved agreement or order on rates shall have earlier become effective.

Dockets 6120/6460, Order of 6/26/01 at appendices page xxi.

3. CVPS has recorded the following amounts as regulatory liabilities associated with the 2001 MOU's earnings cap:

• 2001 -- $0
• 2002 -- $680,874
• 2003 -- $2,475,176

Gibson reb. pf. 11/19/04 at 5.

4. CVPS received an accounting order from the Board dated April 4, 2003, authorizing the Company to defer the $680,874 in 2002 overearnings shown in finding 3, above. This accounting order included the following paragraph:

3. This Order is limited to the accounting treatment for the subject dollar amount and does not bar any party from contesting or the Board from determining or modifying the subject dollar amount, in whole or in part, in any rate proceeding in which the subject dollar amount is reflected in cost of service.

Accounting Order of April 4, 2003.

5. CVPS's proposed calculation methodology starts with the Company's consolidated net income and common stock equity. It then reduces both items by the net income and common stock equity of its non-regulated subsidiaries and its New Hampshire utility subsidiary. The resulting net income is compared to the resulting common stock equity to arrive at the return on equity for CVPS's Vermont jurisdictional electric utility operations. Schultz and DeRonne pf. at 33.

6. The DPS's proposed calculation methodology calculates the revenue requirement for the year of determination using actual information in the same format and manner that is routinely used for setting rates. The only adjustments to actual amounts are for standard accepted regulatory adjustments or adjustments to remove costs that are not to be included in regulatory cost of service. Schultz and DeRonne pf. At 33-34.

7. Using the DPS's proposed calculation methodology results in significantly higher overearnings than using CVPS's proposed calculation methodology. Specifically, the DPS's proposed calculation methodology results in overearnings of:

• 2001 -- $4,607,000
• 2002 -- $6,115,000
• 2003 -- $6,663,000

Schultz sup. pf. at 4.

8. Using the DPS's calculation methodology does not always result in higher overearnings than using CVPS's calculation methodology. The result is company-specific. For example, when the DPS applied its methodology to GMP in 2004, the DPS's calculation methodology resulted in underearnings, while a methodology similar to that proposed by CVPS resulted in overearnings. Tr. 1/13/05 at 16-18 (Schultz).

9. Two factors that can lead to differences in the results of the two proposed methodologies are: (1) below-the-line expenses and revenues; and (2) the amount of cash and temporary investments. Tr. 1/13/05 at 17-18 (Schultz).

10. CVPS had significant temporary cash investments during 2001, 2002, and 2003. The value of these temporary cash investments was:

• $38,885,892 as of January 1, 2001;
• $32,929,809 as of January 1, 2002;
• $21,190,246 as of January 1, 2003;
• $41,300,087 as of December 31, 2003.

Exh. CVPS-11 at 110; exh. CVPS-12 at 110; exh. CVPS-13 at 110.

11. CVPS's calculation included an 11 percent return on equity on the Company's temporary cash investments. These amounts are not being used to provide service to Vermont ratepayers; therefore, ratepayers should not be providing an 11 percent return on these investments. Tr. 11/4/04 at 94-95 (Schultz).

12. CVPS's calculation method included an 11 percent return on items that are normally excluded from ratemaking. For example, account 426 is always excluded for ratemaking purposes.¹⁹ In 2001, that account included the $9 million write-off of deferred accounts that was committed to by CVPS in the 2001 MOU. CVPS's method would allow the Company to earn a return on this write-off. Schultz and DeRonne reb. pf. at 31; tr. 11/4/04 at 95 (Schultz).

13. The DPS's calculation method is based on the methodology used in setting rates.²⁰ Schultz sup. pf. at 5.

14. The purpose of an overearnings calculation is to reflect how the actual period results compare to the actual revenues that were collected. Actual results should not be replaced with estimates, even for those items for which the Board traditionally uses multi-year averages when setting rates. Schultz sup. pf. at 2.

15. If the Board orders CVPS to use a different methodology to recalculate its overearnings for 2001, 2002, and 2003, CVPS will not be required to restate its earnings for those years. Tr. 1/12/05 at 159 (Gibson).

Discussion

              The dispute between the DPS and CVPS related to the 2001 MOU's earnings cap centers on Paragraphs 29 and 30 of the 2001 MOU. The issue before the Board is, given the language of the 2001 MOU, what overearnings calculation methodology should be used to calculate CVPS's overearnings in 2001, 2002, and 2003. The DPS recommends that we calculate CVPS's overearnings in the same way that we establish rates. CVPS recommends that we calculate its overearnings using information from its required filings with the Securities and Exchange Commission.

              We have carefully reviewed the specific language of the 2001 MOU and the Board's Order approving it, and considered all the arguments made by the parties. We conclude that the DPS's cost-of-service-based calculation methodology should be used, and we require CVPS to use this methodology to recalculate its overearnings for 2001, 2002, and 2003, as part of its compliance filing in these proceedings. However, as explained in more detail below, when CVPS recalculates its overearnings, it should:

• remove 100 percent of transmission revenues before applying the wholesale allocation factor;
• include the portion of Construction Work In Progress on which it does not accrue an allowance for funds used during construction;
• treat all of its regulated affiliates above-the-line; and
• reflect our decisions in this Order regarding Distributed Utility Planning Demand-Side Management, and the 2002 Vermont Yankee Mid-Cycle Outage.²¹

              This decision is a direct application of the terms of the 2001 MOU and the Board Order approving it, and is not a modification of either one. Paragraph 30 of the 2001 MOU requires CVPS to return its 2001, 2002, and 2003 overearnings to ratepayers; our decision today implements that paragraph. As discussed further below, the earnings cap provisions in the 2001 MOU use the language of traditional ratemaking practice. After reviewing this language, we conclude that the 2001 MOU does not specify an exact methodology for calculating CVPS's overearnings, but that the methodology for calculating overearnings must be consistent with traditional ratemaking practice.

              One of the fundamental principles of traditional ratemaking is that ratepayers should not be required to pay for, or provide a return on, investments that do not serve them. The DPS's methodology is consistent with this principle, while CVPS's equity-based methodology is not.²² CVPS's methodology would require ratepayers to provide a return on items that are traditionally excluded from rates, including millions of dollars of unused cash and the $9 million writeoff that CVPS agreed to make as part of the 2001 MOU.²³ If we were to require ratepayers to provide a return on such items, we would be denying ratepayers one of the benefits they received from the 2001 MOU C the assurance that CVPS would return to ratepayers any earnings above its allowed return on equity. We consider that benefit to be particularly significant because other provisions of the 2001 MOU resulted in ratepayers paying for costs that would not have been included in rates if the Board had set CVPS's rates using traditional cost-of-service methodologies.²⁴

              Our conclusion is that under the terms of the 2001 MOU CVPS must calculate its overearnings using a method that is consistent with traditional ratemaking practice. This is also consistent with the testimony of the Company's Chief Financial Officer at the time the Board was considering whether to approve the 2001 MOU. Mr. Boyle testified that the 2001 MOU "would not require that customers pay rates that are in excess of what should be due under cost of service ratemaking doctrines."²⁵ CVPS asserts that this testimony was provided in the context of arguing against the imposition of a protection against unjust enrichment, not in the context of the methodology for calculating overearnings.²⁶ However, Mr. Boyle's point that the MOU was adequate protection clearly rests on the comparison to traditional ratemaking. We accept this "traditional ratemaking" characterization of the 2001 MOU, and conclu de that the 2001 MOU earnings cap provisions should be applied in a manner that ensures that ratepayers do not pay more during the 2001B 2003 time period than they would have under cost-of-service ratemaking. The DPS's recommended cost-of-service-based methodology would ensure this, while CVPS's proposed equity-based methodology would not.

              Thus, we conclude that the language of the 2001 MOU and our Order approving that agreement require us to accept the DPS's proposed calculation methodology. However, we do understand that CVPS may have had some reason to believe that its recommended methodology is consistent with prior Board practice.²⁷ The last time the Company was subject to an earnings cap,²⁸ the Board accepted the results of an overearnings calculation methodology substantially similar to the one the Company has proposed using in the instant proceedings.²⁹ The DPS challenged CVPS's calculation methodology in the 1994 proceedings, arguing that the calculation of earnings should be consistent with ratemaking,³⁰ but the Board rejected the DPS's proposed adjustment because of an evidentiary failure.³¹ Even though the Board did not rule on the merits of either CVPS's or the DPS's methodology in the 1 994 proceedings,³² given the Board's decision in those cases, we do not find it unreasonable for CVPS to have thought its calculation methodology might be acceptable to the Board in its current proposed application.

              In recognition of this situation, we have decided it is appropriate to extend the period over which CVPS will return its 2001-2003 overearnings to ratepayers. CVPS had originally proposed a three-year amortization period. We conclude that a four-year amortization period is more appropriate. This will reduce the immediate impact on the Company's earnings and cash flow, while at the same time, ensuring that ratepayers will ultimately recover all the funds owed to them.

Appropriate Calculation Methodology

              To decide upon an appropriate calculation methodology, we start with an analysis of the 2001 MOU and the Board's Order approving it. We conclude that the DPS's proposal, rather than CVPS's is appropriate, based on two related, fundamental considerations:

(1) the meaning of the 2001 MOU's language; and

(2) consistency with traditional ratemaking practice.

We address each of these considerations below.

Language of the 2001 MOU
              Both CVPS and the DPS point to several key phrases in Paragraphs 29 and 30 of the 2001 MOU that they argue support their interpretations. The cited phrases include "allowed return on equity," "Vermont jurisdictional electricity utility operations," and "return on common equity." All of these phrases are commonly used in traditional ratemaking practice and form part of the basis for our conclusion that the language of the 2001 MOU requires us to approve an overearnings calculation methodology that is consistent with traditional ratemaking principles.

              For example, the phrase "allowed return on equity" is very commonly used when setting rates. Each time the Board sets rates, it must decide the affected company's allowed return on equity.³³ In the context of the 2001 MOU, we find that the term indicates, as the DPS asserts, that the calculation must separate items on which the Company does not have an allowed return from those on which it does (in other words, separate those items serving ratepayers from those that do not).

              Similarly, the concept behind "Vermont jurisdictional electricity utility operations" underlies much of our traditional ratemaking practice. When we set rates, we determine what costs are within our jurisdiction, and what costs are appropriately part of a company's utility operations, and therefore recoverable from ratepayers. In the context of the 2001 MOU, we conclude that "Vermont jurisdictional electricity utility operations" do not include items that are normally excluded from ratemaking. Such items are generally excluded for one of three reasons:

(1) they are not within the Board's jurisdiction (for example, costs incurred by CVPS's unregulated subsidiaries); or

(2) they are within the Board's jurisdiction, but are not being used to serve ratepayers (for example, unused cash); or

(3) they are within the Board's jurisdiction, but are not appropriate for recovery from ratepayers (for example, imprudently-incurred costs).

              If something is not within the Board's jurisdiction, it is, by definition, not part of "Vermont jurisdictional electricity utility operations." And, it is consistent with the purpose of the earnings cap provision of the 2001 MOU (to return to ratepayers any earnings above CVPS's allowed return on equity) for items that are not being used to serve ratepayers or are otherwise not appropriate for recovery from ratepayers to be excluded from "Vermont jurisdictional electricity utility operations"; stated another way, it would be illogical to interpret the earnings cap provision as requiring ratepayers to provide a return on items for which it is inappropriate for them to pay.

              CVPS asserts that "return on common equity" is not commonly used in Vermont in the context of a cost-of-service analysis; the Company argues the phrase "return on equity" or "ROE" is typically used instead.³⁴ This assertion is incorrect. Contrary to CVPS's arguments, "return on common equity" is a phrase that is often used in traditional ratemaking practice in Vermont. The Board has consistently used "return on common equity" and "return on equity" interchangeably in the context of cost-of-service analyses across industries during the last 15 years.³⁵ In fact, to be precise, when we set a return on equity, we actually mean return on common equity, since that is the only class of stock for which we set a return. We do not, for example, set a return on preferred stock, even though that is also equity. Even the 2001 MOU, itself, uses the two terms interchangeably -- Paragraph 29 quantifies CVPS's " allowed rate of return on common equity" while Paragraph 30 refers to an "allowed return on equity." If the two terms were not synonymous, it would not be possible to give meaning to the last sentence of Paragraph 30, since CVPS's "allowed return on equity" is not quantified anywhere in the 2001 MOU; only CVPS's "allowed rate of return on common equity" is quantified in Paragraph 29. Thus, we conclude that the use of the term "return on common equity" instead of "return on equity" in Paragraph 29 of the 2001 MOU does not support CVPS's argument that a cost-of-service-based methodology for calculating overearnings would be inconsistent with the 2001 MOU.³⁶

              We do agree with CVPS that "common equity" is not the same as "rate base," but that is not the relevant distinction. The paragraph of the 2001 MOU that defines the earnings cap refers to CVPS's "return on equity on its Vermont jurisdictional electricity utility operations," not to its return on common equity. The key distinction is that CVPS includes millions of dollars of unused cash that was not serving ratepayers in the Company's common equity; however, this cash was not part of the Company's Vermont jurisdictional electricity operations.³⁷

              Finally, we are not persuaded by CVPS's argument that the 2001 MOU's linkage of "earnings" to "operations," instead of to "rate base" or "utility property," supports its proposed calculation methodology. The fact that the 2001 MOU links earning to "operations" rather than to "rate base" or "utility property" is a distinction without a difference. As explained above, we find that "Vermont jurisdictional electricity utility operations" are made up only of items normally included in ratemaking. These are the same items that are included in rate base.

Consistency with Traditional Ratemaking Practice
              Now that we have concluded that the language of the 2001 MOU requires that we approve a methodology that is consistent with traditional ratemaking practice, the next step is to consider which of the two methodologies presented in these proceedings is consistent with those practices.

              Traditionally, utility rates in Vermont are based on a company's cost to provide utility services (including a return on its prudent investments that are used to provide service to ratepayers). The standard practice is for a utility to prepare a cost-of-service filing that is based on a historic test year, adjusted for known and measurable changes. This cost-of-service filing includes information on the utility's revenues, costs, rate base, and cost of capital. This filing is then reviewed, and further adjustments may be made to it. Ultimately, in a fully-litigated rate case, the utility's rates are based upon the final, adjusted cost-of-service and rate base information.³⁸

              The DPS's cost-of-service-based methodology is generally similar to the methodology the Board uses to set rates. It starts with a cost of service, except that the cost of service shows actual results for the particular year in question, rather than information from a historic test year that is adjusted for known and measurable changes. In general, items are included or excluded from the earnings cap calculation based on whether they are included or excluded in a traditional cost-of-service calculation that would be used to set rates.

              CVPS's methodology, on the other hand, is radically different from the methodology the Board uses to set rates. This equity-based methodology uses information from filings with the Securities and Exchange Commission regarding consolidated net income and common stock equity, adjusted to remove the portions of both items attributable to its non-regulated subsidiaries and Connecticut Valley Electric Corporation.³⁹ Other than that one adjustment, CVPS's methodology does not distinguish between items that are traditionally included or excluded from a company's cost of service. As a result, CVPS's methodology requires ratepayers to provide a return on the Company's millions of dollars of unused cash and other items that are not traditionally allowed in rates (such as the $9 million write-off that CVPS agreed to as part of the 2001 MOU). This is inappropriate. As the DPS's earnings cap witness pointed out, includi ng unused cash in common equity can distort the results of an earnings cap calculation. Cash is theoretically generating its own return, and is not providing service to ratepayers.⁴⁰ This issue is particularly important in CVPS's case because of the size of the Company's unused cash balances which averaged approximately $36 million in 2001, $27 million in 2002, and $31 million in 2003.

              Thus, we conclude that the DPS's proposed calculation methodology is generally consistent with the requirements of the 2001 MOU and traditional ratemaking practice. Accordingly, we find this methodology to be appropriate to use to calculate CVPS's overearnings in 2001, 2002, and 2003.

              Having determined that, there are four issues regarding the details of the DPS's calculation methodology that relate to the consistency of the DPS's proposal with traditional ratemaking practices.⁴¹ These are: (1) "averaging" adjustments; (2) transmission revenues; (3) construction work in progress ("CWIP"); and (4) treatment of regulated affiliates. Our decision rule with respect to all of these issues is that the starting point for the overearnings calculation in each year should be a traditional cost-of-service calculation, except that actual costs and revenues should be used to the extent possible. The only adjustments to these actual amounts should be for standard accepted regulatory adjustments or adjustments to remove costs that are not to be included in a regulatory cost of service.

              Using this decision rule, we conclude that no adjustment to actual expenses should be made for those items for which the Board traditionally allows average expense levels in cost-of-service filings. Such "averaging" adjustments are appropriate to use when setting rates, but do not function as intended when calculating overearnings.⁴²

              With respect to transmission revenues, in its cost-of-service filings in these proceedings, CVPS followed the historical practice of removing 100 percent of its transmission revenues before applying the wholesale allocation factor.⁴³ The DPS did not challenge this adjustment to CVPS's costs of service for ratemaking purposes.⁴⁴ CVPS argues that the same practice should be followed in the overearnings calculation.⁴⁵ The DPS, on the other hand, asserts that the transmission revenues should not be removed before applying the wholesale allocation factor. Instead, the DPS argues that the wholesale allocation factor should be applied to both revenues and expenses.⁴⁶ We are not persuaded by the DPS's argument. The DPS asserts that its recommended approach is "more equitable,"⁴⁷ but the DPS has not explained why the traditional practice is sufficiently equitable in a cos t-of-service calculation for ratemaking purposes, but not in an overearnings calculation.⁴⁸ Therefore, CVPS should remove 100 percent of transmission revenues before applying the wholesale allocation factor when calculating its overearnings for 2001, 2002, and 2003.

              The issue of CWIP is similar to that of transmission revenues. The portion of CWIP on which a company does not accrue an allowance for funds used during construction is traditionally included in a company's rate base. CVPS argues that it should also be included in its overearnings calculation.⁴⁹ The DPS, on the other hand, asserts that because there is no evidence that CWIP is providing service to customers, CWIP should not be included in CVPS's rate base in the overearnings calculation. As in the case of transmission revenues, we conclude that the DPS has not shown why the traditional practice is appropriate in a cost-of-service calculation for ratemaking purposes, but not in an overearnings calculation. Therefore, when calculating its overearnings for 2001, 2002, and 2003, CVPS should include the portion of CWIP on which it does not accrue an allowance for funds used during construction.

              Our basic decision rule leads us to conclude that CVPS's regulated affiliates should be treated above-the-line in the calculation of its overearnings. As explained in Section VIII.A, below, we determine that CVPS should account for its regulated affiliates above-the-line in its cost-of-service filings in these proceedings. We considered whether there was some justification for treating the regulated affiliates differently in an overearnings calculation than in a cost-of-service used to set rates, and conclude that there is not. Removing the regulated affiliates from the cost-of-service calculation would not be a standard regulatory adjustment, nor would it remove costs that should be excluded from a cost-of-service. We are not persuaded by the DPS's argument that the regulated affiliates should be treated above-the-line in the overearnings calculations only to the extent that the regulated affiliates were included in t he revenue requirement filing which led to the 2001 MOU.⁵⁰ That revenue requirement filing resulted in a bottom-line settlement that did not specify how the regulated affiliates were treated. In the instant proceedings, CVPS states that it treated all its regulated affiliates except for Vermont Yankee below-the-line in its filing that led to the 2001 MOU,⁵¹ but we do not conclude that this is sufficient basis for making a distinction among regulated affiliates. Instead we find that since CVPS's affiliates should be treated above-the-line in its cost-of-service filings for ratemaking purposes, they should also be treated above-the-line for calculations of overearnings.

Retroactive Ratemaking

              CVPS asserts that if the Board were to accept the DPS's proposed calculation methodology and require the Company to recalculate its overearnings for 2001, 2002, and 2003, we would be engaging in prohibited retroactive ratemaking. We conclude that CVPS's arguments about retroactive ratemaking are misplaced. The 2001 MOU and our Order approving it set rates prospectively (from 2001 forward), with a requirement that earnings over 11 percent be returned to ratepayers. Our decision today is not retroactively changing CVPS's rates because the rates were set in 2001 by the 2001 MOU and the Board's June 26, 2001, Order approving that agreement.

              As the Vermont Supreme Court stated:

Retroactive ratemaking occurs when rates are set at a level that permits a utility to recover past losses, or that requires it to refund past excess profits, that resulted from a disparity between projected expenses of a prior rate base and actual incurred expenses. In re Central Vermont Pub. Serv. Corp., 144 Vt. 46, 52, 473 A.2d 1155, 1158 (1984). While "the Board may consider a utility's recent past operating experience with such adjustments as will make the test period reflect typical conditions in the immediate future," it may not set a rate "that requires a utility to refund to consumers a portion of its previously earned profits." Id. at 53, 56. "[T]he Board has no statutory authority to make whole either the utility company or its customers for inequities that existed in the past." Id. at 53.⁵²

The Vermont Supreme Court has consistently held that retroactive ratemaking is prohibited, whether the intent was to make utilities whole for costs not contemplated in a previous rate order (as in In re CVPS, supra) or to return excess utility profits to ratepayers (as in In re GMP, supra).⁵³

              However, none of the cases identified by CVPS involve the application of a Board-approved settlement agreement, and CVPS has failed to explain how those cases apply to a situation where the utility has previously agreed, and the Board has previously ordered it, to return its excess earnings to ratepayers. Indeed, in the 2001 MOU, CVPS agreed, in return for valuable consideration, to return its excess earnings to ratepayers, and the Board issued an order approving the 2001 MOU. CVPS itself recognizes its obligation to return overearnings, notwithstanding the general prohibition on retroactive ratemaking. The Company reflected the return of its overearnings (calculated using its methodology) in its original cost-of-service filings in these proceedings. The disagreement in the instant proceedings relates to the calculation of overearnings under the 2001 MOU⁵⁴ -- should CVPS be allowed to use a calculation metho dology that results in the Company earning a return from ratepayers on items expressly excluded from legitimate "utility profits" (as that term is used in the CVPS and GMP appellate cases)? We conclude that CVPS should not be allowed to do so, and that requiring CVPS to recalculate its overearnings accordingly does not constitute retroactive ratemaking as defined by the Vermont Supreme Court. To read the 2001 MOU as CVPS now suggests is to argue, in essence, that the Company never intended to do what it promised to do.

              CVPS tries to characterize its argument regarding retroactive ratemaking in many different ways. It alleges that:

(1) the DPS is asking the Board to alter the terms of a prior Board order;⁵⁵

(2) an earnings cap based on a cost-of-service methodology automatically constitutes retroactive ratemaking;⁵⁶ and

(3) requiring CVPS to recalculate its overearnings using the DPS's proposed methodology is the same as requiring the Company to correct an "error" (as defined in Maine Public Advocate v. Public Utilities Commission, 476 A.2d 178 (Me. 1984)).⁵⁷

We address each of these in turn.

              First, we conclude that the DPS is not seeking to alter the terms of a prior Board order. Rather, the DPS is seeking to enforce the terms of a prior Board order. CVPS argues that the 2001 MOU requires the use of CVPS's overearnings calculation methodology. We disagree. Instead, as we concluded above, the 2001 MOU does not specify an exact calculation methodology, but does specifically refer to "allowed" earnings and repeatedly relies upon phrases consistent with the DPS's "traditional ratemaking" rationale. Therefore, it is necessary for us to determine what the appropriate calculation methodology is. That requires us to apply the 2001 MOU and our Order approving it; it does not require us to modify either of those documents.⁵⁸

              Second, we find that an earnings cap based on a cost-of-service methodology does not constitute retroactive ratemaking. As we explained above, our decision today simply applies the terms of the 2001 MOU and our Order approving it. That 2001 Board Order set rates prospectively (from 2001 forward); those previously-established rates, with their required refunds of overearnings, still control. Nothing in our decision today changes the rates established in 2001. All we are doing is applying those rates, which include the terms of the 2001 MOU that require CVPS to return its overearnings during 2001-2003.

              Third, CVPS relies on In re Maine Public Advocate which holds that "errors made in the calculation of a utility's base rates may be remedied only prospectively."⁵⁹ We conclude that requiring CVPS to recalculate its overearnings is not the same as requiring a utility to fix an error in the calculation of the utility's base rates. The methodology used to calculate CVPS's overearnings is unrelated to the calculation of CVPS's previous base rates. There was no error made in the calculation of CVPS's previous base rates. Those rates were established as part of the bottom-line settlement that is the 2001 MOU. As a result, there are no specific calculations of CVPS's previous rates that could be reconsidered, and the decision in In re Maine Public Advocate is not relevant to the issue before us.

Timing of Challenges to CVPS's Proposed Calculation Methodology

              One of CVPS's arguments against the adoption of the DPS's proposed calculation methodology is that if the DPS or the Board disagreed with CVPS's proposed calculation methodology, it should have challenged it earlier, well before the instant proceedings.⁶⁰ CVPS claims that the 2001 MOU required resolution of issues concerning the determination of earnings cap amounts "at the time of any such excess."⁶¹ We do not accept that interpretation of the 2001 MOU. Nevertheless, today's Order has the same substantive effect as if the excess earnings had been determined shortly after the end of 2001, 2002, and 2003.

              CVPS argues that various times would have been appropriate for the DPS and/or the Board to challenge CVPS's proposed calculation methodology including: (1) when the Company reported its 2001 earnings;⁶² (2) any time after early 2002 when CVPS provided its financial statements, including its earnings amounts, to the DPS;⁶³ (3) at the time CVPS filed its request for an accounting order that would enable it to defer the amount it calculated as its 2002 overearnings;⁶⁴ and (4) in CVPS's cost of service filed in Docket 6545 or in Docket 6866, the ensuing investigation into the settlement agreement between the DPS and CVPS.⁶⁵ CVPS asserts that by not challenging CVPS's calculation methodology earlier, the DPS "accepted or acquiesced in the Company's method of calculation."⁶⁶

              We are not persuaded by CVPS's arguments. While the DPS could have challenged CVPS's earnings cap calculation methodology at any of the times identified, the 2001 MOU did not require it to do so. If it was important to CVPS that the amount of overearnings be finally determined before it closed its financial books for the year in question, CVPS could have petitioned the Board to make such a determination. CVPS did not do so.

              CVPS states in its reply brief that "A determination by the Board at this late date which changes the calculation of the recorded excess earnings amounts raises serious financial concerns for the Company and its stakeholders."⁶⁷ CVPS also contends more broadly that adoption of the DPS's recommendation threatens CVPS's financial stability. We are not persuaded by these assertions. First, CVPS's total shareholder return has been near, or at, the top of all publicly-traded electric and combination utilities in 2001, 2002, and 2003.⁶⁸ That is an indication of a financially healthy company, not one that is financially unstable. We do understand that restatement of earnings for prior years can affect a company's financial health; however, CVPS's Chief Financial Officer testified that if the Board required CVPS to recalculate its overearnings, the Company would not be required to restate its earn ings for 2001, 2002, and 2003.⁶⁹ Thus, CVPS has failed to demonstrate that any "serious financial concerns" will result from a recalculation of its overearnings using the DPS's methodology.

              CVPS requested that the Board issue an accounting order, which was expressly limited to the accounting treatment of the amount of overearnings identified by CVPS. As stated in finding 4, above, the accounting order also explicitly provided that any party may contest, and the Board may modify, the identified dollar amount in any rate proceeding in which the identified dollar amount is reflected in the cost of service. Thus, the accounting order explicitly deferred a ruling on whether CVPS calculated the amount of the overearnings correctly until a future rate proceeding.⁷⁰

              CVPS asserts that the Board's accounting order allowed the DPS to challenge, in the future, CVPS's calculation of the deferred amount, but not the methodology used by CVPS to determine the amount to be deferred.⁷¹ There is simply nothing in the Board's April 4, 2003, accounting order to support such a distinction. On the contrary, the accounting order clearly stated that CVPS's calculation could be reviewed in future rate proceedings.⁷² Not only is it eminently reasonable to conclude that the calculation methodology is part of the calculation, but also the accounting order expressly provides that the order is limited to the accounting treatment of the excess earnings. CVPS's calculation methodology is clearly outside the scope of the "accounting treatment" that was the subject of the Board's limited approval.

              We are troubled that, once again, CVPS appears to be asserting that, even though the Board's accounting order expressly stated that the Board could modify the overearnings deferral amount in any rate proceeding in which the amount is included in the cost of service, it is, in effect, too late for the Board to do so. This is the latest example of a disturbing situation -- the Board issues an accounting order that states it is limited to the accounting treatment of a particular amount, only to later have the company argue that the accounting order resolved more than just the accounting treatment. As we stated in Docket 5983 (a rate case involving Green Mountain Power Corporation):

Under 30 V.S.A. Section 221, the Board is authorized to issue accounting orders; notice and opportunity for hearing are not necessarily required. We must stress that, in the absence of full notice and opportunity for hearing on a request for an accounting order, such an order will not have final effect in a later rate proceeding under 30 V.S.A. Sections 225-227, and it would be wrong for any party to think otherwise.⁷³

Comparison with Treatment of GMP

              CVPS asserts that the DPS is proposing to treat the Company much more harshly than it did GMP.⁷⁴ CVPS notes that, pursuant to two different settlement agreements approved by the Board in two different dockets, GMP has been subject to an earnings cap since 2001.⁷⁵ However, the DPS has not challenged GMP's overearnings calculations for 2001 and 2002, although it has examined GMP's calculation methodology for 2003. CVPS alleges that challenging CVPS's earnings cap calculations back to 2001, while only challenging GMP's back to 2003, constitutes "disparate treatment."⁷⁶

              The DPS argues that the DPS-GMP settlement agreements are explicitly non-precedential, as are virtually all settlement agreements filed with the Board, because each company's circumstances are different, particularly with respect to an earnings cap. However, the DPS points out that it did require GMP to recalculate its 2003 earnings using the same methodology that the DPS is recommending in the instant proceedings.⁷⁷

              We disagree with the Company's argument that it is unfair for the DPS to challenge CVPS's overearnings calculations for 2001 and 2002 when it did not challenge GMP's overearnings calculations for the same time periods. Far more significant is that the same policy is being applied to all utilities in a comparable situation at the same time. The DPS did not challenge either GMP's or CVPS's overearnings calculations in Dockets 6866 and 6867, which were contemporaneous. But, in 2004, the DPS challenged both utilities' overearnings calculations. The fact that the relevant calculation for GMP extended only back through 2003, while the relevant calculation for CVPS extended back through 2001, does not mean that the DPS is treating CVPS more harshly than it is GMP. Rather, it is simply a reflection of the fact that GMP's and CVPS's situations are different. Docket 6866 led to a final resolution of issues for GMP, including t he establishment of new rates, while, as described in Section I, above, Docket 6867 did not lead to a final resolution of issues for CVPS. As a result, the instant proceedings are the appropriate place to consider CVPS's overearnings calculations pursuant to the Docket 2001 MOU, which includes the years 2001, 2002, and 2003.

CVPS's Other Arguments

              CVPS makes two additional arguments in support of its position regarding the overearnings calculation methodology; as explained below, we do not find either of these arguments persuasive.

              CVPS argues that a new ruling on the method for determining compliance with earnings caps is not warranted in order to take account of an intervening change in the applicable legal context or otherwise to avoid inequitable administration of the laws. This argument is unavailing because we have not based our determination on either a change in law or to avoid the inequitable administration of the law.

              Finally, CVPS argues that if the Board wants to change the earnings cap calculation methodology, it should do so in a proceeding with all stakeholders, with any changes applied prospectively. CVPS makes the same assertion with respect to a change in accumulated depreciation policy. We explain why we reject this argument in our discussion of that issue in Section V.B, below.

Decisions on Other Issues That Affect the Overearnings Calculation

              Two of our other decisions in this Order have an impact on CVPS's overearnings in 2001, 2002, and 2003. As discussed in Section V.C below, CVPS incorrectly deferred Distributed Utility Planning Demand-Side Management costs that should have been expensed, and there are additional funds that were previously collected from ratepayers for that purpose that should be returned to ratepayers now. CVPS should treat these Distributed Utility Planning Demand-Side Management costs as expenses in the years in which they should have been recorded (the funds to be returned to ratepayers should be treated as a reduction to the cost of service in 2003) for purposes of performing the overearnings calculation. As discussed in Section VI.A below, we are reducing the amount of CVPS's deferred costs as a result of the 2002 Vermont Yankee Mid-Cycle Outage by $403,000. CVPS should include this $403,000 in its 2002 expenses when performin g the overearnings calculation.

IV.  DEFERRED COSTS AND REVENUES

Findings

16. CVPS has deferred recognizing certain revenues and expenses in accordance with accounting orders and other orders issued by the Board. Gibson pf. at 36-37; exhs. CVPS-JHG-13 at 2, CVPS-JHG-14, CVPS-JHG-15, and CVPS-JHG-16.

17. CVPS has relatively high balances in deferred debits and regulatory assets, which distort the Company's actual financial position and ratemaking accuracy. Id.; tr. 1/12/05 at 13-14 (Gibson).

18. The deferred costs include: Distributed Utility Planning Demand-Side Management costs; Distributed Utility Planning Account Correcting for Efficiency costs; Docket No. 6270 Independent Power Production ("IPP") costs; Docket No. 6330 Retail Choice costs; Vermont Yankee Fuel Rod Repair costs; Vermont Yankee Incremental Power costs due to the sale of Vermont Yankee; and Incremental Decommissioning costs for the Yankee Atomic Electric Power Company ("Yankee Atomic") the Connecticut Yankee Atomic Power Company ("Connecticut Yankee") and the Maine Yankee Atomic Power Company ("Maine Yankee"). The deferred revenues include various deferred credits as partial offsets to the deferred costs described above. Gibson pf. at 36-37; Schultz and DeRonne pf. at 23-24; exh. CVPS-4A; exh. CVPS-JHG-13.

19. CVPS's original cost-of-service filing for Rate Year 1 included amortization of these deferred costs and revenues. CVPS's original cost-of-service filing for Rate Year 2 did not reflect the effects of beginning the amortization of these deferred costs and revenues in Rate Year 1. Schultz and DeRonne pf. at 23-24.

20. Rate Year 1 amortizations can be recorded on the Company's books during Rate Year 1. Tr. 1/11/05 at 69 (Frankiewicz).

21. If amortization is reflected on the books of account in Rate Year 1, the amount recognized should not be included in deferral accounts in subsequent years. Id. at 62-63.

22. A three-year amortization period for most deferred expenses is reasonable. Talbot/Roschelle pf. at 26; Gibson pf. at 37.

23. In a rate case, regulatory assets, deferred charges, and regulatory liabilities that the Board finds reasonable are included in the cost of service that the Board establishes for setting rates. When the amortization of these amounts is complete, the amounts remain "in rates." This could lead to charges being over-recovered or under-recovered in rates, when the amortization for particular costs and revenues ends. Behrns pf. at 16-19.

24. If, at the conclusion of an amortization cycle, the yearly amortization amount associated with a regulatory asset or deferred debit is booked as a regulatory liability, there will be no over-recovery of costs to the Company. The converse is true if completed regulatory liabilities are booked as regulatory assets. Id.

A.  Deferred Accounts Included in Test-Year Rates

25. CVPS's current rates include the amortization and recovery of several regulatory assets. These are Connecticut Yankee Dismantling, Maine Yankee Dismantling, SFAS 109 Deferred Taxes, and 2002 Millstone Refueling. There is no dispute regarding the continued amortization of these accounts. The balance and expense for each account that is currently being recovered in rates are summarized in the table below:

	Balance 12/31/03	Recorded to Expense in Test Year	Carrying Charges
Regulatory Assets Connecticut Yankee Dismantling Maine Yankee Dismantling SFAS 109 Deferred Taxes78 2002 Millstone Refueling Regulatory Liabilities Vermont Yankee Recapture Total (Net)	$       2,979,858 7,287,060 5,639,760 109,087 393,939 $     15,621,826	$         794,364 1,038,190 209,468 654,524 48,732 $     2,647,814	No No No No No

Exh. CVPS-JHG-13.

B.  Deferred Accounts That Will Be Amortized Beginning in Rate Year 1

1.  Regulatory Assets

Docket 5980 Distributed Utility Planning Demand-Side Management and

Docket 5980 Distributed Utility Planning Account Correcting for Efficiency

26. Findings 136-145, below, are incorporated by reference.

Docket 6270 VEPPI Cost Mitigation/Docket 6330 Retail Choice

27. On January 29, 2000, the Board issued two accounting orders to CVPS related to: (1) Docket No. 6270 (Rule 4.100) costs; and (2) the Docket No. 6330 Retail Choice Petition and DPS Electric Utility Industry Restructuring Bill-Backs. Gibson pf. at 38-39.

28. In accordance with these two accounting orders, the Company deferred and continues to defer: (1) its costs incurred to pursue the mitigation of the power costs incurred by the Vermont Electric Power Producers, Inc. ("VEPPI"), the Board's Rule 4.100 Purchasing Agent, that was the subject of Docket 6270; and (2) the costs incurred by the Company or billed-back to it by the DPS relating to the effort to implement a voluntary restructuring program in CVPS's service territory that was the subject of Docket 6330. Gibson pf. at 38-39.

2.  Deferred Debits

Vermont Yankee Fuel Rod Repair

29. In 2002, Vermont Yankee experienced an unscheduled outage to resolve defects affecting certain of the plant's in-core fuel rods (referred to as the 2002 "Mid-Cycle Outage"). Vermont Yankee determined that individual fuel rods had developed small leaks that released radioactivity into the core. Vermont Yankee decided that the best course of action was to shut down and fix the problem. Page pf. at 4.

30. The 2002 Mid-Cycle Outage lasted approximately 12 days. During this time, Vermont Yankee remedied the problem. Page pf. at 5.

31. CVPS incurred replacement power costs for energy and costs to secure options to purchase energy at a fixed cost. Vermont Yankee also incurred incremental operation and maintenance costs that it passed on to its sponsors, including CVPS. Page pf. at 6.

32. Vermont Yankee offset part of the costs through a credit arising from a vendor warrantee for the defective fuel. Page pf. at 7.

33. On July 18, 2002, the Board issued an accounting order that authorized CVPS to defer the costs associated with the defective fuel rods at Vermont Yankee. Gibson pf. at 39; Schultz and DeRonne pf. at 27.

34. In Docket 6460, power costs were based upon an expected forced outage rate for Vermont Yankee of 4 percent. The actual production in 2002 was significantly above the target assumed by the forced outage rates (after factoring out the period of the Mid-Cycle Outage, the costs of which CVPS has deferred). Lamont pf. at 7.

35. The value of the power production in excess of the 4 percent forced outage rate is $403,000. CVPS's proposed deferral account should be reduced by this $403,000.⁷⁹ Lamont reb. pf. at 5; tr. 2/18/05 at 74-75 (Schultz, Watts).

Vermont Yankee Incremental Costs Due to Sale

36. As part of the Docket No. 6545 Order of June 13, 2002, approving the sale of Vermont Yankee, the Board issued two accounting orders for CVPS. Pursuant to the first such order, CVPS was authorized to defer any incremental income tax expense recorded under Statement of Financial Accounting Standards No. 109 as a result of its receipt of the cash proceeds resulting from the sale of Vermont Yankee and commencement of the related transaction agreements. Pursuant to the second accounting order, CVPS was permitted to defer incremental costs (excluding incremental income tax expenses covered under the first accounting order arising as a result of the receipt of the cash proceeds) that occur in 2002 after the sale of Vermont Yankee and consummation of the related transaction agreements. Gibson pf. at 39; exh. CVPS-JHG-15 at 2; see Docket 6545, Order of 6/13/02 at 141-144.

37. The Company deferred its applicable Vermont Yankee sale incremental costs. These costs represent the difference between the costs that the Company would have incurred had it not pursued the sale and those it incurred by pursuing the sale. This difference is primarily related to the Company's need to reflect the deferral and amortization of refueling maintenance costs for Vermont Yankee. Page pf. at 13.

38. Rate Year 1 rate base balance for the Vermont Yankee sale incremental costs should be $5,954,406, and Rate Year 1 amortization should be $1,984,802. Exh. DPS-L&A-11, at page 1 of schedule SR15, and at page 7 of schedule 8.

Vermont Yankee -- June 04 Fire Outage

39. In mid-2004, Vermont Yankee experienced an unscheduled outage due to a busbar fault and subsequent transformer fire. As a result, CVPS incurred additional replacement power costs during this time period of $835,946.⁸⁰ Watts pf. at 12-13; Page reb. pf. at 13-14.

40. CVPS may be able to recover some or all of these costs through the Ratepayer Protection Plan that Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations (jointly "Entergy") implemented as part of the power uprate of Vermont Yankee. Lamont pf. at 4; Deehan reb. pf. at 7-8.

41. CVPS has conducted a preliminary review of the facts relating to the outage and concluded that these incremental costs are eligible for recovery under the Ratepayer Protection Plan. Deehan reb. pf. at 8.

42. CVPS filed a petition asking the Board to resolve the issue of whether the cause of the outage was related to the uprate (and thus reimbursable by Entergy) or not. Docket 6812-A, Order of 3/4/05.

Yankee Atomic and Connecticut Yankee Incremental Decommissioning

43. Yankee Atomic is a retired single 185 MW nuclear power generating station located in Rowe, Massachusetts. Yankee Atomic recovers its costs through power contracts that remain in effect until decommissioning is complete (expected for 2006). Jewell-Kelleher YA (Yankee Atomic) pf. at 2-4.

44. Connecticut Yankee is a retired single 583 MW nuclear power generating station located in Haddam Neck, Connecticut. The plant is currently being decommissioned (a process that is expected to be complete in 2007). Jewell-Kelleher CY (Connecticut Yankee) pf. at 2-4.

45. CVPS pays a share of Connecticut Yankee decommissioning costs through the power contracts. Jewell-Kelleher CY pf. at 3.

46. In late 2002, CVPS received a forecast that the decommissioning costs for Yankee Atomic and Connecticut Yankee would be substantially higher than had been previously forecast. At that time, CVPS sought and received an accounting order from the Board authorizing deferral of the incremental decommissioning expense. Tr. 2/18/05 at 56 (Frankiewicz); Gibson pf. at 41; Page pf. at 13.

47. Decommissioning costs for Connecticut Yankee, Yankee Atomic, and Maine Yankee (in which CVPS also had an ownership share) have increased recently. A large part of this increase is due to the United States Department of Energy's failure to remove the spent nuclear fuel (as required by contract). Increased security costs and the declining financial markets (which reduced decommissioning fund earnings) have also contributed. As a result, the decommissioning funds are inadequate to meet expected decommissioning expenses. Page pf. at 13-18; exh. CVPS CJF-15 at 5 (Page response).

48. Yankee Atomic has filed and settled with the Federal Energy Regulatory Commission ("FERC") to renew collections at a higher level to cover its decommissioning obligations. Connecticut Yankee is also requesting a large increase to its current obligations. Watts pf. at 8; Page pf. at 18-19.

49. The decommissioning costs for Connecticut Yankee and Yankee Atomic as set out in FERC tariffs have increased by approximately $2,345,200 during Rate Year 1.⁸¹ Exh. DPS-CVPS-Joint-2.

3.  Regulatory Liabilities

6062 VEPPI Cost Mitigation (and Docket 6270)

50. On June 9, 2003, the Board issued an accounting order authorizing CVPS to defer the saving credits achieved through the implementation of the Memorandum of Understanding approved in Docket 6270. Gibson pf. at 41-42.

51. CVPS recorded these savings, with carrying costs, as regulatory liabilities. Gibson pf. at 41-42.

52. The Company has been recording regulatory liabilities for savings it has been accruing through March 31, 2005. Frankiewicz reb. pf. at 10.⁸²

53. The savings to be accrued after March 31, 2005, were reflected in Rate Year 2 purchased power costs. The amount of these savings are $373,500. Frankiewicz reb. pf. at 10; exh. DPS-CVPS-Joint-2 at 1.

54. The balance for the credit in Rate Year 1 should be $561,482. CVPS includes both Rate Year 1 amortization, and the savings to be achieved after March 31, 2005 (which were also included in the Company's power cost calculation), in its Rate Year 2 balance. These two amounts should be removed from the Rate Year 2 starting balance, which should be $371,321 ($561,485 less Rate Year 1 amortization of $187,164). Exh. DPS-L&A-11 at page 10 of schedule 8; exh. DPS-L&A-12 at page 10 of schedule SR8.

6460 Millstone Decommissioning

55. Pursuant to the settlement approved in Docket Nos. 6120 and 6460, and in accordance with a letter to the Board dated September 10, 2002, the Company recorded on its books a regulatory liability equal to the retail amount of Millstone III decommissioning expense included in the Docket Nos. 6120 and 6460 settlement cost of service which were subsequently not billed to or paid by the Company. Gibson pf. at 41-42.

56. Since the Company does not expect to pay this expense in Rate Year 1 or Rate Year 2, the Company continues to increase the regulatory liability up to the day before each rate year begins. Gibson pf. at 41-42.

57. Presently, CVPS is not paying any Millstone III decommissioning expense, and no decommissioning costs are included in the cost of service for either Rate Year 1 or Rate Year 2. Page pf. at 21.

58. The Rate Year 1 rate base balance for the 6460 Millstone Decommissioning regulatory liability should be $382,664, and Rate Year 1 amortization should be $127,555. Schultz and DeRonne pf. at 31; Gibson pf. at 42; exh. DPS-L&A-11 at page 11 of schedule 8.

59. Rate Year 2 rate base should be increased $404,937 to reflect the reduction in the credit balance from $596,268 to $191,331. The amortization credit should be reduced by $110,952 to $127,555. Exh. DPS-L&A-11 at page 11 of schedule 8.

5800 Brockway Mills Refund

60. On July 30, 2003, the Board accepted a proposal by the Company to record a credit received from Brockway Mills, Inc. related to Docket No. 5800 in Account 254.0 (Other Regulatory Liabilities) with carrying costs. Gibson pf. at 42-43.

61. CVPS recorded these savings until the next rate case as a regulatory liability. Gibson pf. at 42-43.

62. The Rate Year 1 rate base balance for the 5800 Brockway Mills Refund regulatory liability should be $161,064, and Rate Year 1 amortization should be $53,688. Schultz and DeRonne pf. at 32; exh. DPS-L&A-11 at page 12 of schedule 8.

63. The removal of Rate Year 1 amortization and carrying costs from the Rate Year 2 rate base balance reduces the credit by $66,305 (from $146,837 to $80,532). Id.

6270 Non-Petitioning Utilities

64. In accordance with Docket No. 6270, the Company received reimbursement for legal fees from non-petitioning utilities that were to benefit from the agreements reached to mitigate the cost of Rule 4.100 Qualifying Facility Contracts with VEPPI. This amount was required to be set aside for the benefit of ratepayers, and to be addressed in the Company's next rate proceeding. Gibson pf. at 43.

65. The Rate Year 1 amortization needs to be removed from the Rate Year 2 rate base balance, which should be reduced by $106,396 from $265,991 to $159,595. The amortization credit in Rate Year 2 does not require an adjustment. Schultz and DeRonne pf. at 32; exh. DPS-L&A-12 at page 13 of schedule 8.

66. The Rate Year 1 rate base balance for the 6270 Non-Petitioning Utilities regulatory liability should be $319,189, and Rate Year 1 amortization should be $106,396. Id.

Summary

67. The deferral account balances and amortization expenses for Rate Year 1 and Rate Year 2 which we find reasonable, in accordance with the findings above, are summarized as follows:

	Balance to Amortize 3/31/04	Amortize or Expense in RY 1	Balance to Amortize 3/31/05	Original Accrual	Per- iod
Regulatory Assets Dkt 5980 DUP DSM83 Dkt 5980 DUP ACE Dkt 6270 IPPs Dkt 6330 Retail Choice Deferred Debits VT Yankee Fuel Rod Repair* VY Incr. Costs due to Sale VY - June 04 Fire Outage* YA Incr. Decommissioning* CY Incr. Decommissioning* Subtotal Reg. Assets & Deferred Debits Regulatory Liabilities 6062 VEPPI Cost Mitigation 6062 VEPPI Cost Mitigation* 6460 Millstone Decom. 5800 Brockway Mills Refund 6270 Non-Petitioning Util. 6460 Earnings Cap 02 & 0384 Subtotal, not incl. earnings cap Total (Net), not incl. earnings cap	$               - 145,830 141,803 6,163 2,770,739 5,954,406 - - - - - - 9,018,941 561,482 - - 382,664 161,064 319,189 TBD 1,424,399 7,594,542	$               - 72,915 47,268 2,054 923,580 1,984,802 835,946 1,917,317 428,140 187,161 373,500 127,555 53,688 106,396 TBD	$               - 72,915 94,535 4,109 1,847,159 3,969,604 - - - - - - 5,988,322 374,321 - - 255,109 107,376 212,793 TBD 949,599 5,038,723	1/01-3/04 7/00-9/04 7/01-11/03 7/01-1/02 6/02, 12/03 9/02-1/03 6/04-7/04 6/03-3-05 12/04-3/05 3/98-3/04 4/04-3/05 3/02-3/05 12/96, 3/03 3/03-4/03 12/02, 03	5 yr. 2 yr. 3 yr. 3 yr. 3 yr. 3 yr. Exp. Exp. Exp. 3 yr. Exp. 3 yr. 3 yr. 3 yr. 4 yr.

* See Section VI.A, below, for a discussion of our decision with respect to these deferral accounts.

Exh. DPS-L&A-11 at pages 3-14 of schedule SR8; exh. DPS-L&A-12 at pages 3-14 of schedule SR8; exh. DPS-CVPS-Joint-2.

68. The rate base effects of our decisions regarding deferral accounts are summarized below:

	RY1 Rate Base per CVPS COS	Rate Year 1 Rate Base Adjustment	RY2 Rate Base per CVPS COS	Rate Year 2 Rate Base Adjustment
Regulatory Assets Dkt 5980 DUP DSM85 Dkt 5980 DUP ACE Dkt 6270 IPPs Dkt 6330 Retail Choice Deferred Debits VT Yankee Fuel Rod Repair* VY Incr. Costs due to Sale VY - June 04 Fire Outage* YA Incr. Decommissioning* CY Incr. Decommissioning* Subtotal of Reg. Assets & Deferred Debits Regulatory Liabilities 6062 VEPPI Cost Mitigation* 6460 Millstone Decom. 5800 Brockway Mills Refund 6270 Non-Petitioning Util. 6460 Earnings Cap 02 & 0386 Subtotal Total (Net), not incl. earnings cap	$        345,417 136,791 118,169 5,136 2,644,783 4,962,005 - - 1,294,322 - - 9,506,623 467,902 318,887 134,220 265,991 2,745,032 3,932,032 5,574,591	$     (345,417) (27,418) - - - - (335,834) - - - - - - - - (708,669) - - - - - - - - TBD - - (708,669)	$        378,779 164,549 118,169 5,136 2,900,125 5,441,060 744,254 2,889,194 382,237 13,023,503 820,205 596,268 146,837 265,991 3,003,094 4,832,395 8,191,108	$     (378,779) (73,854) (47,268) (2,053) (1,514,755) (2,463,856) (744,254) (2,112,601) (368,868) (7,706,288) (539,466) (404,937) (66,305) (106,369) TBD (1,117,077) (6,589,211)

* See Section VI.A, below, for a discussion of our decision with respect to these deferral accounts.

Exh. DPS-L&A-11 at page 1 of schedule SR8; exh. DPS-L&A-12 at page 1 of schedule SR8.

C.  Deferred but Not Subject to Rate Recovery

69. CVPS's deferred accounts include certain deferred debits and regulatory liabilities which are not subject to recovery in rates. Exh. CVPS-JHG-15.

70. The deferred debit for incremental tax expense due to the Vermont Yankee sale does not accrue carrying charges, nor has any tax due to the sale been assessed. Id.

71. In April, 2001, the Board approved an accounting order authorizing CVPS to record SFAS 133 unrealized gain or loss on derivative instruments and hedging activities, including CVPS's sell-back arrangement with Hydro-Québec, as a deferred asset or liability. The deferred asset or liability will be eliminated when the power at issue is delivered at the contract price. No carrying charges accrue on the these balances. Id.

72. In Docket 6545, the Board ordered that any refunds that CVPS receives from Vermont Yankee Nuclear Power Corporation, as its share of any Nuclear Electric Insurance Liability refund (or certain other funds), should be applied to the benefit of ratepayers. The Board required the Company to consider applying these funds for the development and use of renewable resources. In accordance with CVPS's Board-approved plan for using these funds, the Company established a regulatory liability account for these funds, which are kept in an interest-bearing account. No carrying charges accrue on these amounts. Id.

73. The balance in deferral accounts that are not subject to rate recovery are:

	Balance 12/31/03	Carrying Charges
Deferred Debits VY Incr. Tax Due to Sale SFAS 133 Unrealized Loss Regulatory Liabilities SFAS 133 Unrealized Gain NEIL Insurance Refund Total (Net)	$     2,887,218 1,295,800 444,200 461,242 3,277,576	No No No No

Exh. CVPS-JHG-15.

D.  Deferred for GAAP Purposes

74. In order to comply with Generally Accepted Accounting Principles ("GAAP"), the Company maintains certain deferral accounts. Exh. CVPS-JHG-16.

75. The Rural Line Extensions account reflects costs incurred by the Company to construct line extensions on behalf of customers who chose to reimburse the Company under a financing agreement for a period of years. These amounts include finance costs that are paid by the customer, and are reflected as a reduction to the Company's cost of service, according to traditional ratemaking policy. This deferred balance is reduced as customers make payments, and the associated income is recognized. Id. at 1.

76. The Hydro Relicensing Costs account reflects costs (such as environmental studies) incurred by the Company in order to relicense a hydroelectric facility. The costs are deferred until the FERC license is received, at which time the costs are reclassified to Electric Plant in Service, and amortized over the license period, in accordance with GAAP. There are no carrying costs accrued on these deferred costs. Id.

77. The IRS Tax re: VIDA Bonds deferred charge is related to an IRS settlement in 1983 concerning the tax treatment of the interest on bonds issued to finance the Bradford hydro facility. The balance does not accrue carrying charges and is reduced through a monthly amortization to Account 930.2, until 2012. Id.

78. The Intangible Asset-Supplemental Retirement Plan deferred charge represents the unamortized expense for the non-qualified supplemental retirement benefit plan for certain retired officers and directors. There are no carrying costs accrued. The deferred balance is reduced through charges to a non-operating expense (below-the-line) to reflect the current year's expense and declining obligations under this plan. Id.

79. CVPS reflects certain portions of the costs and revenues associated with Yankee Atomic and Connecticut Yankee decommissioning as "deferred for GAAP purposes." In addition, as described above, CVPS's deferral accounts include deferred costs associated with incremental decommissioning expenses, which will be amortized and recovered in rates. Carrying costs are not accruing on the GAAP-deferred balance. The deferred asset balance is reduced as decommissioning costs are incurred and paid to the sponsors. Id. at 2; see finding 46, above.

80. The Company follows the accrual method of accounting, as defined by GAAP. As such, at the end of every accounting period, costs for work performed by employees between the last payroll period-end date and the last day of the accounting period are estimated and recorded to O&M expense and capital projects. This deferred balance represents the accrued payroll related to capital projects. There are no carrying costs accrued. The total balance is reversed in the next accounting period. Id.

81. The Miscellaneous Deferred Debits account includes miscellaneous deferred charges, such as work in progress, items that are to be reimbursed, and items whose proper final disposition is uncertain, in accordance with the FERC definition for Account 186. These items do not accrue carrying charges and are reclassified as receivables, expenses, or assets when additional information is obtained. Id.

82. The New Hampshire Pilot Stranded Costs regulatory liability account is related to the Connecticut Valley Electric Company's New Hampshire pilot program and was written off in 2004 as part of the Connecticut Valley Electric Company sale transaction. Carrying costs were not accrued. Id.

83. The Millstone Asset Retirement Overfunding regulatory liability account is the difference between the SFAS 143 Asset Retirement Obligation and the decommissioning trust fund asset balance. It is not being returned to ratepayers in this rate proceeding because the plant is currently operating and the ultimate decommissioning cost is not known. Carrying costs are not accrued. The liability balance will be ultimately decreased when decommissioning of the asset is complete. Id.

84. There is no dispute about the accounting treatment for costs and revenues that are deferred for GAAP purposes, and we find such treatment is reasonable. The amounts in these accounts are as follows:

	Balance 12/31/03	Carrying Charges
Deferred Debits Rural Line Extensions Hydro Relicensing Costs IRS Tax re: VIDA Bonds Intangible Asset/Suppl. Retirement Plan YA Incr. Decommissioning CY Incr. Decommissioning Accrued Payroll Other Deferred Debits Subtotal Regulatory Liabilities New Hampshire Pilot Stranded Costs Millstone Asset Retirement Subtotal Total (Net)	$           32,358 3,470,481 43,399 201,298 6,345,255 10,347,262 95,615 85,155 20,620,823 50,238 890,507 940,745 19,680,078	Yes No No No No No No No No No

Exh. CVPS-JHG-13 at Attachment PSB 1-1A; exh. CVPS-JHG-16.

Discussion

              In Docket 6866, we considered a Memorandum of Understanding between CVPS and the Department under which the parties agreed that CVPS's rates would be frozen during 2004, with earnings in excess of an allowed 10.5 percent return on equity applied for the benefit of CVPS's ratepayers. During our review of that agreement, we found that CVPS had a high, and swiftly increasing, level of deferred costs on its books, which we found troubling.⁸⁷ We concluded that these large deferrals were a significant concern and observed that the deferred balance had been increasing substantially. We noted that cost deferrals "result in current charges being passed on to future ratepayers, possibly resulting in intergenerational inequities."⁸⁸ When a company adds carrying-costs to deferral accounts, the effect is similar to an increase in rate base for future recovery. Our Order conditionally accepting the MOU reflected our concern; we approved the agreement, but only if both the Department and CVPS affirmatively agreed to a number of conditions which were designed to begin addressing the large deferral account balances. In essence, we found that "level rates for current ratepayers must not be achieved by excessively deferring costs for future ratepayers to bear."⁸⁹

              Neither CVPS nor the Department fully accepted the conditions in the Docket 6866 Order; as a result, our concerns about the level of deferred costs were not then addressed.⁹⁰ The amount of deferred costs remains large -- $23,216,368 (excluding the Docket 6460 Earnings Cap regulatory liability). In these proceedings, CVPS has proposed to reduce its deferral accounts, primarily by recovering the deferred amounts from ratepayers over a three-year period. CVPS acknowledges that recovering these deferred costs will improve its balance sheet from a financial perspective.⁹¹ The Company considers the rate impact of the recovery of these costs through amortization to be small and manageable.⁹² In general, the Department does not oppose these recoveries.

              The reference to deferral accounts actually encompasses a large number of regulatory assets (Account 1823), deferred debits (Account 1860), and regulatory liabilities (Account 2540) that can be broadly grouped into four broad categories, each of which has different rate and policy implications:

• those that are deferred and currently being recovered in rates;
• those proposed to be amortized commencing either in Docket 6946 or Docket 6988;
• those that are deferred, but not subject to rate recovery; and
• those that are deferred for Generally Accepted Accounting Principles ("GAAP") purposes.⁹³

              In these proceedings, we are concerned primarily with the first two categories of deferrals. These categories -- which total $23,216,368 in deferred obligations -- reflect expenses from prior periods that CVPS has deferred, generally pursuant to the terms of Board-issued accounting orders.⁹⁴ In this section, we address four issues:

(1) Whether the amortization of the deferral accounts commences in Rate Year 1 (as proposed by the Department) or Rate Year 2 (as advocated by CVPS);

(2) Whether the amortization period for most deferrals for which CVPS proposes to begin amortizing in these proceedings should be over three years (as proposed by CVPS) or over six years (as recommended by AARP);

(3) Whether we should require CVPS to establish a "reverse" deferral account that would continue to track amortizations after the end of the recovery period, so that these amounts could be returned to ratepayers (in the case of regulatory liabilities) or recovered from ratepayers (for regulatory assets); and

(4)The use of accounting orders for events that are not extraordinary.

In addition, in separate sections of this Order, we address issues concerning specific deferral accounts.⁹⁵

Starting Rate Year for Amortization

              These proceedings are the first rate proceedings since CVPS deferred many of the costs and revenues identified above. Therefore, this is the time for us to decide the recoverability and amortization of those costs. CVPS and the Department disagree on when amortization of deferred costs and revenues should begin -- in Rate Year 1 or Rate Year 2. This issue applies to all of CVPS's deferral accounts for which it is requesting to begin amortization in these proceedings.

              The Company's cost-of-service filings for both Rate Year 1 and Rate Year 2 reflect amortization of the deferred costs net of regulatory liabilities as an expense. However, CVPS did not reduce the deferred balances shown in Rate Year 2 as necessary to reflect the amortizations in Rate Year 1. The Company claims that it did not intend to begin amortization in Rate Year 1, but that the Rate Year 1 amortization was for "illustrative" purposes.⁹⁶

The Company argues that the amortization was reflected in Rate Year 1 "in order to present an accurate Cost of Service . . . ."⁹⁷ CVPS further asserts that the amortization cannot be reflected in Rate Year 1 because, in addition to being "illustrative," it is not "known." CVPS bases this latter argument on two points: first, the Company asserts that it has not recorded the amortization on its books of account. Second, CVPS contends that the accounting orders authorizing the deferrals state that the costs will be deferred until the next "rate proceeding;" thus, the amortization cannot be reflected in Rate Year 1 because Docket 6946 is a "rate investigation," not a "rate proceeding." Finally, CVPS argues that it is wrong to start amortization in Rate Year 1 because CVPS will not have an opportunity to earn its return on equity.

              The Department proposes accounting for amortization of deferred accounts beginning in Rate Year 1, and reflecting the impact of that amortization on the deferred balance in Rate Year 2, in a manner consistent with the Company's original filing.⁹⁸

              For several reasons we conclude that all deferrals should be amortized beginning in Rate Year 1.⁹⁹ First, the accounting orders authorizing the deferrals provided that the amounts would be deferred until the next rate case. Just like Docket 6988, Docket 6946 is a proceeding in which we will determine CVPS's rates. In this regard, there is no distinction between whether the case commenced under 30 V.S.A. Section 227(a) or Section 227(b).¹⁰⁰ Second, commencing the amortization in Rate Year 1 will allow CVPS to recover these expenses and remove them from the Company's books more quickly. Third, amortization in Rate Year 1 will contribute to rate stability by making the rate decrease smaller. If amortization were to begin in Rate Year 2, the rate decrease in Rate Year 1 would be one percent larger.¹⁰¹ Fourth, such treatment provides a close match between the period in which the costs wer e incurred and the time period in which they are expensed. This is important for equity reasons - the ratepayers who benefit from a service should be the ones to pay for it. Finally, beginning amortizations in Rate Year 1 allows CVPS to record them in the same accounting period as it recognizes the 2004 earnings that it deferred pursuant to our February 18, 2005, Accounting Order, thereby also contributing to rate stability.

              We are not persuaded by CVPS's claim that starting amortization in Rate Year 1 will prevent the Company from recovering those costs. This assertion might have some merit if we found that CVPS's Rate Year 1 rates were below its costs. Here, however, we find that CVPS's rates are excessive and must be reduced. The rate reduction we find is necessary includes the amortization as an expense. If we accepted CVPS's proposal to start the amortization in Rate Year 2, the Rate Year 1 rate reduction would be larger, by the amount of the Rate Year 1 amortization expense. CVPS thus fully recovers these costs if, as we require, amortization begins in Rate Year 1.¹⁰²

              We also find no merit in CVPS's assertion that it cannot record this amortization on its books. In fact, we flatly reject CVPS's apparent theory that it can control ratemaking treatment of an issue through its own unilateral decisions about how to book items. The proper purpose of such accounting may be to try to predict regulatory decisions; it is certainly not to supplant them. As CVPS acknowledged at the hearing, it can record the expense in Rate Year 1 if we order it.¹⁰³ We do so here.

              Our decision to begin amortization in Rate Year 1 requires that we adjust the Rate Year 2 amortization expense to reflect the Rate Year 1 recoveries. Through our decision, the amortization of deferrals net of regulatory liabilities is known and measurable in Rate Year 1 and the deferred balances for Rate Year 2 should be reduced by the expense reflected in Rate Year 1.

Amortization Period

              CVPS proposed that the deferred balances should be amortized over three years.¹⁰⁴ The Department agreed with CVPS on the amortization time period. AARP proposes that deferred costs should be amortized over six years, with the understanding that each cost should be included in rate base, and that no carrying costs should accrue once amortization begins. AARP does so to reduce the rate effect of the amortization expense.

              We find that for regulatory assets, deferred debits, and most regulatory liabilities that will begin amortization in Rate Year 1, the amortization period proposed by CVPS is reasonable. These amortization periods provide an appropriate balance between the need to reduce deferred balances quickly, and the benefit of mitigating the rate impact during that time. We understand that, if we amortized the deferrals over a longer period, the annual amortization expense would be less, which would initially cause a larger rate reduction. But such a course would keep the deferrals on the books longer and exacerbate inter-generational equity concerns. Nevertheless, for the reasons we discuss in Section III above, we conclude that a four-year amortization of the earnings cap regulatory liability is appropriate to ensure that ratepayers receive the funds owed them in a timely fashion, while also reducing the impact on the Company's earnings and cash flow.

Reverse Amortization

              We now turn to the ratemaking treatment that should occur when the amortization period of a particular deferred cost or revenue expires, and that amount has been fully amortized.

              The Department recommends that the Board rule that when the amortization period of a regulatory asset ends, any associated rate revenues should be booked as a regulatory liability for the benefit of ratepayers and not flow through to income, which inures ultimately to the benefit of shareholders. The Department proposes that this process be reversed when the amortization period of a regulatory liability ends. The Department maintains that such treatment prevents over-recovery of assets, a violation of generally accepted accounting principles and FERC guidelines.

              CVPS would have the Board rule that when a regulatory asset is fully amortized, the associated rate revenue (that is still being recovered in rates) flows to the Company's current income. The reverse is true for regulatory liabilities. This treatment would be in effect until the Company's next rate change. CVPS argues that this policy provides an incentive for efficient behavior, helps it avoid frequent, expensive rate cases, and is consistent with traditional ratemaking. CVPS contends that the Department's proposal represents a ratemaking policy change, and should be considered more broadly.

              To date, we generally have not required CVPS or other companies to record a reverse amortization expense after the deferral is fully amortized.¹⁰⁵ This means that when an asset is fully recovered, CVPS continues to recover the same amount in rates. As CVPS suggests, at times of rising prices, this can help mitigate the need for rate increases as the Company effectively receives an "increase" as each asset is fully recovered.

              When deferral accounts were used sparingly, this regulatory approach did not have much effect. Now, as we have explained, CVPS has many deferrals. In two years, when the assets that begin amortization in Rate Year 1 are fully recovered, more than one percent of CVPS's rates would be associated with expenses that no longer exist.

              We are thus persuaded that it is appropriate to adopt the policy urged by the Department. To allow the continued recovery of a regulatory asset after it has been fully amortized (and fully recovered in rates), does indeed constitute over-recovery of that asset. Moreover, the fact that the reverse effect is true for regulatory liabilities provides the balance which the Company contends is lacking.¹⁰⁶ Accordingly, our ruling is consistent with the Department's recommendation: upon the expiration of a regulatory asset or liability, the corresponding rate revenue shall be booked as a reverse amortization in an opposing regulatory liability or asset account.

Accounting Orders

              The significant cost deferrals that CVPS seeks to begin to recover through amortization in these proceedings have largely arisen because the Company experiences certain events that increase its expenses. GAAP allows regulators to require a company to record its costs and revenues in a different time period than a non-regulated company would. In Vermont, we authorize such treatment through accounting orders or through explicit rulings in cases that require the Company to record costs and earnings in a specific way. We usually consider accounting order requests without providing general public notice of the request (except to the Department) and without evidentiary hearings.¹⁰⁷ We have counterbalanced this policy by affirmatively stating that the accounting order affected solely the accounting treatment of the relevant costs (or revenues) and that it had no precedential effect on the ratemaking treatment of th ose costs (or revenues). As we ruled in Docket 5983, such limitations are essential, given the abbreviated procedures employed:

We must stress that, in the absence of full notice and opportunity for hearing on a request for an accounting order, such an order will not have final effect in a later rate proceeding under Sections 225-227, and it would be wrong for any party to think otherwise.¹⁰⁸

              One set of costs and revenues that the Board may authorize a regulated company to defer under GAAP are those associated with exceptional or extraordinary events. In fact, the bulk of the deferrals that we consider in these proceedings fall into this category; in reliance upon the Company's assertions that the events which cause these costs or revenues are "extraordinary," we issued a number of accounting orders that allow CVPS to "book and defer" costs and revenues. For example, in 2003 we authorized CVPS to defer the incremental decommissioning expenses for Yankee Atomic and Connecticut Yankee. These were large added expenses that CVPS could not reasonably anticipate.

              An extraordinary event or transaction under GAAP is one that is "abnormally and significantly different from the ordinary and typical activities of the company, and which [sic] would not reasonably be expected to occur in the foreseeable future."¹⁰⁹ The GAAP standard encompasses four key considerations in determining whether an event is "extraordinary," and therefore merits a request for an accounting order. These considerations are:

• Is the amount material?
• Was the event unplanned?
• Was the event beyond CVPS's management control?
• Is the problem unusual, abnormal, and not likely to be repeated?¹¹⁰

              The evidence in these proceedings and our experience with accounting orders raises questions about our recent practice. In particular, we have two sets of concerns: (1) whether we have been issuing such Orders too readily; and (2) whether the current practice is unfairly "one-sided" in that it tends to reflect cost deferrals, but not necessarily revenue deferrals (which would tend to benefit shareholders more than ratepayers). For example, some of the expenses that CVPS seeks to recover through deferrals relate to unplanned outages at Vermont Yankee. CVPS has suggested that such outages meet the GAAP standard because each outage has a different cause.¹¹¹ This interpretation of the GAAP standard, however, fails to consider that breakage at a power plant is not an unusual event. On the contrary, CVPS (in its power planning) and we (in our ratemaking) expect power plants to have outages for reasons that canno t be anticipated (which is why CVPS includes a forced outage rate in the power cost models).

              Similarly, the list of deferrals shows many cost deferrals, but few revenue deferrals. In 2004, for example, CVPS sought an accounting order for $835,000 in incremental replacement power costs associated with a fire at Vermont Yankee. At the same time, CVPS did not request special treatment for a $6.6 million gain that it received on the sale of Connecticut Valley Electric Company. Ratepayers would thus have the costs deferred, but the revenues would, in the absence of an earnings cap, go to shareholders.

              Moreover, CVPS itself acknowledged that it has used accounting orders as a substitute for a fuel adjustment clause.¹¹² The Company suggests that this approach is reasonable since every successful candidate for extraordinary cost treatment need not satisfy all four of these key considerations, but that a balance of these considerations is appropriate.¹¹³ We understand that each event is different and that it is impossible to delineate a bright line test to define extraordinary events. But it seems very unlikely that an event or transaction could be considered extraordinary unless it met all four of the GAAP criteria.

              We are also concerned that broad use of the accounting orders as if they were a fuel adjustment clause has the affect of altering the balance of risks that we consider in setting the Company's return on equity. The risk level we find for CVPS, and on which we base the Company's allowed return on equity, encompasses the fact that Vermont does not have a fuel adjustment clause. If CVPS uses these accounting orders in such a way as to mirror (in large part) the effect of such a clause, we would need to downgrade our assessment of the risks that CVPS faces.

              At the present time, we do not envision specific changes to our accounting order practices. However, we will expect CVPS to better explain how future requests meet the GAAP requirements and, most importantly, why they are extraordinary. In addition, we will give consideration to requiring CVPS to commence amortization in the same manner that it would for plant additions (i.e., at the time the event is completed), rather than deferring those costs indefinitely.

              Finally, we want to make clear that, when we issue an accounting order, we are authorizing the Company to defer such costs, not mandating that treatment. We acknowledge that in the past, some accounting orders included the phrase "is authorized and shall defer . . ." However, this language was not intended to require deferral until the next rate proceeding or to prevent the earlier recovery of the deferred costs, as CVPS has suggested it did.

V.  RATE BASE

              A utility's rate base represents the unrecovered prudent investment in facilities dedicated to the provision of a public service. Upon this rate base, the utility earns a risk-adjusted return comparable to similarly-situated companies. Unlike revenue or expense adjustments, a dollar change in rate base does not result in a dollar reduction in the expected earning potential of a regulated utility. Rather, a dollar reduction in rate base equals a reduction in expected earnings equal to the utilities' cost of capital¹¹⁴ times the amount of the rate base adjustment. Thus, assuming a 10.0 percent cost of capital and a rate base reduction of $100, the expected earnings of a utility would be reduced by $10 per year.¹¹⁵

A.  Plant Adjustments

Findings

Rate Year 1 Plant Adjustments

85. CVPS's original cost-of-service filings included plant additions that would increase the Company's Rate Year 1 rate base by $7.2 million. Some of these proposed plant additions are not known and measurable. As a result, net reductions to CVPS's Rate Year 1 cost of service and rate base, by plant category, are as follows:

Plant Category	Net Rate Base Reductions	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Distribution Substation	($25,846)	($115)	($450)	($654)
Distribution Purchases	($100,998)	($1,499)	($876)	($3,727)
Facilities	($53,929)	($314)	($763)	($1,444)
Information Systems	($119,290)	($5,948)	($4,428)	($13,034)
Communication	($7,431)	($99)	($619)	($374)

Schultz and DeRonne pf. at 4B 5; exh. DPS-L&A-11 at schedule 5; exh. CVPS-CJF-3.

86. CVPS's proposed Distribution Substation plant additions include costs associated with replacing the Bethel Breaker and upgrading the Weybridge 80 and 81 relays. The Bethel Breaker is not scheduled to be in service during Rate Year 1 and there is no documentation to support the cost of the Weybridge relay upgrades. Schultz and DeRonne pf. at 11.

87. CVPS's proposed Distribution Purchases plant additions include blanket work orders for regulators and meters that are significantly higher than the non-growth-related five-year averages for those items. Some of the costs requested for these blanket work orders should be disallowed. Schultz and DeRonne pf. at 13; exh. DPS-L&A-11 at schedule 5.

88. The following proposed Facilities plant additions have been cancelled or deferred beyond Rate Year 1: General office-replace computer room; GO-Switchgear upgrade; Engineering building renovations; the SOB-Tel/Data/SCADA unit; and card readers for fuel dispensers. Schultz and DeRonne pf. at 15; exh. DPS-L&A-11 at schedule 5.

89. CVPS duplicated two of its proposed Information Systems plant additions in its original cost-of-service filing. The duplicates should be removed. Also, the proposed "SAN" expansion does not meet the known and measurable test and should be removed. Schultz and DeRonne pf. at 16.

90. CVPS cancelled two of its proposed Communications Systems plant additions that were related to site improvements. Schultz and DeRonne pf. at 17; exh. DPS-L&A-11 at schedule 5.

91. Deferred hydroelectric relicensing costs in Rate Year 1 amounted to $29,231. As a result, the following changes to CVPS's cost of service and rate base are warranted:

Plant Category	Net Rate Base Addition	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Hydro Re-licensing	$29,231	$225	$0	$1,172

Schultz and DeRonne pf. at 19; exh. DPS L&A-11 at page 2 of schedule SR 3.

92. As a result of adjustments to CVPS's cost of service and rate base, CVPS's proposed rate base should be reduced in Rate Year 1 by $278,263, net of relicensing costs. Accumulated depreciation should be reduced by $7,750, deferred income taxes should be reduced by $7,136, and depreciation expense should be reduced by $18,061, also net of relicensing costs. Exh. DPS-L&A-11 at schedule 5 and page 2 of schedule SR3.

Rate Year 2 Plant Adjustments

93. CVPS's original cost-of-service filings included plant additions that would increase the Company's Rate Year 2 rate base by $20.9 million.¹¹⁶ Exh. CVPS-CJF-7.

94. CVPS's capital budgets for 2005 and 2006 have not yet been approved. Some projects that were originally part of CVPS's cost-of-service filings may be cut as part of the budget approval process. Schultz and DeRonne sur. pf. at 7; tr. 1/10/05 at 175 (G. White); tr. 11/1/04 at 75 (Jones).

Production

95. CVPS did not provide cost support for the Glen Station modernization and Silver Lake Automation projects. In addition, based on the projects' late projected in service date, the projects may slip beyond the end of the rate year. Therefore, the following reductions to CVPS's requested cost-of-service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Production	($436,539)	($2,496)	($6,978)	($11,933)

Schultz and DeRonne pf. at 7; exh. DPS-L&A-12 at page 1 of schedule 5.

Transmission Substations

96. Some of CVPS's proposed additions to Transmission Substation plant are not known and measurable due to unsupported or undocumented costs. As a result, the following reductions to CVPS's requested cost-of-service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Taxes	Depreciation Expense
Transmission Substations	($388,737)	($2,989)	($5,169)	($9,893)

Schultz and DeRonne pf. at 9-10; exh. DPS-L&A-12 at page 1 of schedule 5.

Transmission Lines

97. Some of CVPS's proposed additions to Transmission Line plant are not known and measurable due to unsupported or undocumented costs. As a result, the following reductions to CVPS's requested cost-of-service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Transmission Lines	($353,083)	($1,775)	($5,811)	($8,499)

Schultz and DeRonne pf. at 10B 11; exh. DPS-L&A-12 at page 1 of schedule 5.

Distribution Substations

98. CVPS did not provide any cost support for the Weybridge relay upgrade project. Schultz and DeRonne pf. at 11.

99. CVPS did not provide sufficient information to conclude that a portable transformer will actually be purchased. The Company did not provide evidence to justify its need, and the description provided indicates that the portable transformer is a discretionary item. Schultz and DeRonne pf. at 12.

100. CVPS has not provided any information to support the cost of the new spare substation transformer. In addition, the transformer appears to be a discretionary purchase and it is not known whether it will be acquired. Schultz and DeRonne pf. at 12.

101. CVPS has described the Breaker Replacement as a project for the replacement of old breakers that no longer operate reliably. However, the Company did not provide supporting information regarding this project. Schultz and DeRonne pf. at 12.

102. The following reductions to CVPS's requested cost of service and rate base should be made to remove costs associated with proposed projects that do not meet the known and measurable standard:

Plant Category: Distribution Substations	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Weybridge Relay Upgrade Project	($20,000)	($427)	($578)	($540)
Portable Transformer	($784,615)	($10,474)	($5,768)	($21,747)
Sub. Transformer Replacement Spare	($75,385)	($336)	($1,311)	($1,908)
Breaker Replacement	($54,692)	($230)	($899)	($1,309)

Schultz and DeRonne pf. at 11-13; exh. DPS-L&A-12 at page 2 of schedule 5; findings 98-101, above.

103. Some of CVPS's other proposed additions to Distribution Substations plant are not known and measurable due to unsupported or undocumented costs. As a result, the following reductions to CVPS's requested cost-of-service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Distribution Substations	($117,308)	($658)	($1,870)	($3,042)

Schultz and DeRonne pf. at 12; exh. DPS-L&A-12 at page 2 of schedule 5.

104. Total reductions to proposed Distribution Substation plant additions should be:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Distribution Substations	($1,052,000)	($12,125)	($10,426)	($28,546)

Exh. DPS-L&A-12 at page 2 of schedule 5.

Distribution Purchases

105. CVPS did not provide documentation supporting the inclusion of two meter test equipment purchases in rate base in Rate Year 2. These meter test equipment purchases are considered discretionary. As a result, the following reductions to CVPS's requested cost of service and rate base should be made:

Plant Category: Distribution Purchases	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Meter Test Equipment	($67,398)	($829)	($713)	($2,418)

Schultz and DeRonne pf. at 14; exh. DPS-L&A-12 at page 2 of schedule 5.

106. Some of CVPS's other proposed additions to Distribution Purchases plant are not known and measurable due to unsupported or undocumented costs. As a result, the following reductions to CVPS's requested cost of service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Distribution Purchases	($256,756)	($7,908)	($4,506)	($9,108)

Schultz and DeRonne pf. at 13-14; exh. DPS-L&A-12 at page 2 of schedule 5.

107. Total reductions to proposed Distribution Purchases plant additions should be:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Distribution Purchases	($324,154)	($8,737)	($5,219)	($11,526)

Exh. DPS L&A-12-at page 2 of schedule 5.

Facilities

108. The project identified as SOB-Tel/Data/SCADA was not allowed into rate base in Rate Year 1. CVPS flowed some of the costs associated with that project through to Rate Year 2. As a result, the following reductions to CVPS's requested rate base and cost of service should be made:

Plant Category: Facilities	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
SOB- Tel/Data/SCADA	($25,967)	($619)	($224)	($708)

Exh. DPS-L&A-12 at page 2 of schedule 5; finding 88.

109. Some of CVPS's other proposed additions to Facilities plant are not known and measurable due to unsupported or undocumented costs. As a result, the following reductions to CVPS's requested cost of service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Facilities	($89,046)	($1,611)	($1,926)	($2,532)

Schultz and DeRonne pf. at 15-16; exh. DPS-L&A-12 at page 2 of schedule 5.

110. Total reductions to proposed Facilities plant additions should be:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Facilities	($115,013)	($2,230)	($2,150)	($3,240)

Exh. DPS-L&A-12 at page 2 of schedule 5.

Information Systems

111. CVPS duplicated two of its proposed Information Systems plant additions in its original cost-of-service filing (the Liebert HVAC and the 3835 Replacement). The duplicates should be removed. Also, the proposed "SAN" expansion does not meet the known and measurable test and should be removed. Schultz and DeRonne pf. at 16.

112. CVPS did not provide sufficient information to support the cost of the Main Frame project. In addition, the project's scheduled completion date is so late in Rate Year 2 that the project may not be completed during the rate year. Schultz and DeRonne pf. at 17.

113. The following reductions to CVPS's requested rate base and cost of service should be made to remove costs associated with proposed projects that do not meet the known and measurable standard:

Plant Category: Information Systems	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Liebert HVAC	($71,527)	($6,998)	($6,686)	($4,539)
3835 Replacement	($38,877)	($9,930)	($2,885)	($6,809)
SAN Expansion	($38,600)	($5,345)	($4,734)	($6,751)
Mainframe upgrade	($11,135)	($81)	($197)	($1,056)

Exh. DPS-L&A-12 at page 3 of schedule 5; findings 111-112, above.

114. Some of CVPS's other proposed additions to Information Systems plant are not known and measurable due to unsupported or undocumented costs. As a result, the following reductions to CVPS's requested cost of service and rate base should be made:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Information Systems	($32,502)	($1,596)	($2,294)	($6,463)

Schultz and DeRonne pf. at 17; exh. DPS-L&A-12 at page 3 of schedule 5.

115. Total reductions to proposed Information Systems plant additions should be:

Plant Category	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Information Systems	($192,641)	($23,950)	($16,796)	($25,618)

Exh. DPS-L&A-12 at page 3 of schedule 5.

Communications

116. CVPS's original cost of service filing erroneously omitted $454,494 of proposed Communications plant additions. This error should be corrected. Schultz and DeRonne pf. at 18; exh. DPS-L&A-12 at page 3 of schedule 5.

117. CVPS did not provide sufficient support for the requested video conferencing equipment. Schultz and DeRonne pf. at 18.

118. CVPS cancelled two of its proposed Communications Systems plant additions that were related to site improvements. Exh. DPS-L&A-12 at page 3 of schedule 5; finding 90.

119. The following reductions to CVPS's rate base and cost of service should be made to remove costs associated with proposed projects that do not meet the known and measurable standard:

Plant Category: Communication Systems	Net Rate Base Reduction	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Video Conference Equipment Unit Pilot	($10,164)	($85)	($973)	($483)
Video Conference Equipment	($7,692)	($16)	($152)	($209)
Site Improvements/ Additions	($9,975)	($483)	($1,595)	($504)
Emergency Generator Site	($5,250)	($275)	($831)	($264)

Exh. DPS-L&A-12 at page 3 of schedule 5; findings 117-118, above.

120. Total additions to proposed Communications Systems plant additions should be:

Plant Category	Net Rate Base Addition	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Communications Systems	$381,279	$11,771	$52,170	$18,770

Exh. DPS-L&A-12 at page 3 of schedule 5.

121. CVPS incurred costs to relicense its hydroelectric dams. Those costs have been deferred. As a result, the following increases to CVPS's cost of service and rate base should be made:

Plant Category	Net Rate Base Addition	Accumulated Depreciation	Def. Inc. Tax	Depreciation Expense
Hydro Re- licensing	$1,431,538	$15,299	$0	$51,780

Schultz and DeRonne pf. at 19.

122. As a result of adjustments to CVPS's cost of service and rate base, the Company's proposed rate base should be reduced in Rate Year 2 by $1,049,350, net of relicensing costs. Similarly, accumulated depreciation should be reduced by $27,232, deferred income taxes should be reduced by $379 and depreciation expense should be reduced by $28,705, net of relicensing cost. Schultz and DeRonne pf. at 19; exh. DPS L&A-12 at page 3 of schedule 5 and schedule SR3.

Discussion

              Plant investment is typically the largest component of a utility's rate base. This investment is constantly changing as utilities acquire new plant and perform periodic maintenance and replacement of their existing plant. When the Board sets rates for an investor-owned utility such as CVPS, it determines the utility's plant investment for the test year, and then adjusts that investment for known and measurable changes.¹¹⁷

              CVPS's plant investment at the end of the test year in the instant proceedings was approximately $483 million.¹¹⁸ The Company's original cost-of-service filings in these proceedings include additions to utility plant investment that increase CVPS's Rate Year 1 rate base by $7.2 million, the Company's Rate Year 2 rate base by $20.9 million. CVPS asserts that all these proposed additions are known and measurable. The DPS disagrees with this assertion, arguing instead that many of the Company's proposed additions are not known and measurable. However, in a recommendation that is more lenient than traditional Vermont ratemaking practice, the DPS does not propose that the Board disallow all the costs associated with proposed plant additions that are not known and measurable. Instead, the DPS contends that the Board should allow a percentage of unsupported plant costs (with the percentage varying by type of plant ), because it is reasonable to expect that some non-growth-related capital spending will occur, and it is appropriate for CVPS to earn a return of and on plant necessary for the Company to meet its service quality and reliability standards.¹¹⁹

              Our evaluation of CVPS's proposed plant additions begins with a review of the known and measurable standard, as defined by the Vermont Supreme Court, and as applied by this Board. The Vermont Supreme Court has defined the known and measurable standard as "changes that are measurable with a reasonable degree of accuracy and have a high probability of being in effect in the adjusted test year."¹²⁰ The Board has consistently held, including in CVPS's last fully-litigated rate case, that witnesses' representations alone are not sufficient support for a project to meet the Court's known and measurable standard. Rather, the Board has required some tangible work-product that shows that the project is likely to actually be completed; examples include work orders, cost-benefit analyses, or other types of written support for a project's cost and completion date.

              In these proceedings, we conclude that CVPS has not met its burden of showing that all of its proposed additions meet the known and measurable standard. CVPS failed to provide appropriate cost support for many of its projects, and did not demonstrate that all of its proposed projects would be in service during the appropriate rate year. CVPS attempted to overcome this lack of documentation by asserting that all of its projects were known and measurable because they have gone through the Company's capital budgeting process and experts within the Company had stated that they would occur.¹²¹ We are not persuaded by this argument. The Company's own witness admits that CVPS's capital budgets for 2005 and 2006 have not yet been approved, and that some projects included in CVPS's cost-of-service filing may be cut during the budget approval process.¹²² In addition, the DPS has shown that some projects th at were included in past capital budgets were later cancelled.

              The DPS identifies several specific projects included in CVPS's cost-of-service filings that do not meet the known and measurable standard,¹²³ and recommends that the Board disallow the costs associated with these projects. After reviewing the evidence and the parties' arguments, we conclude that these proposed adjustments are reasonable, and we hereby accept them.

              We also accept the DPS's recommendation that we depart from a strict application of the known and measurable standard, and allow CVPS to include in rates a portion of the costs that it has not shown meet that standard. No party has opposed allowing this portion of CVPS's costs in rates, and we determine that such an approach is appropriate in these particular circumstances. Therefore, and without ruling on the merits of the DPS's underlying rationale, we accept the DPS's proposed levels of plant additions to be included in rate base.

              In addition, we accept an adjustment to CVPS's Rate Year 1 and Rate Year 2 rate bases and costs of service that is agreed upon by CVPS and the DPS. This adjustment corrects an omission in CVPS's original cost-of-service filings related to deferred hydroelectric relicensing costs.

              Thus, for the reasons explained above, we conclude that CVPS should reduce its proposed Rate Year 1 rate base by $278,263, and its Rate Year 2 rate base by $1,049,350. In addition, CVPS should make the corresponding reductions to accumulated depreciation, deferred income taxes, and depreciation expense that are shown in findings 92 and 122, above.

              Two additional items deserve discussion. First, CVPS argues that all of its proposed projects are necessary for the Company to provide service to customers, and that it is inappropriate for the Board to deny recovery of the costs associated with these projects. This argument reflects a misunderstanding about the issue before us today. We are not being asked to decide whether CVPS will ever be allowed to recover the costs associated with a particular project. Rather, we are being asked to determine whether it is appropriate for CVPS to recover now the costs associated with a particular project that has not yet been implemented. It is very possible that some of the projects we determine are not known and measurable today will occur in the future. If so, CVPS can request recovery of the costs associated with those projects at such time as it can show that the projects are known and measurable.

              Finally, we are concerned about the level of support CVPS filed in support of its proposed plant additions in these proceedings. This same issue arose in CVPS's last fully-litigated rate cases. In those cases, the Board rejected certain proposed changes to the Company's rate base because of a lack of supporting documentation. The Board stated that:

The company provides no support for capital additions beyond the statements of a company witness. More specifically, there are no exhibits, workpapers, underlying work orders and associated cost/benefit analysis that would enable either the Department or the Board to conclude that these investments are indeed interim period non-growth related investments.¹²⁴

              We expect CVPS to present such supporting information for its proposed capital additions with its initial testimony in its future rate cases.

B.  Accumulated Depreciation

Findings

123. CVPS's proposed rate base for Rate Year 1 includes an average accumulated depreciation balance of $218,353,000. CVPS's proposed rate base for Rate Year 2 includes an average accumulated depreciation balance of $218,978,000. Exh. CVPS-CJF-3; exh. CVPS-CJF-7.

124. CVPS's Rate Year 2 accumulated depreciation should be increased by $15,299 to correct an error in CVPS's original cost-of-service filing related to hydroelectric relicensing costs. Schultz and DeRonne pf. at 19.

125. For each proposed plant addition that is disallowed, there is a corresponding adjustment to accumulated depreciation. CVPS's accumulated depreciation should be reduced by $7,975 in Rate Year 1 and $42,529 in Rate Year 2 to reflect the changes to CVPS's plant balances. Schultz and DeRonne pf. at 19; exh. DPS-L&A-11 at schedule 5; exh. DPS-L&A-12 at page 3 of schedule 5.

126. Rates currently being collected by CVPS assume recovery of depreciation expense. Depreciation is being recorded on CVPS's books. Tr. 11/2/04 at 152 (Gibson); tr. 1/11/05 at 76-78 (Frankiewicz).

127. CVPS's method for calculating its adjustment to accumulated depreciation is to increase test-year accumulated depreciation by 50 percent of the test-year depreciation expense. Frankiewicz reb. pf. at 3.

128. CVPS's method for calculating interim-period depreciation results in an average accumulated depreciation for Rate Year 1 of $214,707,441. However, the accumulated depreciation balance on the books of the Company on March 31, 2004, (the day before Rate Year 1 begins) is $216,722,616. Exh. DPS-34; tr. 1/11/05 at 75-78 (Frankiewicz).

129. CVPS's method for calculating interim-period depreciation results in an average accumulated depreciation for Rate Year 2 of $222,737,225. Given that, according to CVPS's original cost-of-service filings, CVPS's accumulated depreciation balance as of March 31, 2004, (the day before Rate Year 1 begins) is $216,714,895, and that CVPS has requested annual depreciation expense of $16,059,627, this means that CVPS's accumulated depreciation balance at the beginning of Rate Year 2 will be $232,774,522. It is not mathematically possible to have an average Rate Year 2 balance of $222,737,225 when the beginning balance is $232,774,522. Schultz and DeRonne reb. pf. at 21; exh. DPS-L&A-10.

130. CVPS's original filing includes an error in the calculation of annualized test-year depreciation expense. This expense was $16,059,627 ($1,338,302 per month) in the original filing, while the correct amount should be $16,090,512 ($1,340,876 per month), for an annual difference of $30,888, or 0.19 percent. Exh. DPS-34.

131. If the correct amount of monthly depreciation is used, CVPS's accumulated depreciation balance as of March 31, 2004, (the day before Rate Year 1 begins) is $216,722,616, and its accumulated depreciation balance at the beginning of Rate Year 2 is $232,813,128. Using these amounts in the analysis shown in finding 129, above, does not change the conclusion; CVPS's average accumulated depreciation for Rate Year 2 is still less than the accumulated depreciation balance at the start of Rate Year 2. Exh. DPS-L&A-10; findings 129-130, above.

132. The interim-period adjustment to accumulated depreciation should be calculated as follows:

• Add interim-period depreciation to the accumulated depreciation balance at the end of the test year to determine the accumulated depreciation balance at the end of the interim period;
• Average the accumulated depreciation balance at the end of the test year and the accumulated depreciation balance at the end of the interim period to determine the average interim-period accumulated depreciation balance;
• Subtract the average interim-period accumulated depreciation balance from the average test-year accumulated depreciation balance to determine the interim-period adjustment to accumulated depreciation.

Schultz and DeRonne sur. pf. at 19.

133. The rate-year adjustment to accumulated depreciation should be calculated as follows:

• Add rate-year depreciation to the accumulated depreciation balance at the end of the interim period to determine the accumulated depreciation balance at the end of the rate year;
• Average the accumulated depreciation balance at the end of the interim period and the accumulated depreciation balance at the end of the rate year to determine the average rate-year accumulated depreciation balance;
• Subtract the average rate-year accumulated depreciation balance from the average interim-period accumulated depreciation balance to determine the rate-year adjustment to accumulated depreciation.

Schultz and DeRonne sur. pf. at 19.

134. CVPS's average Rate Year 1 accumulated depreciation balance should be increased by $4,015,000 to reflect interim-period and rate-year depreciation. Schultz and DeRonne pf. at 20-21; exh. DPS-L&A-11 at page 1 of schedule 6.

CVPS's average Rate Year 2 accumulated depreciation balance should be increased by $20,075,000 to reflect interim-period and rate-year depreciation. Schultz and DeRonne pf. at 21; exh. DPS-L&A-12 at page 1 of schedule 6.

Discussion

              Depreciation is the accounting convention that defines the pace at which utilities should recover the cost of their prudently-incurred investment in physical "plant" that is used to serve ratepayers. Accumulated depreciation is the sum of all the depreciation a utility has already collected from its ratepayers on its plant that remains in service, plus amounts collected for net salvage and future cost of removal of that plant.¹²⁵ Each year, a utility's accumulated depreciation increases by the amount of depreciation expense that it records in its financial books, and decreases by the amount of accumulated depreciation on plant that is retired. For ratemaking purposes, gross plant is reduced by accumulated depreciation to arrive at the net plant on which a company earns a return. An increase in accumulated depreciation has the effect of reducing the rate base upon which a return is earned. Thus, an i ncrease in accumulated depreciation results in a reduction in ultimate rates. The converse is also true -- a decrease in accumulated depreciation has the effect of increasing the rate base upon which a return is earned, thereby resulting in an increase in ultimate rates.

              The DPS argues that CVPS's accumulated depreciation should be adjusted in four ways:

(1) to correct an error in CVPS's original cost-of-service filing related to hydroelectric relicensing costs (this applies to Rate Year 2 only);

(2) to reflect the DPS's recommended disallowances of additions to CVPS's plant balances;

(3) to reflect changes to depreciation expense resulting from the DPS's recommendations regarding net salvage rates; and

(4) to properly reflect interim-period and rate-year depreciation.

              CVPS does not contest the correction of the error relating to hydroelectric relicensing costs. It also does not contest the principle that accumulated depreciation should be adjusted to reflect changes in plant balances,¹²⁶ although it does contest the DPS's recommended changes to its plant balances (see the discussion in Section V.A, above). CVPS does not directly address the DPS's proposed changes resulting from its recommendations regarding net salvage rates; however, CVPS does contest CVPS's proposed changes to those rates (see the discussion in Section VI.D, below). In addition, CVPS acknowledges that accumulated depreciation should be adjusted to reflect interim-period depreciation, although it contests the methodology that the DPS uses to calculate interim-period depreciation. Finally, CVPS argues that accumulated depreciation should not be increased to reflect rate-year depreciation.

              We have reviewed the uncontested adjustment related to hydroelectric relicensing costs described in finding 124, above, and conclude that it is appropriate and should be made. We have also reviewed the DPS's proposed adjustment to accumulated depreciation to reflect changes in CVPS's plant balances. Accumulated depreciation should be adjusted to be consistent with plant account balances. Since we have accepted the DPS's proposed adjustments to plant balances (see Section V.A, above), it is necessary to make the corresponding adjustments to accumulated depreciation. Therefore, we accept the DPS's proposed adjustment to accumulated depreciation shown in finding 125, above.

              We do not accept the DPS's proposed $903,634 reduction to the average Rate Year 1 accumulated depreciation balance, and $2,710,902 reduction to the average Rate Year 2 accumulated depreciation balance. The DPS proposes these reductions in order to reflect its recommended change in depreciation expense related to net salvage rates.¹²⁷ As explained in Section VI.D, below, we have rejected the DPS's recommended change in depreciation expense related to net salvage rates. Consequently, it is not appropriate to make the corresponding reductions to the Rate Year 1 and 2 average accumulated depreciation balances.

Interim Period and Rate Year Depreciation

              We now turn to the issue of adjusting accumulated depreciation to reflect interim-period and rate-year depreciation.

              Vermont ratemaking uses a historic test year adjusted for known and measurable changes. The Vermont Supreme Court has held that, while the Board's discretion is broad, it may not reject an adjustment that is unquestionably known and measurable.¹²⁸ The Vermont Supreme Court made that statement when it required the Board to adjust test-year rate base for interim-period depreciation because (1) interim-period depreciation is known and measurable, and (2):

. . . once customers have, in effect, returned a portion of a utility's investment, they should not be required to pay for that portion a second time, once as depreciation expense and again as a return on plant value which had not been correspondingly reduced to reflect the "return of" the investment through depreciation expense payments.¹²⁹

The same principles apply to rate-year depreciation; both interim-period and rate-year depreciation are known and measurable amounts already reflected in rates as an expense. In both instances, ratepayers will have returned a portion of a utility's investment. Therefore, under the Vermont Supreme Court's standard, ratepayers should not be required to pay for that portion a second time, and the Board must recognize an adjustment to accumulated depreciation for interim-period and rate-year depreciation.

              The Vermont Supreme Court's decision in In re GMP does address the issue of interim-period depreciation, as CVPS suggests.¹³⁰ However, the logic of the Supreme Court's decision extends beyond simple recognition of interim-period depreciation and mandates that we incorporate adjustments that are known and measurable. The Supreme Court clearly set out the public policy reason for applying the known and measurable change principle to the test-year rate base -- to ensure that ratepayers do not pay for the same portion of a utility's investment twice, once as depreciation expense, and a second time as return on plant value which had not been reduced to reflect the return of a portion of the investment through depreciation expense payments. This principle applies to rate-year depreciation just as to interim-period depreciation; ratepayers will pay depreciation expense in the rate year, the amount of that exp ense is known and measurable, and a utility's rate base should be adjusted to reflect the recovery of that portion of its investment from ratepayers. It would be wrong for the Board to ignore the core rationale of the Vermont Supreme Court's decision in In re GMP and to limit the Court's holding only to the issue of interim-period depreciation.

              We also reject CVPS's assertion that the anti-updating provisions of 30 V.S.A. Section 225(a) undermine the Vermont Supreme Court's rationale in In re GMP by denying a utility an "ample opportunity" to present evidence of plant additions during the rate year.¹³¹ This assertion is not plausible on its face. Section 225(a) was in effect at the time the Supreme Court issued its decision in In re GMP,¹³² yet that decision stated that GMP had had an ample opportunity to introduce evidence regarding its rate-year plant additions.¹³³ We have to infer that the Vermont Supreme Court understood 30 V.S.A. Section 225(a)'s mandate at the time it considered GMP's appeal. Since the statute has not changed, the Vermont Supreme Court's decision still controls.

              More significantly, CVPS did have an ample opportunity to present evidence regarding its plant additions. This opportunity was at the time that CVPS filed its costs of service in these rate cases. CVPS chose not to present sufficient evidence at that time, even though the Company knew of the limits imposed on updating by 30 V.S.A. Section 225(a). Instead, CVPS provided insufficient evidence to show that its plant additions were known and measurable, and then tried to update the support for its plant additions with additional evidence months later, after the DPS pointed out the deficiencies in CVPS's initial filing. The DPS challenged this additional evidence on the grounds that it violated the anti-updating provisions of 30 V.S.A. Section 225(a). After reviewing the DPS's objection, and CVPS's response to it, we struck the additional evidence from the record.¹³⁴ It is inappropriate for the Company to now b lame the DPS and Vermont law for the consequences of its own timing decisions.

Calculation Methodology for Interim Period and Rate Year Depreciation Adjustments

              Given that we have decided that adjustments should be made for interim-period and rate-year depreciation, we must next determine the appropriate calculation for these adjustments.

              The DPS asserts that the correct methodology for calculating the adjustments for interim-period and rate-year depreciation is that which the Board has applied in recent cases involving other Vermont utilities (Dockets 6596 and 6914).¹³⁵ Essentially, this methodology calculates (1) an interim-period adjustment that is the difference between the average interim-period accumulated depreciation balance and the average test-year accumulated depreciation balance; and (2) a rate-year adjustment that is the difference between the average rate-year period accumulated depreciation balance and the average interim-period accumulated depreciation balance.¹³⁶

              CVPS has calculated the interim-period depreciation adjustment using the methodology that the Board approved in Dockets 5701/5724, CVPS's last litigated rate cases. No adjustment was made in those dockets for rate-year depreciation, and CVPS did not calculate a rate-year depreciation adjustment in the instant proceedings.

              We have reviewed both parties' arguments regarding the two proposed methodologies, and conclude that the DPS's methodology should be applied in these proceedings, for the reasons explained below. Therefore, we accept the DPS's proposed adjustments to average accumulated depreciation of $4,015,000 in Rate Year 1, and $20,075,000 in Rate Year 2.¹³⁷

              Most importantly, the DPS's methodology is consistent with the Vermont Supreme Court's decision in In re GMP because it adjusts CVPS's accumulated depreciation for all known and measurable changes (not just interim-period depreciation), and because it ensures that ratepayers do not pay twice for the same investment.

              Second, the DPS's proposed methodology is identical to the calculation methodologies that we applied in both the Docket 6596 Order and the Docket 6714 Order, and is related to the methodology that the Board had considered in Docket 5532, the case that led to the In re GMP ruling from the Vermont Supreme Court. Thus, the DPS's proposed methodology is consistent with recent Board precedent.¹³⁸

              Third, and importantly, the DPS has shown that CVPS's methodology for calculating its adjustment to accumulated depreciation produces mathematically impossible results in which CVPS's average rate-year accumulated depreciation balance is less than CVPS's accumulated depreciation balance at the beginning of the rate year (see findings 128 and 129, above). This persuades us that CVPS's methodology does not protect ratepayers from paying twice for the same investment as In re GMP requires. Therefore, rates based on CVPS's methodology would not be just and reasonable, and we must revisit the interim-period calculation methodology that we accepted 10 years ago in Dockets 5701/5724 in order to arrive at just and reasonable rates.¹³⁹

              We are not persuaded by CVPS's multiple arguments in support of its position on this issue. First, CVPS claims that because its methodology has not been found to be unjust or unreasonable, it should be accorded a presumption of reasonableness.¹⁴⁰ As explained above, we reach the opposite conclusion C using CVPS's methodology would not result in just and reasonable rates. None of CVPS's other arguments can overcome this fundamental failing of its proposed methodology. Nevertheless, the discussion below addresses CVPS's other arguments regarding this issue.

Case-by-Case Development of the Law

Many of CVPS's arguments in support of its methodology fail to recognize the critical role of case-by-case evolution in the development of the law,¹⁴¹ and the responsibility of a tribunal to "discard(s) the old rule when it finds that another rule of law represents what should be according to the established and settled judgement of society."¹⁴² Given these well-established legal principles, CVPS should not be surprised that during the 10 years since the Board issued its order in Dockets 5701/5724 (CVPS's last fully-litigated rate cases), the Board has modified some of the ratemaking methodologies that it accepted in those dockets. It would be incorrect for the Board to apply to CVPS only those methodologies that it accepted in Dockets 5701/5724, and to ignore any orders it has issued in the last 10 years in litigated cases involving companies other than CVPS that altered those ratemaking methodologies.¹⁴³

              Similarly, it is inconsistent with the case-by-case development of the law (not to mention the seven-month standard of Title 30) for CVPS to assert that the Board should convene a proceeding or workshop for all utilities before making changes to any previously accepted ratemaking methodology. The Board must resolve disputed issues in cases before it. It is impractical, unrealistic, and contrary to judicial economy, to expect the Board to never change a regulatory policy or calculation methodology, except in generic proceedings that involve all the state's utilities.

              In addition, CVPS's argument that any significant changes to accumulated depreciation should only be implemented prospectively in a subsequent proceeding is incompatible with well-established administrative law precedent that policies may be changed at the same time they are applied.¹⁴⁴ This precedent makes clear that, contrary to CVPS's assertions, it is not unfair to apply a result that is consistent with other cases in which CVPS was not a party. The question before the Board in the instant proceedings is: what is the appropriate accumulated depreciation adjustment calculation methodology for CVPS to use? CVPS was certainly given notice in the DPS's direct prefiled testimony that this would be an issue in these proceedings, and the Company had an opportunity during the rebuttal phase of these proceedings to present evidence regarding the appropriateness of applying the DPS's proposed methodology to C VPS.

Precedential Nature of Board's Orders in Dockets 6596 and 6914

              Contrary to CVPS's assertions,¹⁴⁵ the Docket 6596 Order and the Docket 6914 Order are precedential. We find CVPS's multiple, scatter-shot arguments related to this issue to be unpersuasive and either inaccurate or irrelevant to the decision before us in these proceedings. Many of the Company's assertions relating to these two orders are addressed elsewhere in this Order; the discussion below focuses only on those not addressed elsewhere.

• It is irrelevant that the Docket 6596 Order did not reference prior Board or Vermont Supreme Court decisions related to accumulated depreciation, and did not state that the Board was establishing a new methodology that was to be used in all future cost-of-service studies. It is not necessary for a Board order to cite previous relevant Board and Vermont Supreme Court decisions in order for the order to be precedential. In addition, it is not necessary for a Board order to explicitly state that a particular decision should apply to other utilities in the future in order for it to serve as precedent. CVPS appears to confuse notice-and-comment rulemaking with common-law contested-case adjudication.

• The methodology we approved in Dockets 6596 and 6914 is different than that accepted by the Board 11 years ago in Dockets 5701/5724, and the two methodologies do produce different results. However, given the case-by-case evolution in the development of the law, the fact that the two methodologies differ and produce different results does not affect our decision regarding which will produce just and reasonable rates in the instant proceedings.

• No party has suggested that Citizens' agreement to the DPS's rate-year methodology in Docket 6596 should be extended to CVPS. We understand that CVPS does not agree to the DPS's proposed adjustment; that is why the issue is before us to resolve. However, the mere fact that CVPS has not agreed to a concept does not mean that this Board must reject that concept.

• Some small elements of the Docket 6914 Order may or may not have ambiguities;¹⁴⁶ however, that is irrelevant to our decision today regarding which methodology is most appropriate to use in the instant proceedings.

              We reject CVPS's characterization of the interim-period and rate-year accumulated depreciation adjustment methodology approved by the Board in Docket 6596 as a "utility-specific penalty on Citizens."¹⁴⁷ Nowhere in the Docket 6596 Order does it state, or imply, that the accumulated depreciation adjustment we approved in that Order was a "penalty." We assume this is a reading error by CVPS, rather than a misrepresentation of the Board's Order.

Timing of Challenges

              We reject CVPS's argument that it is appropriate for the Company to continue to use its proposed methodology for calculating the appropriate adjustment to accumulated depreciation because neither the DPS nor the Board challenged that methodology in any of CVPS's rate cases since Dockets 5701/5724 (until the instant proceedings). All of CVPS's rate cases since Dockets 5701/5724 resulted in bottom-line settlement agreements among the parties or were closed without resolution. It is unpersuasive for CVPS to argue now that a methodology should not be changed because the old methodology was not challenged in cases that were settled or closed. Furthermore, as the Board stated in Docket 5983:

. . . the rate-making process relies upon the use of evidentiary presumptions to facilitate reaching a conclusion about the overall justness and reasonableness of rates without requiring an exhaustive review of hundreds or thousands of detailed cost of service items in every rate case; according to Board practice, in each rate case, a utility's filing receives the benefit of a rebuttable presumption that 'expenditures claimed to support the rates were reasonable and prudent.' Rate proceedings then focus on those aspects of a filing that parties choose to examine and present to the Board.¹⁴⁸

It is unrealistic to expect the DPS to challenge every possible issue in every rate case; and CVPS's litigation costs would be far higher over time if we accepted its argument to that effect today. As the Board stated in Docket 5983, requiring the DPS to litigate every potential cost item in every rate case would be "an outcome inimical to the administrative process, and likely impossible to comply with within the statutory period allowed for utility rate cases."¹⁴⁹ This same rationale applies to the Board. The Board can, and often does, raise issues in rate cases that no party has addressed. However, it is not feasible for the Board to review in detail every item not addressed by a party. Thus, the fact that neither the DPS nor the Board challenged CVPS's methodology for calculating the adjustment to accumulated depreciation in CVPS's prior rate cases is unpersuasive. The issue has been raised in these proceedings, and in this Order, we resolve the dispute regarding it.

Retroactive Ratemaking

              Given the schedule in Docket 6946, which CVPS itself proposed, Rate Year 1 is almost over. That does not mean, however, that we are engaging in prohibited retroactive ratemaking by applying the DPS's proposed methodology to CVPS in Rate Year 1.¹⁵⁰ On the contrary, 30 V.S.A. Section 227(b) specifically provides that when the Board, on its own motion, opens an investigation into a utility's rates, the final order shall be retroactive.¹⁵¹ Our decision today is consistent with the statute's requirements that we (1) determine just and reasonable rates, and (2) apply our decision regarding those rates retroactively.

Cost Recovery

              CVPS asserts that the DPS's proposed adjustment violates 30 V.S.A. Section 218(a), because, according to the Company, it denies CVPS the opportunity to recover the costs of the plant necessary to serve customers, thereby making the Company's rates "insufficient."¹⁵² This is not so -- the DPS's proposed adjustment does not deny CVPS recovery of its legitimate costs, it simply ensures that the Company only recovers those costs once.

              Finally, CVPS argues that the DPS's adjustment reduces the Company's ability to recover the costs of its capital assets, promotes more frequent utility rate cases, and burdens regulatory lag.¹⁵³ This argument is closely linked to CVPS's assertions regarding its inability to provide evidence supporting its rate-year plant additions, because of the anti-updating provisions of 30 V.S.A. Section 225(a). We have already addressed CVPS's arguments regarding this point. CVPS chose not to present supporting evidence at the time the statute requires such evidence to be presented. If the results of the Company's decision are more frequent utility rate cases and increased regulatory lag, CVPS must accept responsibility for the consequences of its own actions.

Correction to Annualized Test Year Depreciation Expense

              No party has asked that the depreciation expense and accumulated depreciation calculations be revised to reflect CVPS's correction of its annualized test-year depreciation expense described in finding 130, above. Nevertheless, we conclude that the error should be corrected. Therefore, we require CVPS, as a part of its compliance filing in these proceedings, to modify the DPS's recommended adjustments to rate-year average accumulated depreciation in both Rate Years 1 and 2 to reflect the correct value of annualized test-year depreciation expense.¹⁵⁴

C.  Distributed Utility Planning Demand-Side Management

Findings

136. CVPS is seeking recovery of Distributed Utility Planning Demand-Side Management expenditures incurred from January 1, 2001, through December 31, 2003. The total Distributed Utility Planning Demand-Side Management expenditures for this period, including carrying costs and adjustments, are $359,864. These expenditures are reasonable, as they were incurred to acquire demand-side management resources from high use customers in identified constrained transmission and distribution areas in CVPS's service territory. Welch pf. at 2; exh. CVPS-JHG-14 at Attachment PSB 1-2.

137. Under the terms of the Memorandum of Understanding approved by the Board in Dockets 6120 and 6460, CVPS's current base rates include the collection of $195,546 each year for recurring Distributed Utility Planning Demand-Side Management costs. This Memorandum of Understanding became effective July 1, 2001. Therefore, only half that amount, or $97,773, was collected from ratepayers in 2001 for recurring Distributed Utility Planning Demand-Side Management costs. Welch pf. at 2-3; tr. 1/12/05 at 160-161 (Frankiewicz).

138. CVPS's Distributed Utility Planning Demand-Side Management expenditures for 2001 through 2003 should be adjusted for the amount of recurring Distributed Utility Planning Demand-Side Management costs recovered from ratepayers in rates during those years. When this calculation is performed, CVPS's Distributed Utility Planning Demand-Side Management deferral account has a negative balance of $184,479. Welch pf. at 2-3; tr. 1/12/05 at 161-162 (Frankiewicz).

139. All of the amounts associated with the Distributed Utility Planning Demand-Side Management regulatory asset should be removed from CVPS's cost of service and rate base because CVPS has already fully recovered these amounts from ratepayers. The removal results in a $76,759 reduction to amortization expense and a $345,417 reduction to rate base in Rate Year 1. In Rate Year 2, the removal results in a reduction to amortization expense of $84,173 and a reduction to rate base of $378,779. Schultz and DeRonne pf. at 24-25; exh. DPS-L&A-11 at page 2 of schedule 8, and schedule 15; exh. DPS-L&A-12 at page 2 of schedule 8, and schedule 15.

140. The ($184,479) balance in CVPS's Distributed Utility Planning Demand-Side Management deferral account should be returned to ratepayers. Tr. 1/12/05 at 161-162 (Frankiewicz).

141. The adjustments to the balance in CVPS's Distributed Utility Planning Demand-Side Management deferral account should be reflected in the calculation of CVPS's overearnings in 2001, 2002, and 2003, pursuant to the 6120/6460 MOU. Tr. 1/13/05 at 14 (Schultz).

Discussion

              There is no dispute regarding the amount of CVPS's Distributed Utility Planning Demand-Side Management expenditures for the period 2001 through 2003 that is appropriate to be recovered. There is also no dispute regarding the amount of recurring Distributed Utility Planning Demand-Side Management expenditures that were included in CVPS's rates during that time period. There is a dispute regarding how those recurring expenditures should be used to adjust the amount of Distributed Utility Planning Demand-Side Management expenditures that CVPS now seeks to recover.

              The Board's January 11, 1995, Order in Dockets 5701/5724 granted CVPS's request to amend the Board's October 31, 1994, Order in those same dockets so that it was clear that:

. . . the Company dedicate all C&LM [Conservation and Load Management] dollars [that are] included in its rate year cost of service as C&LM Recurring Amounts to its C&LM programs and that any amounts not expended in a particular year for such purposes be held for use in subsequent years or for eventual return to ratepayers.¹⁵⁵

              The DPS argues that the amount of CVPS's Distributed Utility Planning Demand-Side Management costs should be adjusted in each year (2001, 2002, and 2003) by the amount of recurring Distributed Utility Planning Demand-Side Management expenditures collected from ratepayers in those years. When this calculation is performed, and any amounts not spent in a particular year are carried forward to future years, the balance in CVPS's Distributed Utility Planning Demand-Side Management deferral account is a negative $184,479.

              CVPS does not contest that all Distributed Utility Planning Demand-Side Management amounts reflected in CVPS's last rate case cost of service that were not expended in a particular year for such purposes should be held for use in subsequent years.¹⁵⁶ In addition, CVPS admits that ratepayers are entitled to a refund of $184,479.¹⁵⁷ However, CVPS argues that the adjustment for recurring expenditures should only be made in 2001. The Company asserts that the adjustment should not be made in 2002 or 2003 because CVPS was subject to an earnings cap, and the recurring amounts not properly applied to 2002 and 2003 Distributed Utility Planning Demand-Side Management balances caused part of CVPS's overearnings adjustment that is included in its overearnings regulatory liability. CVPS argues that the DPS's adjustment is not necessary for years 2002 and 2003 because the appropriate amount will be returned to ratepayers through the overearnings adjustment. CVPS further asserts that if the Board does accept the DPS's adjustment to Distributed Utility Planning Demand-Side Management balances, the Board should reduce the overearnings deferral amounts to avoid double counting these amounts.¹⁵⁸

              CVPS is correct in noting that making the DPS's proposed adjustment for recurring Distributed Utility Planning Demand-Side Management expenditures for 2002 and 2003, without making a corresponding adjustment to CVPS's overearnings for those years, would result in a double recovery by ratepayers. This logic is similar to that which underlies our determination in Section V.B regarding interim-period and rate-year accumulated depreciation. There, we required an adjustment to ensure that ratepayers do not pay CVPS twice for the same investment; here, we require an adjustment to ensure that CVPS does not pay back ratepayers twice for the same refund.

              To properly implement the requirements of our January 11, 1995, Order in Dockets 5701/5724, we conclude that the adjustment for recurring Distributed Utility Planning Demand-Side Management expenditures should be made in each of the three years (2001, 2002, and 2003), effectively removing the Distributed Utility Planning Demand-Side Management asset from the list of deferral accounts shown on exh. CVPS-4A. Based on the Board's January 11, 1995, Order in Dockets 5701/5724, the difference between what CVPS collected in rates for Distributed Utility Planning Demand-Side Management recurring expenses, and its actual expenses in 2001, 2002, and 2003, ($184,479) should be returned to ratepayers.¹⁵⁹ We require CVPS to reflect this decision in its compliance filing in these proceedings.

              Furthermore, to avoid double-recovery by ratepayers, our decisions regarding CVPS's Distributed Utility Planning Demand-Side Management deferral account, including our decision that the excess recurring expenses be returned to ratepayers, should be reflected in the calculation of CVPS's overearnings in 2001, 2002, and 2003. As explained in Section III, we require CVPS to recalculate its overearnings for 2001, 2002, and 2003, using the cost-of-service methodology proposed by the DPS, as modified by the Board. Consistent with our decision that CVPS should not have deferred its Distributed Utility Planning Demand-Side Management costs because it had already recovered them from ratepayers, the Company's actual Distributed Utility Planning Demand-Side Management expenditures in each of those three years should be included in the calculation of its overearnings for 2001, 2002, and 2003. In addition, CVPS's return to ratepayer s of $184,479 in excess Distributed Utility Planning Demand-Side Management collections should be included in the 2003 overearnings calculation.

D.  Distributed Utility Planning Account Correcting for Efficiency ("ACE")¹⁶⁰

Findings

142. The formula for calculating ACE is gross lost revenue minus the production savings and other incremental operational savings experienced by CVPS during the calculation period. Welch pf. at 4; Gibson pf. reb. At 16-17.

143. The avoided costs used to compute ACE should be adjusted for the latest available market price information and forecasts for the remainder of the period. Bentley reb. pf. at 2-3; Welch pf. at 3-4.

144. The balance in the Distributed Utility Planning ACE deferral account, including carrying costs, as of March 31, 2004, should be $145,830. Exh. DPS-L&A-11 at page 3 of schedule 8.

145. The balance of the Distributed Utility Planning ACE deferral account should be amortized over two years. Gibson pf. at 37; Docket No. 5980, Order of 9/30/99 at A-19 (Paragraph 33 of the Memorandum of Understanding).

Discussion

              CVPS and the DPS agree in principle on the formula that should be used to calculate ACE. They also agree that the most recent information available should be used to calculate the production savings component of the ACE calculation. However, they disagree about the most recent avoided cost information. As a result, they have calculated slightly different Distributed Utility Planning ACE amounts.

              CVPS and the DPS also disagree on when the amortization of the balance in the Distributed Utility Planning ACE deferral account should start. CVPS argues that it should begin at the start of Rate Year 2 while the DPS asserts that it should begin at the start of Rate Year 1. For the same reasons articulated in Section IV, above, regarding when the amortization of other deferral accounts should begin, we conclude that the amortization of the Distributed Utility Planning ACE deferral account should begin at the start of Rate Year 1.

              Given this decision, it is necessary for us to determine the balance in the Distributed Utility Planning ACE deferral account as of March 31, 2004, the end of the interim period. The most recent information available should be used to calculate the production savings component of the ACE calculation, and the latest calculations of the Distributed Utility Planning ACE amount were performed by CVPS; the DPS did not address these calculations. However, CVPS did not provide the balance in the deferral account as of March 31, 2004, including carrying costs.¹⁶¹ Based on the evidence in the record, the difference between the DPS's and CVPS's positions regarding the balance in the deferral account at the beginning of Rate Year 1 is likely to be de minimus.¹⁶² Since the only number in the record for the balance as of March 31, 2004, is the DPS's, and the difference appears to be so small, we will ac cept the DPS's number of $145,830.¹⁶³

              However, we do not accept the DPS's recommendation regarding the changes in the balance of the Distributed Utility Planning ACE deferral account during Rate Years 1 and 2. The DPS correctly determined the amount of monthly amortization ($6,076) by dividing the balance in the deferral account at the start of Rate Year 1 by 24.¹⁶⁴ But the DPS also added to the balance in the deferral account the Distributed Utility Planning ACE related to the energy efficiency measures projected to be installed during each month of Rate Year 1.¹⁶⁵ This is not consistent with past practice in Vermont.

              Traditionally, the Board approves recovery of a specified amount in an ACE deferral account, and that amount is amortized in even increments over two years. At the end of the two-year amortization period, the ACE deferral account is fully amortized.¹⁶⁶ ACE associated with any new energy efficiency installations is deferred in a new deferral account until the utility's next rate proceeding, when it is reviewed for its appropriateness before cost recovery is allowed.¹⁶⁷ The DPS has argued that it is appropriate to change Board policy and establish what is in essence a "revolving" Distributed Utility Planning ACE account in order to ensure that CVPS does not overcollect Distributed Utility Planning ACE by continuing to collect amortization in rates beyond the point at which the deferral account is fully amortized.¹⁶⁸ This is a valid concern; however, we believe it is better addressed throu gh the concept of "reverse amortization", which we explain in more detail in Section IV. Reverse amortization will ensure that ratepayers do not pay twice for Distributed Utility Planning ACE deferral costs, while preserving the opportunity for the Board to review the appropriateness of the Distributed Utility Planning ACE deferral costs for recovery in a rate case.

              Therefore, the formula for determining the change in the balance in the Distributed Utility Planning ACE deferral account that is used on page 3 of schedule 8 of both exh. DPS-L&A-11 and exh. DPS-L&A-12 (unamortized monthly balance = prior month's unamortized monthly balance + Distributed Utility Planning ACE amounts due to new installs - current month's amortization) should be adjusted to remove the amounts shown under the column labeled "Installs." Instead, each monthly balance should be the previous monthly balance less the current month's amortization. When this simple mathematical calculation is performed, the Distributed Utility Planning ACE deferral account's 13-month average balance for Rate Year 1 is $109,373, and the Distributed Utility Planning ACE amount included in CVPS's rate base in Rate Year 1 should be reduced by $27,418.¹⁶⁹

              In addition, the DPS took the balance in the deferral account at the start of Rate Year 2 and divided it by 24 to determine the amount of monthly amortization in Rate Year 2. This is also incorrect. Once the monthly amortization is determined for the deferral account, it should remain constant (at $6,076 per month) until the balance in the deferral account is eliminated. Using the unamortized balance in the deferral account as of the start of Rate Year 2, and the same formula for calculating each month's unamortized balance, the Distributed Utility Planning ACE deferral account's 13-month average balance in Rate Year 2 is $36,458, and the Distributed Utility Planning ACE amount included in CVPS's rate base in Rate Year 2 should be reduced by $128,091.¹⁷⁰

              In each rate year, the total amortization expense is $72,915 ($6,076 * 12 months). Compared to CVPS's original cost-of-service filing, this represents a reduction to Distributed Utility Planning ACE amortization expense in Rate Year 1 of $18,279, and a reduction to Distributed Utility Planning ACE amortization expense in Rate Year 2 of $36,784.

VI.  COST OF SERVICE

A.  Power Costs

Findings

146. CVPS receives the bulk of its power, both capacity and energy, from Vermont Yankee and the Hydro Quebec Joint Owners Contract ("Hydro-Quebec"). These two sources provide a total of about 320 MW of capacity and a projected 2.12 million MWh of energy in Rate Year 1 and 2.28 million MWh of energy in Rate Year 2. Watts pf. at 4.

147. CVPS owns or purchases energy produced by hydro facilities in Vermont and New Hampshire which exceeds 250,000 MWh in an average year, receives about 150,000 MWh annually (on average) through its ownership of the Millstone 3 nuclear plant, and owns or has entitlements in other generation sources that produce about 125,000 MWh annually for CVPS. Watts pf. at 4.

148. CVPS is entitled to, and committed to, purchase more energy from its power supply resources than it currently needs to meet its own expected demand requirements in most hours of the year, except for time periods when Vermont Yankee is not generating. CVPS's resources can deliver up to 235 MW around-the-clock and meet a peak load capacity of 415 MW. CVPS's load averages 275 MW, ranging from approximately 205 MW to 360 MW, depending upon the time of day and year. Watts pf. at 5.

149. CVPS sells excess power back through the New England wholesale market and through bilateral contracts. This occurs in most hours of the year. Watts pf. at 6; Lamont pf. at 2.

150. Since CVPS is a net seller on the market, its revenues are directly affected by the market price for power. Recent increases in the market price of power have allowed CVPS to sell back its excess power at a higher price. Watts pf. at 9; Lamont pf. at 2-3.

151. The Connecticut Valley Electric Company sale (described in part VI.B of this Order) reduced CVPS's energy demand requirements by about 130,000 MWh. Watts pf. at 8.

The Power Cost Stipulation

152. CVPS and the Department entered into an agreement resolving most power cost issues.

153. The Net Power Costs (Purchased Power and Production Fuel) for Rate Year 1 are $128.389 million. Of this, Purchased Power is $124.863 million and Production Fuel is $3.526 million. For Rate Year 2, the Net Power Costs are $124.777 million, consisting of $121.864 million in Purchased Power and $2.913 million for Production Fuel. Exh. DPS-CVPS Joint-2.

154. The effective forced outage rate for Vermont Yankee for both rate years is 2.12 percent.¹⁷¹ Exh. DPS-CVPS Joint-2 at 1.

155. The Rate Year 1 Purchased Power Costs reflected in finding 153 include the following amounts as expenses:

2004 Vermont Yankee Fire Outage                  $835,900

Small Power Provider Savings                        ($373,500)

CY/YA¹⁷² Incremental Decommissioning     $2,345,200

Exh. DPS-CVPS-Joint-2 at 1.¹⁷³

156. Transmission by Others includes charges CVPS incurs for general use of the region's Pooled Transmission Facilities and VELCO's transmission system, as well as other specific charges for facilities CVPS uses. Watts pf. at 22.

157. Transmission by Others costs are $13.562 million in Rate Year 1 and $14.895 million in Rate Year 2, of which $9.202 million and $10.604 million, respectively, are VELCO costs. Exh. DPS-CVPS Joint-2 at 2.

158. The Transmission by Others figures reflect the favorable impact of the Highgate convertor station receiving phased-in Pooled Transmission Facilities treatment beginning February 2005. This reduced costs by $45,000 in Rate Year 1 and $575,000 in Rate Year 2. Exh. DPS-CVPS Joint-2 at 2.

2002 Vermont Yankee Mid-Cycle Outage

159. Findings 29-35, above, are incorporated by reference.

Nuclear Decommissioning Costs

160. Findings 43-49, above, are incorporated by reference.

Docket 6270 Savings

161. Findings 50-54, above, are incorporated by reference.

2004 Vermont Yankee Fire Outage

162. Findings 39-42, above, are incorporated by reference.

Discussion

              Power costs represent the largest component of CVPS's cost-of-service. Purchased power alone -- largely from Vermont Yankee and Hydro-Quebec -- is nearly half of CVPS's cost-of-service. Thus, CVPS's management of its power supply costs can significantly impact the overall rate levels.

              At the present time, CVPS has entitlements for more power than it needs. In most hours of the day, CVPS has excess energy and capacity, which it sells through bilateral contracts with other utilities or through the New England wholesale market. From a ratemaking perspective, the Board has traditionally allowed CVPS to include the cost of all of its power resources in the power costs, even if those were not necessary to serve Vermont load. To balance these charges, we have consistently included the revenues from these wholesale arrangements (adjusted to reflect the market prices expected to prevail in the adjusted test year). This regulatory treatment means that Vermont ratepayers benefit from the sale of the excess power, particularly if the market price for power in these wholesale transactions exceeds the costs of the power.¹⁷⁴ Moreover, energy efficiency savings also produce a benefit for Vermont ratepay ers as they allow CVPS to sell more power than the Company otherwise would have. Significantly for the present case, wholesale power costs have risen well above the level in the 1990s and the test year. The effect is that a company like CVPS, which has power available for sale, will be earning more from wholesale transactions than in prior years and thus needing less revenue from its retail customers.

              In this case, the Department and CVPS have largely agreed on the power costs for both rate years. They embodied this consensus in a Power Cost Agreement.¹⁷⁵ In the Power Cost Agreement, these parties specify the appropriate costs for Purchased Power, Production Fuel, and Transmission by Others for each of Rate Years 1 and 2. The Agreement did not resolve all disputes, however. Instead, the parties deferred several specific issues to the Board for resolution. We address each of these below.

2002 Vermont Yankee Mid-Cycle Outage

              During 2002, Vermont Yankee experienced an unanticipated shutdown to replace defective fuel rods. The fuel rods had developed small leaks and were releasing radiation into the core. Vermont Yankee had identified the problem earlier in the year and, after investigation, decided that the best option was to shutdown the facility to remedy the problem (rather than waiting for the scheduled refueling outage in October of that year).

              The Mid-Cycle Outage lasted 12 days. The loss of the Vermont Yankee power forced CVPS to acquire replacement power. CVPS also incurred other expenses for Vermont Yankee's operation and maintenance expenses to remedy the problem and replace the defective fuel. At CVPS's request, we issued an accounting order on July 18, 2002, authorizing CVPS to defer these incremental costs. Subsequently, Vermont Yankee received partial compensation from the fuel vendor; CVPS reduced the deferral amount based upon its share of these recoveries. CVPS now seeks recovery of the remaining deferral amount.

              The Department generally does not oppose the recovery of the amounts deferred from the 2002 Mid-Cycle Outage. However, the Department points out that during the rest of 2002, Vermont Yankee had an output greater than the Board had assumed in setting CVPS's rates in 2001 (Dockets 6120/6460). According to the Department, the parties had used a 4 percent forced outage rate in formulating the stipulation in that case; Vermont Yankee's actual performance was much better during 2002, particularly after factoring out the Mid-Cycle Outage for which CVPS was already expected to receive compensation.¹⁷⁶ The Department takes the position that in determining the appropriate amount that CVPS can recover, we should assess the financial harm to CVPS of Vermont Yankee's under-performance and not limit our ruling to the time period of the Mid-Cycle Outage.¹⁷⁷

              CVPS argues first that the Department's proposed adjustment has no impact on rates as a downward adjustment to the Mid-Cycle Outage regulatory asset would lead to a similar downward adjustment to overearnings in 2002.¹⁷⁸ In addition, CVPS argues that the Department's proposal is not consistent with the terms of the Mid-Cycle Outage Accounting Order, which was limited to the period of the outage.¹⁷⁹ Finally, CVPS states that, if the Board makes an adjustment, the proper amount is $403,000, not the amount the Department had previously recommended.¹⁸⁰

              Vermont Yankee is a favorably-priced source of power for CVPS; when it is not operating, CVPS must purchase replacement power (or use its excess resources, losing the resale revenues), often at higher prices. To reflect this in ratemaking, we assume that Vermont Yankee will be unavailable a certain percentage of the time and that other sources will provide the power during that time. We embody these assumptions in a forced outage rate, which is typically derived based upon the recent operating performance of Vermont Yankee. For example, in this proceeding, the Department and CVPS have agreed that the rates we set here should be based upon a 2.12 percent forced outage rate.¹⁸¹ Of course, actual performance does not necessarily reflect these assumptions. If Vermont Yankee's operating performance matches the assumptions incorporated into the forced outage rate, CVPS benefits in the form of lower power cos ts than we had assumed. Conversely, CVPS bears the risk that Vermont Yankee produces less power than assumed and its earnings may be adversely affected. Typically, we do not attempt to recapture these gains or compensate CVPS for its losses (the performance would be incorporated into the forced outage rate for the next rate case).

              CVPS's deferral of the costs associated with the 2002 Mid-Cycle Outage alters this normal allocation of risk. Instead of CVPS incurring the higher costs that arise because Vermont Yankee performed less well than expected, the deferral assigns these costs to CVPS's ratepayers. In this situation, we conclude that CVPS should offset the deferral amount by the better-than-average performance to mitigate the effect of the shifting of risk allocation. Both the Department and CVPS agree that the value of the gain is $403,000 and we accept that figure.

              We find the terms of the accounting order in which we authorized the deferral do not require a different result. First, as we have explained elsewhere in this Order,¹⁸² accounting orders do not dictate ratemaking treatment. The determination of the appropriate amount that CVPS can recover in rates was deferred to this proceeding. Second, to the extent that CVPS is now attempting to use accounting orders as substitutes for fuel adjustment clauses,¹⁸³ fairness dictates that the adjustment cannot be one-way.¹⁸⁴ Yet the effect of CVPS's proposal is to obtain recovery for the part of the year when Vermont Yankee's performance was worse than expected, while ignoring the superior performance in the surrounding period.

              We agree with CVPS that our ruling on this issue may not have any impact on the ultimate rates. CVPS excluded the deferred amount from its overearnings calculation for 2002. As a result of our decision, CVPS will reduce the deferral amount to be recovered through amortizations starting in Rate Year 1, but it will also need to adjust the amount of the deferral excluded from the 2002 overearnings calculation. The evidence suggests that these two amounts will offset.

Expensing of VEPPI Cost Mitigation, Incremental Decommissioning Costs, and 2004 Vermont Yankee Fire Outage

              In Section IV, above, we describe CVPS's various regulatory assets and liabilities. In its original filing, CVPS proposed to amortize most of these deferrals over three years beginning in Rate Year 2. The Company also included the same amortizations (or, in the case of the 2004 Mid-Cycle Outage, the full expense) in Rate Year 1. CVPS characterized these as illustrative, pro forma adjustments. In its later filings and brief, CVPS removed the Rate Year 1 amortizations for most of these accounts. The Department supports commencing the amortization of all of these accounts in Rate Year 1, with corresponding adjustments to Rate Year 2 to reflect the amortization that occurred in Rate Year 1. Above, we adopt the Department's recommendation, for the reason we explained.

              In the Power Cost Agreement, CVPS and the Department identify three particular cost items that these parties agree should be either treated as an expense in Rate Year 1 or deferred with amortizations to begin in Rate Year 2. The three items are as follows:

• 2004 Vermont Yankee Fire Outage. In June, 2004, Vermont Yankee experienced an outage due to a busbar fault and subsequent transformer fire. CVPS incurred $836,000 in incremental replacement power costs as a result. The Board authorized the deferral of the added costs of the 2004 Fire Outage in an Interim Accounting Order dated July 12, 2004, although we subsequently stayed portions of that Order and deferred a final accounting order to this proceeding.¹⁸⁵ CVPS also reflected the costs of the 2004 Fire Outage in Rate Year 1 as expenses.¹⁸⁶

• VEPPI Cost Mititgation. CVPS receives credits from VEPPI as a result of agreements approved by the Board in Docket 6270. CVPS proposes to amortize these credits, as a reduction to purchased power costs. A portion of the credits are incremental in Rate Year 1 and the Department seeks to expense them instead of deferring and amortizing the credits.

• Incremental Decommissioning Expenses. CVPS will need to pay incremental decommissioning expense associated with Maine Yankee, Yankee Atomic, and Connecticut Yankee during Rate Year 1. The Board authorized CVPS to defer these incremental decommissioning expenses in an Accounting Order dated October 29, 2003.¹⁸⁷

              In the Power Cost Agreement, the parties reflected each of these items as expenses in Rate Year 1, but continued to request that the Board decide whether to expense the item in that Rate Year or defer and amortize the costs beginning in Rate Year 2.¹⁸⁸ The Department takes the position that CVPS should either reflect the costs as expenses in Rate Year 1 or defer them for recovery starting in Rate Year 2, but not both. The Department asks us to adopt the former approach.¹⁸⁹ CVPS favors deferring these costs and amortizing them beginning in Rate Year 2. CVPS asserts that the costs for the decommissioning and VEPPI cost mitigation were erroneously included in Rate Year 1 as an expense.¹⁹⁰ CVPS takes the position that absent such treatment, CVPS will have no ability to recover them. According to CVPS, it has a revenue deficiency in Rate Year 1; expenses added in Rate Year 1 exacerbate that deficiency and deny CVPS any opportunity to recover these deferred costs.

              We conclude that, particularly in light of the fact that we find CVPS to have excess earnings in Rate Year 1 -- even after reflection of these three items as expenses -- it is reasonable to incorporate them as expenses now rather than create another set of deferrals that will be charged to future ratepayers (or, in the case of the VEPPI mitigation, serve as a credit). In the case of the 2004 Vermont Yankee Fire expense, it is undisputed that the actual expense occurred in Rate Year 1.

              As to CVPS's claim that deferral and amortization is necessary in order to allow CVPS to recover these costs (or ratepayers to receive the benefit of the VEPPI credit), we disagree. In this Order, we find that CVPS must reduce its rates in Rate Year 1. Inclusion of these cost items will have the effect of making the reduction smaller. Moreover, by including them in our cost analysis, we have allowed CVPS to recover them.¹⁹¹

              Our decision today means that the accounting order associated with each of these expenses (and credit) will terminate. The full rate recovery in Rate Year 1 makes such treatment moot.¹⁹²

              It is possible that CVPS will be reimbursed for some or all of the expenses of the 2004 Vermont Yankee Fire Outage. As part of a Memorandum of Understanding with the Department in Docket 6812, Entergy has established a Ratepayer Protection Plan, under which Entergy will reimburse CVPS and GMP for replacement power costs (and lost resale revenues) arising from outages at Vermont Yankee caused by the power uprate authorized in that Docket and the plant modifications that enabled that power increase. CVPS has requested that the Board determine whether the 2004 Fire Outage was uprate-related and thus whether Entergy is obligated to provide reimbursement.¹⁹³ The Department raised concerns during the instant cases that, if CVPS is successful, the recovery may not be passed on to ratepayers.

              We expect that CVPS will ensure that any recovery from Entergy will be returned to ratepayers. The purpose of the Ratepayer Protection Plan was to ensure that ratepayers were not exposed to higher costs due to uprate-related outages at Vermont Yankee. Failure to return this money to ratepayers would defeat this purpose, given that in today's Order we are allowing CVPS to recover in rates the costs of the 2004 Vermont Yankee Fire Outage. Thus, we direct that, if CVPS receives full or partial reimbursement from Entergy, the Company will book the amount received as a regulatory liability for return to ratepayers in the next rate proceeding.

Levelization of Decommissioning Costs

              The Department raises concerns about the timing of the decommissioning expenses for Connecticut Yankee, Maine Yankee, and Yankee Atomic (jointly referred to as the "Yankee" plants). Because of increased costs for decommissioning these three facilities, CVPS reflects high costs in both Rate Years 1 and 2. After that time, CVPS's expected decommissioning obligation is smaller (assuming current estimates remain unchanged). As a result, the Department is concerned that reflection of the actual Yankee decommissioning expenses for Rate Years 1 and 2 will lead to "significant overpayment by ratepayers in years subsequent to Rate Year 2."¹⁹⁴ The Department's proposed remedy is to levelize the decommissioning expenses over the period from April 1, 2004, through 2010.¹⁹⁵

              CVPS opposes levelization of the Yankee decommissioning expense. CVPS takes the position that, if we levelize the decommissioning expense, CVPS will recover significantly less than it must pay during the early years, which adversely affects its cash flow and denies the Company an opportunity to earn its allowed return.¹⁹⁶ CVPS also notes that levelization would increase the regulatory asset balances and impose a cash flow constraint on the Company.¹⁹⁷

              The evidence demonstrates that CVPS will have to pay the actual Yankee decommissioning costs, not the levelized rate. If we adopted the Department's proposal, we would thus embed in CVPS's rates a cost component that we know is below the Company's actual costs. We are not persuaded that, considering the magnitude of the change in decommissioning costs after this year (which is small in relation to CVPS's overall cost of service)¹⁹⁸ and the possibility that those costs will change again in the future, such a course is reasonable.

              Moreover, the Department's proposal would have future ratepayers pay the costs for decommissioning that are associated with expenses that are arising today. As a general rule, the Board's policy has been that current ratepayers should pay for current costs. Using this rationale, we agree with CVPS that current ratepayers should be paying for increased decommissioning costs.¹⁹⁹

              We are concerned, however, that the decommissioning costs that we use for setting rates are in excess of those that will apply after Rate Year 2. Therefore, beginning April 1, 2006, we will require CVPS to book and defer the difference between the decommissioning cost for Rate Year 2 on which we set rates and the actual decommissioning cost payments.²⁰⁰ CVPS will amortize the balance in this account in its next rate case.

Treatment of Decommissioning Costs

              In its cost-of-service filings, CVPS includes the decommissioning costs for Connecticut Yankee, Yankee Atomic, and Maine Yankee as part of purchased power expense. According to the Department, none of these plants is operating, so the costs are not actually power costs.²⁰¹ Therefore, the Department asks that we classify these costs as non-fuel production. CVPS maintains that the FERC chart of accounts requires these costs to be recorded as purchased power expense.²⁰²

              The parties agreed that the outcome of this dispute has virtually no monetary impact;²⁰³ there is no significance for rate setting if the decommissioning costs are recorded in purchased power or in non-fuel production. Given this fact, it appears that the only significance is whether FERC accounting will be the same as Board accounting. CVPS's proposal would align our accounting with FERC, whereas the Department's would not.²⁰⁴ For this reason, we adopt CVPS's recommendation to continue recording the decommissioning costs in purchased power accounts.

B.  Sale of Connecticut Valley Electric Company

Findings

163. CVPS sold the assets of its New Hampshire subsidiary, Connecticut Valley Electric Company ("CVEC"), to Public Service Company of New Hampshire ("PSNH") effective January 1, 2004. Gibson pf. at 2, 7.

The Sale Transaction

164. CVPS sold the assets of CVEC at the sum of book value plus $21 million. Gibson pf. at 19.

165. The $21 million payment was intended to cover stranded costs associated with CVPS's provision of wholesale power to CVEC. The intent of the payment was to hold CVPS's ratepayers harmless from the effects of the termination of the CVEC power arrangement that otherwise would have meant a shift of costs to Vermont retail ratepayers. Gibson pf. at 19; Deehan reb. pf. at 12; exh. DPS-37.

166. As part of the transaction, CVEC and CVPS allowed the wholesale power agreement between them to end. PSNH also received open access transmission service from VELCO and CVPS. Deehan reb. pf. at 12.

167. The $21 million represented the parties' estimate of the loss to CVPS from termination of the power contract. At the time of closing, the estimated loss became $14.351 million, resulting in a $6.649 million gain for CVPS which the Company recorded on January 1, 2004.²⁰⁵ Schultz and DeRonne pf. at 65.

168. On January 1, 2004, CVPS recorded the estimated loss of $14.351 million and a future liability for power costs through 2016. CVPS proposed to amortize the liability over 12 years as a reduction to the actual power cost obligation recorded and paid each year. Schultz and DeRonne pf. at 64; tr. 1/12/05 at 46-47 (Gibson).

169. The sale of CVEC eliminated the risk that significant power costs incurred to serve CVEC customers would be shifted to CVPS's customers as a result of restructuring in New Hampshire. Deehan reb. pf. at 12-13; Gibson pf. at 7, 18-19.

Events Prior to the Sale

170. On February 28, 1997, the New Hampshire Public Utility Commission ("NHPUC") adopted a restructuring plan that found that CVEC should terminate its wholesale requirements power agreement with CVPS and ruled that no above-market (or stranded costs) recovery would be allowed in CVEC's rates. Deehan reb. pf. at 9.

171. Implementation of the NHPUC's restructuring order would have had a material adverse impact on the Company. It also would have required CVPS to record a loss contingency at that time of $75 million under SFAS 5. Deehan reb. pf. at 9, 13; exhs. CVPS-WJD-4, CVPS-8, CVPS-9, and CVPS-10.

172. CVPS challenged the NHPUC's restructuring order in federal court. After years of litigation, the U.S. District Court permanently enjoined the NHPUC's restructuring plan, determining that until FERC established stranded cost compensation and the wholesale arrangement was legally terminated, the restructuring plan could not proceed. Deehan reb. pf. at 9.

173. CVPS also participated in litigation at FERC concerning the NHPUC's Order. CVPS charged all of the costs of the FERC litigation to CVEC. Frankiewicz reb. pf. at 23.

174. As a result of the federal litigation (generally referred to as the "Patch" case), the loss contingency estimated at $75 million in 1997 dropped to $33 million in 2001 and $14.6 million at the time of the sale on January 1, 2004. Deehan reb. pf. at 9-10.

Cost-of-Service Effects

175. CVPS will flow the stranded cost payment from PSNH back to Vermont retail customers in the form of credits. Deehan reb. pf. at 14; exh CVPS-WJD-5.²⁰⁶

176. Prior to the sale, CVEC compensated CVPS for costs associated with operations, maintenance, and infrastructure services provided by CVPS to CVEC through direct assignment of costs, to the extent that these costs could be identified. In addition, CVPS entered into a service contract with CVEC to allocate a share of other costs, such as infrastructure costs, that could not be directly assigned. Tr. 11/2/04 at 144-145 (Gibson); tr. 11/3/04 at 85-86 (Gibson).

177. As part of the sale, CVPS terminated the service contract with CVEC. Schultz and DeRonne pf. at 70.

178. The sale of CVEC causes a loss of some economies of scale and scope that CVPS enjoyed through the ownership of CVEC. Gibson pf. at 20.

179. CVPS took some steps to mitigate cost impacts of the CVEC sale, such as closing the Ascutney Service Center and the transfer of employees who worked in CVEC's service territory. Gibson pf. at 21.

180. Only a few employees left CVPS as a result of the CVEC transfer. Schultz and DeRonne pf. at 64.

181. CVPS cannot readily reduce many of the fixed costs that had been allocated to CVEC. These include costs such as the computer network necessary to meet customer service obligations. These general operating costs are shared by the consolidated entity, so that with the sale of CVEC, the remaining customers of CVPS must pick up all of the costs. Gibson pf. at 20; Schultz and DeRonne pf. at 64.

182. Largely because of the CVEC sale, the allocation of costs to wholesale services dropped from 4.73 percent to 1.1 percent. Tr. 11/2/04 at 17 (Frankiewicz).

183. The change in the allocation of wholesale costs means that the sale has the effect of transferring approximately $1.846 million annually in costs to CVPS and its Vermont retail ratepayers. These cost increases would not have occurred if CVEC had not been sold. Schultz and DeRonne pf. at 63; tr. 11/2/04 at 145-147 (Gibson); tr. 1/11/05 at 99-100 (Frankiewicz).

184. The power costs that are stranded and are reallocated through the wholesale allocation factors comprise Purchased Power, Production, Transmission by Others, Highgate, and Other Operating Expenses and Return. Tr. 1/11/05 at 103 (Frankiewicz)

185. The termination of the service contract, by which direct costs as well as cost allocations for general corporate overhead were assigned to CVEC, results in the transfer of $1.9 million in Rate Year 1, and a slightly larger increase in Rate Year 2, to Vermont customers. Tr. 11/2/04 at 145-147 (Gibson); Deehan reb. pf. at 14-15.

186. Most of the costs associated with the service contract are for administrative and general expenses. Other costs are for production, transmission, distribution, customer accounting, and customer service. Exh. CVPS-55.

187. In Rate Year 1, $1.327 million of the service contract costs are administrative and general. In Rate Year 2, this figure is $1.405 million. After assigning a proportionate share of payroll taxes, these amounts increase to $1.376 million and $1.456 million, respectively.²⁰⁷ Collectively, the other categories of expenses allocated under the service contract total to $0.536 million in Rate Year 1 and $0.558 million in Rate Year 2. Exhs. CVPS-CJF-2 and CVPS-CJF-6; exh. CVPS-55.

Discussion

              For over 70 years, CVPS owned and operated a New Hampshire retail subsidiary, CVEC, as an integrated part of its utility operation. CVPS acquired power supply resources beyond those necessary to serve its native Vermont load in order to provide power for the CVEC load, with the costs charged to the New Hampshire customers. CVEC also paid CVPS for other elements of the retail service. To the extent that costs were directly attributable to CVEC, CVPS assigned those costs to its subsidiary. For joint and common costs that could not be directly assigned, CVPS and CVEC entered into a service contract under which CVPS was allocated a share of those costs.²⁰⁸ Through the service contract, portions of costs such as the billing system could be passed on to CVEC.

              These cost allocation methodologies ensured that CVEC and its customers paid for the direct costs that CVPS incurred to serve them. In addition, CVPS could take advantage of the economies of scale arising from the larger entity. This had the effect of reducing the cost of service for Vermont ratepayers. Traditional ratemaking methodologies led to even further reductions in costs for CVPS's Vermont customers since CVPS's overall cost of service is adjusted by allocating a portion of its costs to wholesale services. Due to the size of the CVEC commitment, the wholesale cost allocator was 4.73 percent.²⁰⁹

              In 1996, the New Hampshire Public Utilities Commission ("NHPUC") began steps towards electric restructuring.²¹⁰ On February 28, 1997, the NHPUC adopted a restructuring plan that found that CVEC should terminate its wholesale requirements power agreement with CVPS. Significantly, the NHPUC also specified that no above-market cost recovery would be allowed in CVEC's retail rates. The NHPUC also ruled that CVEC was imprudent for not terminating its FERC-authorized power contract with CVPS to take advantage of lower market costs. This decision would have required CVPS to record a significant loss contingency under SFAS 5, then-estimated to be $75 million.²¹¹

              CVPS challenged the NHPUC's ruling in federal court in what became referred to as the Patch case. The U.S. District Court upheld FERC's exclusive jurisdiction over the wholesale power arrangement and enjoined the NHPUC from proceeding until FERC had established stranded cost compensation and terminated the wholesale power arrangement.²¹² At the same time, CVPS initiated a proceeding at FERC to establish an exit fee under FERC's open access transmission regulations. An Administrative Law Judge issued a ruling that was generally favorable to CVPS.²¹³

              At the same time it pursued litigation, CVPS also conducted negotiations with New Hampshire parties to try to resolve the dispute. These ultimately led to an agreement to sell CVEC to PSNH. CVPS pursued the sale in order to mitigate harm that was being imposed on the Company by the NHPUC's policies.²¹⁴

              The sale to CVEC was a three-party arrangement between CVEC, CVPS, and PSNH. CVPS sold the assets of CVEC for book value. CVPS agreed to terminate the wholesale power sale arrangement with CVEC. In exchange, PSNH agreed to pay CVPS $21 million. This figure represented the parties' assessment of the stranded costs that CVPS would experience from having incurred the long-term arrangements to serve the CVEC load that would now be PSNH's responsibility. As such, it was based upon the parties' market price forecasts. The parties closed the transactions on January 1, 2004. By the time of the closing, long-term market price forecasts had changed, so that the stranded cost estimate had dropped to $14.351 million.²¹⁵ As a result, CVPS recorded a loss of this amount and a gain of $6.649 million (which represented the difference between the original estimate and the January 1, 2004, estimate) on the closing date.216

              CVPS states that the $21 million payment to terminate the power contract was designed to ensure that, over time, the loss of CVEC loads would not result in increased power costs being recovered from CVPS customers.²¹⁷ CVPS planned to amortize the stranded cost payment (offset by the $6.649 million gain) over 12 years as a reduction to the actual power cost obligation recorded and paid each year.²¹⁸ CVPS also observes that, given the expected cost and market value of the power, in combination with the stranded cost payment received, CVPS expects that its Vermont customers will receive net power cost credits.²¹⁹ CVPS calculates the net present value of those expected credits as of January 2005 is $6.2 million.²²⁰

              The Department challenges CVPS's proposed ratemaking treatment. From a broad perspective, the Department points out that CVPS booked a $6.649 million gain on January 1, 2004, which inured to the benefit of shareholders. At the same time, CVPS has proposed to increase costs by $1.9 million in Rate Year 1 and $2.0 million in Rate Year 2 due to elimination of the service contract and an estimated $1.8 million each year due to the change in wholesale allocation factors. In addition, according to the Department, the service to Vermont ratepayers is the same today as it was prior to the sale, yet as a result of the CVEC sale, ratepayers incur added costs.

              The Department proposes two particular adjustments to make the transaction more fair. First, the Department objects to flowing back the costs of the service contract to CVPS. The Department recommends reversing CVPS's reflection of the elimination of the service contract. Second, the Department argues that we should flow back the $6.649 million gain from the termination of the power contract to ratepayers over a three-year period. According to the Department, this treatment will offset the additional costs that Vermont ratepayers would otherwise absorb as a result of the sale of CVEC and the change in wholesale cost allocators that ensued.²²¹

              AARP supports the Department's recommendations. AARP argues that the testimony "burst the bubble" of the rebuttable presumption that CVPS was prudent in negotiating the terms of the CVEC sale. AARP asserts that, in the absence of the rebuttable presumption, CVPS has not presented sufficient evidence to justify any increased cost to Vermont ratepayers as a result of the CVEC sale.

              CVPS opposes the Department's adjustments. CVPS states that it has recorded all of the costs of the transaction above the line and asks that the Board allow recovery for all of them. CVPS also argues that it has proposed no adjustment to its cost of service, other than the $1.8 million adjustment for the service contract, that sought to recover common costs from Vermont ratepayers.²²² CVPS adds that it has taken actions to pass the gain from the sale on to customers; the Company points to the accounting order that we issued on February 18, 2005, under which the Company will defer overearnings in 2004 (computed under the Company's methodology) to 2005. CVPS says that this assures that all excess earnings -- caused largely by the gain on the CVEC transaction -- can be reflected to the benefit of customers at the start of new rates on April 1, 2005. CVPS argues that this action, coupled with the annual re versal of the $14.4 million SFAS No. 5 loss contingency, assures that customers benefit from the excess net profits of the transaction.²²³

              Turning first to AARP's arguments, we find no basis to conclude that CVPS may have been imprudent in negotiating the CVEC sale. To the contrary, the record shows that CVPS's aggressive pursuit of litigation in both federal court and at FERC and the ultimate sale to CVEC avoided potentially negative consequences to the Company and its Vermont ratepayers. Had CVPS not sold CVEC and the NHPUC order requiring restructuring was ultimately upheld, the restructuring might have resulted in higher power costs for CVPS and its Vermont ratepayers. CVPS would still have the same power resources, but would no longer receive revenues from the sale of power to CVEC.²²⁴ The evidence shows that the potential magnitude of these costs was large -- as of 1997, CVPS estimated that the power resources it had to serve CVEC would, if that sale was no longer available, have been in excess of their market value by approximately $75 million over their remaining life.²²⁵ By the time of the sale agreements, this figure had dropped to $21 million, for which CVPS received compensation;²²⁶ market price rises subsequent to that time have now reduced the estimated stranded costs to only $14.4 million. Thus, CVPS's litigation and sale avoided substantial additional power costs to Vermont ratepayers.

              The Department's proposed adjustments do not challenge the merits of the sale, but focus on the cost shifts that arise from the sale. The first cost shift arises from the termination of the service contract, whereby CVPS allocated certain costs to CVEC. In large part, we do not accept the Department's recommendation. Over 60 percent of the costs allocated under the contract are general overhead expenses (or associated payroll taxes). For example, portions of officers' salaries were assigned through this mechanism. These expenses are not readily avoidable; after the CVEC sale, most of these costs remain unchanged.

              Other costs allocated under the service contract, however, are associated with specific functions that CVPS will no longer provide to CVEC. These include allocations for customer accounting and billing, the bulk of which are associated with payroll.²²⁷ Although the Company's billing system does not change with the end of the CVEC contract, CVPS no longer needs the employees that previously provided such support to CVPS. Similarly, production, transmission, and distribution services will no longer be performed. Instead of the full costs of the service contract, we find it reasonable to allow CVPS to recover $1.376 million in Rate Year 1 and $1.456 million in Rate Year 2.²²⁸

              The second cost shift identified by the Department is the change in the wholesale allocation factor. CVPS asserts that there is no actual change in costs, so the Department's adjustment must be rejected. In a narrow sense, CVPS is correct -- the loss of CVEC did not shift costs to CVPS (except for the costs directly assigned or allocated through the service contract). However, it fails to consider the fact that, in addition to these two methods of assigning costs to CVPS, the ratemaking methodology we employ also allocates a certain portion of other costs through the wholesale allocation factor. This factor will be directly affected by the large reduction in wholesale power sales to CVEC. The parties could not calculate it precisely, but the financial impact on Vermont ratepayers of this change appears to be approximately $1.8 million annually.

              To compensate ratepayers for these added costs (at least in the short run), the Department proposes to allocate the $6.6 million gain from the termination of the CVEC power contract, amortized over three years. We find this approach reasonable. The cost shift to Vermont ratepayers from the wholesale allocation factor change is real. As presently structured, CVPS would have Vermont ratepayers absorb the full impact of this change, while simultaneously retaining the full value of the $6.6 million gain for its shareholders. CVPS has not shown why this allocation of costs and benefits is reasonable.

              We recognize that CVPS has deferred some overearnings from 2004, the bulk of which are attributable to the CVEC sale, to 2005.²²⁹ However, this adjustment is for accounting purposes only; it is not revenue that we can consider for ratemaking purposes in 2005. We expect that CVPS's deferral of these earnings will help the Company's financial standing, but it has no bearing on the rates we set today. Similarly, the deferral does not actually return any of the $6.6 million to ratepayers.

              CVPS also states that the Department's approach fails to recognize the stranded cost payments that are being used to benefit ratepayers. Specifically, CVPS will amortize the $14.4 million over 12 years to offset the stranded power costs. CVPS's ability to secure full compensation for these stranded costs is a positive aspect of the sale as structured. These payments, however, do not provide ratepayers with an additional benefit as CVPS suggests; rather, they simply make ratepayers neutral as to the power costs that will be returned to CVPS as a result of the termination of the wholesale arrangement.

              Overall, we find that the proposed amortization of the $6.6 million over three years is reasonable. Both the $6.6 million gain and the $1.8 million increase in annual costs result directly from termination of the CVEC power contract. It is appropriate to offset the increased power costs by the $6.6 million gain. We, therefore, adopt the DPS's proposed amortization of the $6.6 million gain over three years.

C.  Regulatory Commission Expense

Findings

188. Findings 170-174 above are incorporated here.

189. CVPS included the half of its costs of litigating the Patch case in its calculation of regulatory commission expenses. Schultz and DeRonne pf. at 57-60.

Discussion

              Regulatory commission expenses can vary greatly from year to year. For example, over the past five years, they have ranged from $569,579 to $1,245,520.²³⁰ Because of this variance, the Board typically establishes the regulatory commission expense for CVPS using an average of the previous five years.

              No party challenges the use of the five-year average. However, both the Department and AARP object to the inclusion of the costs associated with the Patch case. The Department asserts that the issues that CVPS litigated related to the power costs that would be charged to CVEC customers, not CVPS ratepayers. As such, the costs for the litigation should be borne by CVEC or CVPS shareholders.²³¹ AARP supports the Department's recommendation.

              CVPS maintains that the Patch case costs should be charged to Vermont ratepayers. According to CVPS, these costs were necessary to permit CVPS to obtain the sale of CVEC on terms that covered the power costs that CVPS had incurred to serve its subsidiary and thereby minimized the financial impact on CVPS's Vermont ratepayers. CVPS points out that, in the absence of the Patch litigation, CVPS's Vermont ratepayers would have ended up paying for all of the stranded costs when the power contract with CVEC was terminated.²³²

              The Department's position would have merit if we could be assured that all of the financial impacts of the NHPUC's restructuring order would have been borne by CVEC's ratepayers or by shareholders. But, as we discuss in the previous section, under traditional ratemaking in Vermont, it is likely that CVPS's Vermont ratepayers would have absorbed at least part, if not all, of the excess stranded costs.

              CVPS's pursuit of the Patch case and FERC litigation avoided the potential for shifting these significant excess power costs to CVPS's Vermont ratepayers. For this reason, we accept CVPS's position that it is reasonable to assign half of the costs of the Patch litigation to retail customers.

D.  Depreciation Expense

Findings

190. CVPS's annual depreciation expense results from the application of revised depreciation rates calculated in a depreciation study prepared in 2001, and based on CVPS's plant in service balances as of December 31, 2000. Majoros pf. at 4-5; exh. DPS-MJM-1.

191. CVPS began using the depreciation rates calculated in its 2001 depreciation study on April 1, 2002. Majoros pf. at 5.

192. Plant and equipment are removed from service at the end of their useful lives. Sometimes the retired plant and equipment may be physically removed and can be resold for value. This is called gross salvage. The cost of removing the retired plant less the value received for the salvage is net salvage. Net salvage can be positive or negative. Majoros pf. at 20, 33.

193. CVPS's current depreciation rates include a component for future negative net salvage of at least $1.6 million per year. Majoros pf. at 21 and 33; exh. DPS-MJM-1 at 8; exh. DPS-MJM-3 at page 8 of statement C.

194. During the most recent five-year period available, CVPS's actual expenditures for net salvage have been, on average, positive $0.5 million. Majoros pf. at 21, 33; exh. DPS-MJM-3 at statement D.

195. An asset retirement obligation ("ARO") is a liability resulting from a legal obligation to retire or decommission a plant asset. In this context, a legal obligation is "an obligation that a party is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel." Exh. CVPS-40 at 4; 103 FERC Paragraph 61,021 at Paragraph 2 (FERC 2003) (referrred to herein as "FERC Order 631").

196. Statement of Financial Accounting Standards No. 143 ("SFAS 143") was issued in June 2001. SFAS 143 requires that prior and future amounts of "non-legal AROs"²³³ be reported as a regulatory liability in financial statements. Majoros pf. at 22, 25.

197. As a result of SFAS 143, in 2002 CVPS identified $4.3 million of non-legal ARO collections relating to prior years that were included in its accumulated depreciation account. This $4.3 million was classified as a regulatory liability. Majoros sur. pf. at 5, 25-26; exh. CVPS-10 at 59.

198. CVPS's regulatory liability associated with non-legal ARO collections grew to $5.2 million at the end of 2003. Majoros sur. pf. at 26; exh. CVPS-10 at 59.

199. FERC Order 631 was issued on April 9, 2003. It requires an identification of amounts accrued for cost of removal for non-legal retirement obligations that are included in the depreciation reserve. It also requires jurisdictional entities to maintain subsidiary records for the purpose of identifying the amount of specific allowances collected in rates for non-legal AROs included in depreciation accruals. R. White reb. pf. at 20.

200. The matching principle of accounting provides that both initial and future expenditures should be allocated to the accounting periods in which the service potential of an asset is consumed. R. White reb. pf. at 9.

201. The standard or criterion that should be used to determine a proper net salvage rate is cost allocation over economic life in proportion to the consumption of the service potential. R. White reb. pf. at 9.

202. The economic principle underlying both the accounting and ratemaking treatment of cost of removal is that in addition to return of and return on invested capital and taxes, a revenue requirement for cost of removal is created when an asset is placed in service. R. White reb. pf. at 9.

203. If CVPS has over-collected from ratepayers for the cost of future net salvage, ratepayers should receive rate relief through downward adjustments in CVPS's net salvage rates. Tr. 1/10/05 at 60 (R. White).

204. CVPS's depreciation expense should be increased by $1,172 in Rate Year 1 and by $51,780 in Rate Year 2 to correct an error in CVPS's original cost-of-service filings related to deferred hydro relicensing costs. Schultz and DeRonne pf. at 19; exh. CVPS-4.

205. CVPS's depreciation expense should be reduced by $19,233 in Rate Year 1, and $80,486 in Rate Year 2 to reflect changes to CVPS's plant balances. These adjustments incorporate the corrections to CVPS's communications plant balances that are shown on exh. CPVS-4. Schultz and DeRonne pf. at 18; exh. CVPS-4 at pages 2-4; exh. DPS-L&A-11 at schedule 5; exh. DPS-L&A-12 at schedule 5.

Discussion

              Depreciation allows the recovery of the cost of an asset to be spread over the asset's expected life, thereby enabling all ratepayers who benefit from the asset to pay a portion of the asset's cost. Traditionally, net salvage is also collected through depreciation rates.²³⁴ Depreciation rates are established based on depreciation studies that review the assumptions underlying the current depreciation rates.

              In these proceedings, the DPS argues that CVPS's depreciation expense should be adjusted for three reasons.²³⁵ First, the DPS asserts that depreciation expense should be increased to correct an error in CVPS's original filing related to the Company's deferred hydro relicensing costs. CVPS agrees with this adjustment. The proposed adjustment, which is shown in finding 204, above, is appropriate, and we hereby accept it.

              Second, the DPS argues that depreciation expense should be reduced to reflect the DPS's recommended changes to plant balances. CVPS does not contest the adjustment of depreciation expense to reflect changes to plant balances (although the Company does contest the adjustments to the plant balances, as discussed in Section V.A, above). It is appropriate to modify depreciation expense to reflect adjustments to plant balances. Since we have accepted the DPS's recommended changes to CVPS's plant balances, we also accept the DPS's proposed adjustments to depreciation expense that reflect the effects of those changes (see finding 205, above).

              Third, the DPS advocates reducing CVPS's depreciation expense because future net salvage is bundled into CVPS's depreciation rates, even though CVPS has no legal obligation to incur those costs.²³⁶ The DPS argues that net salvage should be separated from other depreciation expenses through the use of a "net salvage allowance" that is, in essence, a normalized expense. According to the DPS, the net salvage allowance should be equal to the average of the last five years' net salvage expense (whether that amount is positive or negative). However, in these proceedings, as a transitional measure, the DPS recommends a zero net salvage allowance, rather than the positive $0.5 million net salvage allowance that would apply if a five-year average was used.²³⁷ To support its position, the DPS points out that CVPS has collected considerably more in net salvage than it has spent, on average, over the last fiv e years. The DPS argues that this proves that CVPS's net salvage rates are excessive.²³⁸

              CVPS does not agree with the DPS's position regarding the collection of net salvage. CVPS asserts that it is appropriate to continue to collect net salvage through depreciation rates, regardless of whether CVPS has a legal obligation to incur those costs. As a practical matter, CVPS asserts that even though it may not have a legal obligation to incur removal costs for most of its plant, it does in fact incur removal costs.²³⁹ CVPS argues that the DPS's net salvage allowance proposal would create intergenerational inequities because, under that proposal, the entire cost of removal of an asset would be born by ratepayers at the time the asset is retired, rather than spread among all ratepayers who benefitted from the use of the asset.²⁴⁰ CVPS asserts that comparing its annual collections for net salvage with its realized net salvage costs is inappropriate because annual collections are for the future removal of all plant now in service, not just to pay for the plant that was retired in a particular year.²⁴¹ CVPS asserts that its net salvage rates will be reexamined as part of its next depreciation study, which it expects to conduct in 2006.²⁴²

              The DPS has highlighted an important policy issue -- in contrast to collections for depreciation, which enable the utility to recover costs that it has already incurred, collections for net salvage are, in essence, prepayments by ratepayers for expenses that the utility estimates it will incur at some point in the future. This is a significant distinction, and one that persuades us that collections for net salvage should be tracked and reported separately from other funds collected via depreciation expense. For this reason, we accept the DPS's recommendation that we require CVPS to follow the recording and reporting requirements of FERC Order 631 for Vermont jurisdictional ratemaking purposes. In other words, CVPS must track and report its prior and future net salvage collections in a separate subsidiary account, and we expect this separate account to be shown in future cost-of-service filings.²⁴³

              However, we do not require CVPS to stop collecting net salvage through its depreciation rates. Intergenerational equity is of great concern to us. CVPS has convinced us that to adopt the DPS's recommendation regarding a net salvage allowance would create inequities by requiring ratepayers at the time an asset is retired to pay all the net salvage costs (or allow ratepayers at the time an asset is retired to receive the benefit if the net salvage costs are negative).²⁴⁴ Instead, net salvage costs should be recovered from ratepayers over an asset's expected lifetime. This concept of spreading cost recovery over time to match the costs with the benefits is similar to the purpose behind depreciation. Given that depreciation and net salvage rates are determined using the same service life estimates and dispersion patterns, it is acceptable for the collection mechanism (the depreciation rate itself) to combine net salvage with depreciation, provided that the recoveries for the two items are tracked and reported separately, as discussed above.

              We are not persuaded by the DPS's argument that, because CVPS has collected more in net salvage than it has spent, on average, over the last five years, the Company has overcollected net salvage. Because the recovery of net salvage costs is spread over an asset's lifetime, while actual net salvage expenses are linked to a particular year's retirements, it would be surprising if collections for net salvage matched CVPS's net salvage expenses in any particular year.²⁴⁵

              In addition, we disagree with the DPS's characterizations of SFAS 143 and FERC Order 631,²⁴⁶ both of which were enacted subsequent to CVPS's last depreciation study. Rather, we are persuaded by CVPS's arguments, and the actual language of the two documents that, for regulated entities, these new policies impose new tracking and reporting requirements for non-legal AROs, but do not require that net salvage costs no longer be recovered through depreciation rates.²⁴⁷

              Finally, the DPS has recommended that we order CVPS to conduct a new depreciation study immediately. We decline to do so at this time. In making this decision, we are relying on CVPS's representation that it will conduct a new depreciation study in either 2005 or 2006, which is five years after its last depreciation study was performed. We are persuaded that it is reasonable to conduct a new depreciation study every five years, and decline to order the Company to do so more frequently. Nevertheless, we are very interested in the results of CVPS's next depreciation study, and we require the Company to file it with the Board and the DPS when it is completed, which should be no later than December 31, 2006.

Correction to Annualized Test Year Depreciation Expense

              As explained in finding 130 and Section V.B, above, CVPS's original filing includes an error in the calculation of annualized test year depreciation expense. No party has asked that CVPS's depreciation expense calculation be revised to reflect the Company's correction of its annualized test year depreciation expense. Nevertheless, we conclude that the error should be corrected. Therefore, we require CVPS, as a part of its compliance filing in these proceedings, to adjust depreciation expense in both Rate Year 1 and Rate Year 2 to reflect the correct value of annualized test year depreciation expense.

E.  Payroll-Related Items

1.  Number of Employees

Findings

206. On December 31, 2003 (the end of the test year in these proceedings), CVPS had 514 employees and 11 vacant positions. Gamble pf. at 39; tr. 1/11/05 at 20 (Gamble); exh. CVPS-JFG-9; exh. CVPS-JFG-16; exh. CVPS-JFG-17.

207. CVPS's filed cost of service for Rate Year 1 includes 34.5 employees more than CVPS had as of December 31, 2003, for a total of 548.5 full-time equivalent employees. CVPS's filed cost of service for Rate Year 2 includes 7 more employees than its Rate Year 1 cost-of-service, for a total of 555.5 full-time equivalent employees. Tr. 1/11/05 at 21 (Gamble).

208. As of August 17, 2004, CVPS had 524.3 full-time equivalent employees. Tr. 1/11/05 at 21-22 (Gamble).

209. As of October 31, 2004, CVPS had 527 full-time equivalent employees. Tr. 1/11/05 at 23 (Gamble).

210. As of December 2004, CVPS had around 530 full-time equivalent employees. The Company had 5.5 fewer full-time equivalent employees than it had projected in its cost-of-service filings that it would have in December 2004. Tr. 1/11/05 at 28, 34-35 (Gamble).

211. CVPS filled 16 new positions in calendar year 2004. However, nine months into Rate Year 1, CVPS still had approximately 18 fewer employees than it included in its Rate Year 1 cost of service. Findings 206, 207, and 210, above.

212. CVPS originally budgeted for 532.2 full-time equivalent employees in 2005. Schultz and DeRonne pf. at 50.

213. As of January 11, 2005, only six external positions were listed as open on CVPS's website, one of which was for Catamount, Inc. This is not a complete list of CVPS's job openings because (1) when a job becomes open, it is first posted internally and not on CVPS's website, and (2) the list on the website does not include jobs for which someone has been hired from outside the Company, but has not yet started work. Tr. 1/11/05 at 24-27 (Gamble).

214. CVPS's original cost-of-service filings for both rate years did not account for ongoing vacancies. Gamble reb. pf. at 34.

215. CVPS's five-year average turnover rate is 6.2 percent. The lowest number of employees to leave CVPS in any one year since 1999 has been 25. Twelve employees left CVPS between January 1, 2004 and August 17, 2004. Schultz and DeRonne pf. at 49.

216. CVPS's requested number of employees should be reduced by 11 in each rate year in order to account for vacancies. Schultz and DeRonne pf. at 49; findings 214-215, above.

217. The average compensation expense for the 34.5 positions added by CVPS in Rate Year 1 was $24,806. CVPS's Rate Year 1 cost of service should be reduced by $272,866, which is $24,806 times 11 positions. Schultz and DeRonne pf. at 51.

218. The average compensation expense for the 41.5 positions added by CVPS in Rate Year 2 was $32,571. CVPS's Rate Year 2 cost of service should be reduced by $358,280, which is $32,571 times 11 positions. Schultz and DeRonne pf. at 51.

219. The electric industry has the oldest average age of employees among all industry groups, except for religious organizations. Gamble pf. at 40.

220. Based on CVPS's employee demographics, the Company expects a significant number of retirements to occur over the next 20 years. Gamble pf. at 41; exh. CVPS-JFG-18.

221. Sixteen of the additional full-time-equivalent employees included in CVPS's cost-of-service filings are related to succession planning for employees who will be retiring after the end of Rate Year 2. Ten of these 16 positions are related to Engineering and Operations. Due to the technical nature of this work, and to assure safety, it may take as long as four years to complete the training of qualified employees. Gamble pf. at 39-40.

Discussion

              CVPS projected significant increases in the number of full-time equivalent employees during Rate Years 1 and 2, when compared to the test year for these proceedings. However, CVPS did not persuade us that these increases are known and measurable. On the contrary, as explained below, the evidence in this proceeding has convinced us that it is unlikely that CVPS's number of employees will increase as the Company originally projected.

              The DPS and CVPS agree that the Company's requested number of employees should be adjusted downwards to account for vacancies. However, they disagree on the size of this adjustment. The DPS argues that the Company's turnover rate for the last five years supports the use of 11 vacancies (which was also the number of vacancies at the end of the test year).²⁴⁸ In addition, the DPS points out that CVPS's number of employees has been significantly below 548.5 throughout Rate Year 1, and nine months into Rate Year 1, CVPS still had approximately 18 unfilled positions.²⁴⁹

              CVPS argues that this figure is too high because it includes retirements and involuntary terminations, in addition to voluntary terminations. CVPS asserts that retirements and involuntary terminations should not be used to calculate the vacancy rate because (1) CVPS is prehiring replacements for impending retirements, therefore the vacancy rate related to retirements is expected to approach zero; and (2) in the past few years, there were a high number of involuntary terminations, especially related to raising the bar on management performance, and it is not reasonable to expect that this high level of involuntary terminations will continue at the same rate.²⁵⁰ As a result, CVPS recommends a rate of 3.7 vacancies.²⁵¹

              We are persuaded that the DPS's vacancy rate is more appropriate. Not only does 11 vacancies better match CVPS's historic turnover rate, using this vacancy rate also brings the number of employees included in the cost of service closer to the actual number of employees that CVPS had during the first nine months of Rate Year 1.

              With respect to Rate Year 2, in order for CVPS to reach its projected number of employees, it would have to hire all the employees it originally anticipated hiring in Rate Year 1 but did not, plus the seven additional employees it originally projected hiring in Rate Year 2. CVPS has not convinced us that it will hire all these additional employees during Rate Year 2, particularly since its 2005 budget (which covers three months of Rate Year 1 and nine months of Rate Year 2) included only 532.2 employees, far fewer than the 555.5 employees included in CVPS's Rate Year 2 cost of service.

              CVPS has argued that the vacancy rate related to retirements is expected to approach zero, and that there will be fewer involuntary terminations during the rate years. These assertions may be true. However, they do not change the fact that nine months into Rate Year 1, CVPS still had approximately 18 unfilled positions, and there is nothing in the record that convinces us that this situation will change significantly in Rate Year 2.²⁵²

              We note, however, that reducing CVPS's number of employees by a vacancy rate of 11 still leaves approximately 7 positions unfilled nine months into Rate Year 1, and an additional 7 positions to be filled in Rate Year 2. Even though it could be argued that these additional positions are not known and measurable, we do not reach that conclusion in this Order. Rather, CVPS has persuaded us that it is necessary for its staffing levels to increase slightly in order to train new employees who can replace those expected to retire after Rate Year 2.²⁵³ We recognize that the aging of the workforce is an issue confronting the electric utility industry as a whole, and we are pleased that CVPS is planning for expected retirements. Our decision today takes into consideration CVPS's decision to prehire replacements for some impending retirements in order to ensure that the replacements are adequately trained. An adequate ly-trained workforce will benefit ratepayers; for this reason, we allow CVPS to include the costs of the remaining currently unfilled positions in rates.

2.  Employee Incentive Plan

Findings

222. CVPS has an Employee Incentive Plan ("EIP") under which non-union employees (excluding officers) have the ability to earn an annual incentive payment if certain performance objectives are met. Gamble pf. at 27-28.

223. The EIP has a broad payout range. CVPS designed the EIP so there is a 90 percent chance of reaching the threshold performance level (below the threshold no payment is made), a 50 percent chance of reaching the target performance level (at which the target payout is made), and a 10 percent chance of reaching the maximum performance level (at which the maximum payout is made). The maximum payout is twice the target payout. Gamble pf. at 29.

224. CVPS requests in its filed costs of service the target payout amounts of $887,380 in Rate Year 1, and $1,187,760 in Rate Year 2. Gamble pf. at 29; tr. 11/2/04 at 35-36; exh. DPS-L&A-11 at page 2 of schedule 11; exh. DPS-L&A-12 at page 2 of schedule 11.

225. Fifty percent of CVPS's EIP is based on three Company-level measurements, and 50 percent of the EIP is based on specified team-level measures. Exh. CVPS-JFG-33 at 3.

226. The three Company-level measures used to calculate CVPS's EIP, along with the weight given to each, are: (1) utility earnings per share (50 percent); (2) cash flow (25 percent); and (3) whether CVPS meets its service quality standards (25 percent). Exh. CVPS-JFG-33 at 3.

227. The Team-level measures used to fund CVPS's EIP are divided among four categories: financial, customer, process, and people. For teams that work with external customers, the customer measures are given a weighting between 35 and 45 percent. Exh. CVPS-JFG-33 at 3.

228. The EIP's 2004 target for utility earnings per share is $1.24, while the utility earnings per share for 2002 and 2003 were $1.49 and $1.57, respectively. Schultz and DeRonne pf. at 43.

229. Fifty percent of CVPS's requested EIP expense (in other words, 50 percent of the target payout amount) should be disallowed in Rate Year 1 in order to share the expected costs of the EIP equally between shareholders and ratepayers. Schultz and DeRonne sur. pf. at 41-42.

230. Fifty percent of the Company's requested EIP expense should be disallowed in Rate Year 2, after removing an amount that is not known and measurable as provided in confidential exh. CVPS-JFG-29, in order to share the expected costs of the EIP equally between shareholders and ratepayers. Schultz and DeRonne sur. pf. at 41-42; exh. CVPS-JFG-29.

231. CVPS's Vice President for Strategic Change and Business Services is responsible for overseeing all aspects of human resources, and was the Company's primary witness regarding the design of CVPS's EIP. Gamble pf. at 1, 27-33; Gamble reb. pf. at 25-33.

232. CVPS's Vice President for Strategic Change and Business Services incorrectly stated in her prefiled direct and rebuttal testimony, and during her live testimony during the direct portion of these proceedings that the weight given to the three Company-level measures used to fund CVPS's EIP were: (1) utility earnings per share (25 percent); (2) cash flow (25 percent); and (3) whether CVPS meets its service quality standards (50 percent).²⁵⁴ Gamble pf. at 30; Gamble reb. pf. at 26, 28; tr. 11/2/04 at 36 (Gamble); exh. CVPS-JFG-33 at 1.

233. CVPS's Vice President for Strategic Change and Business Services did not discover the error described in finding 232, above, until sometime after the rebuttal hearings in these proceedings when she began looking back at the Company's 2004 performance. Exh. CVPS-JFG-33 at 1.

Discussion

              The DPS argues that 50 percent of the amount CVPS has requested for its EIP should be excluded from the costs of service for both Rate Years 1 and 2 because: (1) the EIP is based 75 percent on financial goals and only 25 percent on meeting service quality and reliability goals; (2) the EIP's goals are not appropriate because they are set too low; (3) CVPS lowered its earnings per share goal because earnings are expected to decrease due to the sale of CVEC and the return of costs previously paid by CVEC customers to Vermont ratepayers; and (4) the EIP has too many discretionary measures for which there is no means to verify that the decisions are justified.²⁵⁵ Alternatively, the DPS argues that 50 percent of the amount CVPS has requested for its EIP should be disallowed in order to provide for an equal sharing of costs between ratepayers and shareholders.²⁵⁶

              CVPS argues that the requested amount for its EIP (which is the target payout amount) should be allowed because its EIP is necessary to provide employees incentives for cost-effectively meeting the Company's goals, and to enable the Company to remain competitive with the marketplace.²⁵⁷ CVPS also asserts that the DPS has misunderstood the EIP's components. CVPS explains that its EIP is based 50 percent on Company measures, and 50 percent on Team measures. The Company states that the DPS is correct that 75 percent of its Company measures are financial goals, and 25 percent are service quality and reliability goals, but asserts that the DPS ignores the contribution of Team measures. According to CVPS, for teams that work with external customers, between 35 and 45 percent of the Team measures are focused on customer-oriented goals. Therefore, for teams that work with external customers, between 30 and 35 perce nt of the EIP is based on customer-focused goals (including both the Company and Team measures).²⁵⁸ Finally, CVPS argues that not all of its teams have discretionary goals, but that discretionary goals are necessary for some of its teams in order to prevent "absurd results."²⁵⁹

              We do not dispute CVPS's contention that its EIP provides its employees with incentives for cost-effectively meeting the Company's goals. However, the Company's goals benefit both shareholders and ratepayers. As a result, shareholders and ratepayers should share equally in the expected costs of the EIP.

              We have two reasons for requiring that the EIP's expected costs be shared equally between shareholders and ratepayers. First, most of the EIP is not focused on customer goals. CVPS correctly points out the error in the DPS's assertion that only 25 percent of the EIP's overall weight is assigned to customer service and reliability goals. The Company has shown that only 25 percent of the EIP's Company measures are customer-oriented goals, but the overall weight, including the Team measures, is between 30 and 35 percent for those teams that work with external customers. Nevertheless, this range still indicates that only approximately one-third of the EIP's weight is assigned to customer service and reliability goals.²⁶⁰

              Second, the Company has set inappropriately low targets for some of the measures, particularly its utility earnings per share measure, which by itself accounts for 25 percent of the overall EIP. The 2004 target for this measure is 21 percent below actual 2003 utility earnings per share, and 17 percent below actual 2002 utility earnings per share. It is not appropriate to provide an incentive for performance significantly below the previous two years' achievements, particularly if, as the DPS argues, the target was reduced because CVPS's regulated utility operations will need to absorb nearly $4 million of additional costs as a result of CVPS's sale of CVEC.²⁶¹

              We are not basing our disallowance on the EIP's use of discretionary measures. CVPS has convinced us that discretionary goals are appropriate for some teams, and we do not conclude, at this time, that CVPS's EIP relies too heavily on discretionary measures. However, we remind CVPS that it is responsible for maintaining sufficient documentation justifying the discretionary determinations. Should CVPS fail to maintain such documentation, we may well reach a different conclusion regarding the EIP's reliance on discretionary measures in the future.

              The remaining issue to decide is, "what are the EIP's expected costs?" CVPS has stated the EIP was designed so there would be a 50 percent chance of reaching the target performance level, which would result in the target payout being made. Thus, it is equally likely that CVPS would pay more or less than the target payout. As a result, we conclude that the target payout level is the best estimate of the EIP's expected costs in each of the rate years.²⁶² Therefore, we are persuaded that 50 percent of the Company's requested EIP expense should be disallowed in Rate Year 1. In addition, we conclude that 50 percent of the Company's requested EIP expense should be disallowed in Rate Year 2, after removing an amount that is not known and measurable as provided in confidential exh. CVPS-JFG-29.²⁶³

              Finally, we are compelled to comment on Ms. Gamble's error regarding the weights assigned to the utility earnings per share and service quality and reliability portions of the EIP. We do not believe Ms. Gamble deliberately misled the Board, and we believe that she acted properly in promptly informing the Company's legal department, who in turn immediately informed the Board and the other parties in these proceedings. Furthermore, we realize that everyone makes a mistake occasionally. Nevertheless, we are astounded that someone in her position could make this particular mistake not once, but three times, both orally and in written prefiled testimony. We are very troubled that the Company's senior executive with primary responsibility for overseeing all aspects of human resources, including the implementation of CVPS's EIP, could have such a fundamental misconception regarding the EIP's priorities. We are very in terested in the way the EIP balances shareholder and ratepayer concerns, and we were disturbed to discover late in these proceedings that the EIP accorded only half as much significance to the Company's service quality and reliability goals and twice as much significance to utility earnings per share as CVPS's senior executive with responsibility for the EIP thought it did. This situation reinforces our original concern regarding the EIP's balance between shareholder and ratepayer interests, which we have addressed in this Order through an equal sharing of the EIP's expected costs between shareholders and ratepayers.

3.  Officers' Compensation

Findings

234. CVPS multiplied the total salaries of all Vermont regulated utility employees (including officers) by an adjustment factor of 74.85 percent to calculate the Operations and Maintenance portion of those employees' salaries. The 74.85 percent adjustment factor is based on the percentage of compensation dollars that are spent, on average, by all utility employees working on Operations and Maintenance activities, as opposed to capital projects, unregulated activities, or other "below-the-line"²⁶⁴ activities. Gamble pf. at 43; Gamble reb. pf. at 37-38.

235. The DPS asked CVPS to provide information regarding individual officers' compensation that was charged below-the-line. CVPS initially provided no information regarding how individual officers' compensation was allocated between ratepayers and shareholders, and later provided a calculation that shows that 88.9 percent of a particular unidentified officer's time was charged to Vermont utility operations during the test year. Schultz and DeRonne pf. at 51-52; Schultz and DeRonne sur. pf. at 43-44; Gibson reb. pf. 11/15/04 at 28-29.

236. Because CVPS failed to demonstrate that an appropriate amount of officers' compensation has been charged below-the-line, 10 percent ($96,514) of the requested amount of officers' compensation should be removed from the costs of service for both Rate Years 1 and 2. Schultz and DeRonne pf. at 52.

Discussion

              A long-standing regulatory principle is that ratepayers should not pay for costs incurred to support a utility's unregulated affiliates or other below-the-line activities. It is the utility's responsibility to maintain records that will allow regulators to verify that costs, including payroll costs, allocated to activities that are excluded from ratemaking are not included in a utility's cost of service.²⁶⁵

              In these proceedings, CVPS has failed to provide records showing what portion of its officers' compensation was charged below-the-line. Instead, it relies upon an allocation percentage that was calculated based upon how all employees spend their time. However, the DPS has argued that officers provide a different level of service to regulated and unregulated operations than the general employee complement.²⁶⁶ CVPS notes another difference between how officers spend their time compared to employees as a whole -- officers generally do not spend time on capital projects.²⁶⁷ For these reasons, the evidence presented by CVPS regarding the allocation of one officer's compensation is insufficient to support the use of an allocation factor that is based on all employees' compensation.

              CVPS has asserted that the actual allocation of individual officers' compensation is not readily available because specific employee salaries lose their identity in the Company's general ledger system.²⁶⁸ This is not an acceptable reason to fail to provide appropriate documentation regarding the allocation of officers' compensation. It is CVPS's responsibility to ensure that its recordkeeping enables the Company to provide information regarding the allocation of all costs, including payroll costs, above- and below-the-line.

              Because CVPS has not provided information regarding the actual allocation of individual officers' compensation, we are unable to ascertain whether 74.85 percent is the correct factor to use to allocate the officers' time. The Company has not met its burden of proof on this issue. Therefore, we accept the DPS's proposed additional 10 percent reduction to officers' compensation.²⁶⁹ It is imperative that a utility's failure to meet its recordkeeping responsibilities not result in a windfall to the company, or its corporate officers.²⁷⁰

4.  Other Payroll Adjustments

Findings

237. Temporary employee salaries for Rate Year 2 should be reduced by $91,175. Gamble reb. pf. at 37; Schultz and DeRonne pf. at 51; exh. CVPS-4.

238. Wages and salaries for Rate Years 1 and 2 should be reduced by $68,720, and $20,560, respectively, to correct errors in CVPS's original filing. Gamble pf. at 42; exh. DPS-L&A-11 at page 2 of schedule 11; exh. DPS-L&A-12 at page 2 of schedule 11.

Discussion

              CVPS and the DPS have agreed that two additional adjustments should be made to payroll, as described in findings 237-238, above. We conclude that the adjustments are reasonable and should be made.

5.  Payroll Tax Expense

Findings

239. Payroll tax expense should be adjusted to reflect the adjustments made to payroll expense. Gibson pf. at 31.

240. The payroll tax expense adjustment should be calculated by multiplying the respective payroll expense adjustments by the test year's effective social security rate of 7.12 percent. Schultz and DeRonne pf. at 53.

Discussion

              CVPS and the DPS agree that payroll tax expense should be adjusted to reflect the adjustments made to payroll expense. However, they disagree on the effective tax rate that should be used in the calculation.

              The only effective tax rate in the evidentiary record in these proceedings is that proposed by the DPS -- 7.12 percent. In CVPS's reply brief, it asserts that the Company used a combined tax rate of 7.65 percent to calculate its payroll tax expense, and argues that "the DPS calculated rate must be rejected so that the Company can recover its rate year Social Security tax expense."²⁷¹

              The payroll tax expense is a combination of social security tax expense and medicare tax expense. Based on our experience with utility company payroll tax expense, we know that medicare tax is assessed on all of each employee's earnings, but social security tax is only assessed on each employee's earnings up to a certain limit, which is changed by the federal government each calendar year. As a result, it is common for a utility company's total payroll tax expense to be less than would result if the full 7.65 percent tax rate that is applied to individual employees' earnings below the specified limit were applied to the company's total payroll expense.

This is, in fact, what occurred for CVPS in 2003, as shown by the DPS. The DPS divided CVPS's test year payroll tax expense of $1,868,807 by CVPS's test year payroll of $26,234,661 to arrive at an effective payroll tax rate of 7.12 percent.²⁷² The DPS has proposed using this effective payroll tax rate to calculate the adjustment to payroll tax expense.

              In other words, the DPS has proposed using a lower effective payroll tax rate to calculate its reduction to payroll tax expense than CVPS has proposed. This results in a smaller reduction to payroll tax expense than if the Company's proposed effective tax rate was used.²⁷³ As a result, we are confused by CVPS's assertion that if the DPS's effective tax rate is used, the Company will not recover its rate year Social Security tax expense. On the contrary, if the DPS's effective payroll tax rate is used, the Company will collect more payroll tax from ratepayers than it would if its proposed effective tax rate were used to calculate the adjustment.

              We recognize that CVPS's effective payroll tax rate during the rate years may be higher or lower than 7.12 percent. However, based on the evidence in the record, we cannot conclude that there is a known and measurable change to the effective payroll tax rate for the rate years. Thus, we accept the DPS's proposed effective tax rate for the purpose of calculating the adjustment to payroll tax expense for two independent reasons: first, because substantively it is the appropriate effective payroll tax rate to use, and second, because CVPS's proposed effective payroll tax rate is not in the evidentiary record in these proceedings.

              In the Company's compliance filing, CVPS should include an adjustment to payroll tax expense that is equal to 7.12 percent times our approved adjustments to payroll expense.

6.  401(k) Expense

Findings

241. 401(k) expense should be adjusted to reflect the adjustments made to payroll expense. Frankiewicz pf. at 10.

242. The 401(k) expense adjustment should be calculated by multiplying the respective payroll expense adjustments by the test year's effective 401(k) employer match rate of 2.95 percent. Schultz and DeRonne pf. at 56.

Discussion

              CVPS and the DPS agree that 401(k) expense should be adjusted to reflect the adjustments made to payroll expense. However, they disagree on the effective employer match rate that should be used in the calculation.²⁷⁴

              The only effective employer match rate in the evidentiary record in these proceedings is that proposed by the DPS C 2.95 percent. In CVPS's reply brief, it asserts that the DPS employer match rate should be rejected.²⁷⁵ However, neither CVPS's calculation of its 401(k) expense nor its recommended employer match rate are in the evidentiary record.²⁷⁶ Therefore, we accept the DPS's proposed effective tax rate for the purpose of calculating the adjustment to payroll tax expense.

              In the Company's compliance filing, CVPS should include an adjustment to 401(k) expense that is equal to 2.95 percent times our approved adjustments to payroll expense.

F.  Medical Insurance

Findings

243. CVPS's average medical insurance cost per employee, prior to capitalization, in Rate Year 1 is $10,118. A Hewitt Associates study shows the national average total medical insurance cost per employee in 2003 was $6,295. Schultz and DeRonne pf. at 53.

244. CVPS's average medical cost per employee is higher than the national average per employee because: (1) CVPS's plan has 2.6 dependents per employee -- for comparison purposes, Cigna, the second largest provider of insurance for privately insured individuals in Vermont, has a national average contract size of only 2.25 dependents per employee; (2) CVPS's workforce is older than the national average, and older employees generally have higher medical expenses; and (3) Vermont health care is more costly than the national average because there is less competition for medical services in Vermont. Gamble reb. pf. at 40; exh. CVPS-JFG-19; exh. CVPS-JFG-26.

245. CVPS employees' contribution to medical expense increased from 15 percent in 2003 to 19 percent in 2004. This change was not reflected in CVPS's costs of service for Rate Years 1 and 2. CVPS's medical expenses for Rate Years 1 and 2 should be reduced by $118,772 to reflect this change. Gamble reb. pf. at 44; Gamble sup. pf. at 6; exh. DPS-L&A-11 at schedule 13; exh. DPS-L&A-12 at schedule 13.

246. CVPS's most recent agreement with its employees' union provides for: (1) significant increases in employee co-pays for hospital stays, outpatient surgery, office visits, and pharmaceutical drugs, beginning April 1, 2005; and (2) increases in employees' health insurance premiums, beginning in 2006. Non-union employees will experience the same increases in employee co-pays. Gamble sup. pf. at 4-5; exh. CPVS-JFG-28 at 1.

247. According to CVPS's medical insurance broker, employers with more than 500 employees expect to experience a 14 percent increase in medical insurance costs in 2004. In addition, estimates of increases in medical insurance costs for 2005 range from 12 percent to 18 percent. Gamble reb. pf. at 38; exh. CVPS-JFG-19.

248. The State of Vermont projects increases in its medical insurance costs for its two largest insurance plans of 16 and 18 percent between fiscal years 2004 and 2005, and 22 and 23 percent between fiscal years 2005 and 2006. Gamble reb. pf. at 39.

249. The fiscal year 2003 actuarial valuation under Statement of Financial Accounting Standards No. 106 prepared by Towers Perrin for CVPS shows inflation assumptions for pre-age 65 retiree medical costs of 8 percent, 7 percent, and 6 percent for 2004, 2005, and 2006, respectively. Schultz and DeRonne pf. at 55.

250. In April 2004, Towers Perrin provided CVPS updated inflation assumptions for pre-age 65 retiree medical costs of 12 percent, 11 percent, and 10 percent for 2004, 2005, and 2006, respectively. However, these rates were not part of a completed actuarial report. Tr. 1/11/05 at 19-20 (Gamble); exh. CVPS-JFG-24.

Discussion

              The DPS argues that the medical expenses included in CVPS's cost-of-service filings are excessive because: (1) CVPS's medical cost per employee is significantly above the national average in 2003; (2) the medical inflation rates used by CVPS are too high; and (3) CVPS failed to reduce its medical costs by the increase in employee contributions to medical costs between 2003 and 2004.²⁷⁷

              CVPS disagrees with the DPS's first two arguments, but agrees that its medical expenses should be reduced to reflect the increase in employee contributions between 2003 and 2004.

              CVPS admits that its medical insurance costs per employee are above the national average, in part due to the Company's "generous medical program design."²⁷⁸ However, CVPS has persuaded us that this is not the only reason CVPS's medical insurance costs are above the national average.²⁷⁹ In addition, CVPS has taken steps to change its "generous" medical insurance program. CVPS's employee payments increased from 6.5 percent of total health claims in 2001 to 19.2 percent in 2004 (the national average is 20 percent).²⁸⁰ Furthermore, CVPS's new contract with its employee union increases employee co-pays substantially beginning in 2005, and provides for additional contribution increases beginning in 2006.

              As for medical inflation rates, the evidence in these proceedings shows that expert estimates vary. The DPS's proposed inflation rates are based upon a 2003 actuarial valuation that was later updated (although not as part of a complete new report). The inflation rates from the 2003 report are significantly lower than the other expert estimates, and do not appear reasonable to us. At the same time, however, we are not persuaded that the medical inflation rates used by CVPS in its cost-of-service filings (14 percent for 2004, and 12 percent for 2005 and 2006) are appropriate either. While they are within the range of inflation rates provided by experts, and are less than the projected increases for the State of Vermont's two largest medical insurance plans, they are higher than the inflation rates included in the 2004 update of Towers Perrin's actuarial valuation, which the Company has relied upon in the preparation of p revious financial disclosures.²⁸¹ We conclude that the updated Towers Perrin medical inflation rates are the appropriate rates to use in these proceedings -- 12 percent in 2004, 11 percent in 2005, and 10 percent in 2006.

              Therefore, we require CVPS to recalculate its medical expense for both rate years, taking into account: (1) the agreed-upon $118,772 adjustment for the increase in employee medical insurance premiums from 2003 to 2004; (2) medical inflation rates of 12 percent in 2004, 11 percent in 2005, and 10 percent in 2006; and (3) the results of the Company's new contract with its union employees.

G.  Director and Officer Liability Insurance

Findings

251. Director and Officer liability insurance protects shareholders from their own decisions regarding management of the company. Schultz and DeRonne pf. at 67-68.

252. Director and Officer liability insurance is a necessary cost of doing business for utility companies. A utility company must have Director and Officer liability insurance in order to attract capable people to serve as officers and directors. Deehan reb. pf. at 26.

Discussion

              The DPS argues that since there is no identifiable benefit to ratepayers from Director and Officer liability insurance, the entire cost of that insurance should be removed from CVPS's cost of service.²⁸² Alternatively, if that recommendation is not accepted, the DPS asserts that the increase in premium between 2002 and 2003 should be removed, and the remaining balance shared 50/50 between ratepayers and shareholders.²⁸³

              CVPS argues that the full amount of the Company's Director and Officer liability insurance should be allowed in its cost of service because it is a necessary aspect of providing service to consumers. The Company asserts that without Director and Officer liability insurance, CVPS will not be able to attract capable people to serve as the Company's officers and directors.²⁸⁴

              While the DPS is correct that shareholders receive the direct benefits of Director and Officer liability insurance, we are persuaded by CVPS that such insurance is a necessary cost of doing business because without such insurance, CVPS would have a difficult time attracting quality officers and directors. For this reason, we conclude that Director and Officer liability insurance does have an indirect benefit to ratepayers that justifies requiring ratepayers to pay at least part of the cost.

              However, Director and Officer liability insurance protects the Company as a whole, not just its regulated utility operations. As such, its costs should be shared by all portions of the Company, in proportion to the benefit each receives from the insurance. Since the Director and Officer liability insurance protects CVPS's shareholders from the actions of its management, we conclude that the best proxy for allocating the insurance's benefits among the Company's different operations is the allocation of CVPS's officers' time.

              As discussed in Section VI.E.3, above, we determined that it was appropriate to charge 67.365 percent of CVPS's officers' time to regulated utility operations.²⁸⁵ Applying this same adjustment factor to CVPS's requested $393,000 expense for Director and Officer liability insurance²⁸⁶ results in a disallowance of $128,256 of the requested costs.²⁸⁷

H.  Tree-Trimming

Findings

253. Falling trees (and tree limbs) are the number one cause of outages on CVPS's system and have the largest impact on overall system reliability. Every year approximately 2,500 tree-related outages occur. Outages caused by trees tend to be longer in duration because they usually cause significant damage. G. White pf. at 14-15.

254. During the test year ending December 31, 2003, CVPS spent $5,221,854 on tree trimming in distribution and transmission rights-of-way. Dickinson pf. at 3.

255. CVPS requested tree trimming expenses of $6,284,444 in Rate Year 1 and $6,466,224 in Rate Year 2. Dickinson pf. at 2-3.

256. CVPS's tree trimming expenses are increasing due to higher contractor fees which are a result of increased costs in fuel, labor, equipment and liability insurance. Dickinson pf. at 3.

257. Inspecting and treating poles before they become a public hazard and undermine system reliability is prudent. G. White pf. at 17.

258. CVPS requested pole treatment expenses of $304,000 in Rate Year 1 and $523,000 in Rate Year 2. Dickinson pf. at 3.

259. In order to maintain system reliability and ensure public safety, it is necessary to expend the full amount of the expected tree trimming and pole treating expenditures annually. Tr. 11/1/04 at 30 (Dickinson).

Discussion

              Downed trees and tree limbs materially affect reliability and create safety hazards for CVPS employees and the public. Similarly, aged poles subject line workers and the public to unnecessary hazards that could be easily avoided by replacing those poles that show signs of structural deterioration.

              CVPS and the DPS agree that maintaining a program of annually trimming trees and treating poles helps to ensure system reliability and safety. They disagree, however, on whether the Board should require the Company to spend all the funds requested for tree trimming and pole treatment each year, and to carry forward any unspent funds into the next year. The DPS asserts that the Board should impose this requirement, and should require CVPS to report its actual annual expenditures and amounts carried forward, compared to the amounts included in the Company's rates.

              CVPS claims that the DPS's recommendation is one-sided, as it only addresses underspending of budgeted amounts and does not address what would happen if the Company spent more than the amounts included in rates.

              Ensuring public safety and system reliability is a critically important task for CVPS. The amount that CVPS spends annually on tree trimming and pole treatment directly affects the Company's ability to remove potentially hazardous trees and replace aged poles.²⁸⁸ Without such attention to the condition of the rights-of-way and structural integrity of poles, CVPS's system reliability and safety could deteriorate. Therefore, we approve CVPS's request for tree trimming and pole treatment expenses, as stated in findings 255 and 258, above.

              However, as we stated in our decision in a 1978 CVPS rate case:

In allowing the Company [tree trimming, pole treatment and overhead maintenance] costs, the Board expects that the funds approved be spent exclusively on these programs and within the time schedule to which the Company testified.²⁸⁹

Consistent with this long-standing expectation, in these proceedings we require CVPS to spend the entire amount included in rates for tree trimming and pole treatment each year on such activities. If CVPS is unable to do so, it should carry forward into subsequent years the amount of unspent funds. We also require CVPS to include in its annual reports filed pursuant to PSB Rule 4.903 the amounts spent for each of the above-mentioned programs, the amount to be carried forward into subsequent years, and a comparison of the amounts actually spent to the amounts allowed in rates. To the extent that CVPS spends more than the amounts allowed in rates in a given year, the Company may include the excess amounts as a credit toward the next year's spending so long as CVPS provides a detailed accounting, with supporting documentation, of the amount expended in excess of the amount collected in rates.

I.  Cost Savings from Capital Additions

Findings

260. Capital additions to replace vintage mainframe tape technology (WO 6682), purchase a new network printer (Rutland WO 6778) and a so-called Tivoli Enhancement (WO 6782) will result in expected operating expense savings in both rate years. The net effect of these adjustments is $81,250 and $98,500 in Rate Year 1 and Rate Year 2, respectively. Schultz and DeRonne pf. at 72; Schultz and DeRonne sur. pf. at 16; Monder reb. at 11-12; exh. DPS-L&A-6 at schedule SR 22; exh. DPS-L&A-7 at schedule SR22.'

261. CVPS's costs of service reflected cost savings associated with a video conferencing plant addition. This project resulted in cost savings of $1,658 in Rate Year 2. As the video plant addition is not known and measurable (see Section V.A), these cost savings do not exist. Schultz and DeRonne sur. pf. at 17.

262. The net effect of these adjustments is $79,592 and $96,842 in Rate Year 1 and Rate Year 2, respectively. CVPS's regulated operating and maintenance expense should be adjusted to reflect these cost savings. Schultz and DeRonne sur. pf. at 16; Monder reb. at 11-12; exh. DPS-L&A-6 at schedule SR 22; exh. DPS-L&A-7 at schedule SR22.²⁹⁰

Discussion

              CVPS and the Department agree that CVPS's cost of service should be reduced to reflect the cost savings from the three capital additions mentioned above. We conclude that these reductions are appropriate. If ratepayers are paying for capital additions, they should also benefit from any cost savings that result from these proposed capital additions. If, on the other hand, certain capital additions are disallowed, then the anticipated cost savings that were to be derived from the proposed capital addition should also be removed from the Company's cost of service. Consistent with these principles, we conclude that the agreed-upon cost adjustments shown in finding 260 above, are acceptable.

              CVPS's cost-of-service filing included cost savings arising from the addition of new video conferencing equipment. In Section V.A, we conclude that CVPS has not demonstrated that its proposed plant addition is known and measurable. As a result, we need to reverse the cost savings that CVPS attributed to this plant addition. CVPS had reflected cost savings of $1,658.²⁹¹ We accept the parties' recommendation that we offset the cost savings identified above by these costs savings that are not known and measurable.

J.  Revenues

1.  Unbilled Revenues

Findings

263. In its cost-of-service filings, CVPS used the actual, billed revenues from customers that occurred during the test year (calendar year 2003). CVPS did not include unbilled revenues, even though these revenues were earned by the Company. Schultz and DeRonne pf. at 39; Anderson reb. pf. at 2.

264. The difference between the Accrued Utility Revenues between December 31, 2002, and December 31, 2003 is $777,387, which is the amount of unbilled revenues that CVPS excluded. Schultz and DeRonne pf. at 41.

265. Including these unbilled revenues would have no effect on the Company's revenue requirement, but would affect the percentage increase or decrease arising from this Order. Anderson reb. pf. at 2-3.

266. CVPS records its unbilled revenues, as required by GAAP. Tr. 1/12/05 at 37 (Gibson).

Discussion

              In calculating the amount (and percentage) by which CVPS's rates should increase or decrease, we determine the Company's revenue requirement and then compare that figure to the Company's test year revenues. As a result, any adjustments to the test year revenues have a direct effect on the final rate levels.

              In its cost-of-service filing, CVPS reflected the actual, billed revenues from customers that occurred during the test year.²⁹² These billed revenues do not, however, reflect all of the actual revenues earned from regulated operations during 2003. Rather, CVPS also earned $777,387 in unbilled revenues that the Company excluded from its revenue totals.²⁹³

              The Department argues that we should adjust CVPS's cost-of-service filing to reflect the unbilled revenues. According to the Department, CVPS's filing, by excluding these revenues, does not reflect the actual calendar-year 2003 revenues from regulated operations.²⁹⁴ The Department asserts that ignoring the unbilled revenues would "ignore sales that have occurred." It also, the Department maintains, would result in a mismatch of revenues and expenses by including the costs associated with producing the revenue while excluding the resulting revenue.²⁹⁵

              CVPS takes the position that its approach is consistent with past ratemaking conventions in that the Board had not previously adopted an adjustment for unbilled revenues. The Company suggests that the Department has selectively reversed its position on these revenues simply to justify lower rates.²⁹⁶ CVPS also states that the unbilled revenues only reflect estimates based upon kWh sales, not all of the time-of-day kWh and kW elements of the Company's rate structure, so that the amount of unbilled revenues is not precise.²⁹⁷

              We accept the Department's recommendations and direct CVPS to adjust the test-year revenues to include the unbilled revenues that it originally excluded. Inclusion of unbilled revenues will mean that the revenues used for determining the rate changes are based upon actual sales to customers that occurred during the historic test year.²⁹⁸ This resolution is also consistent with our previous rulings on the issue.²⁹⁹

              We recognize that we have not made such an adjustment for CVPS in prior cases. That fact alone is not sufficient basis for failing to take into account revenues where the evidence demonstrates that CVPS earned the revenues during the test year. Moreover, as the Department has argued, adjusting revenues to reflect the unbilled revenues that CVPS earned also better matches the revenues with the underlying expenses. CVPS's cost of service is based upon its expenses during calendar year 2003 (the test year). The Department's adjustment aligns the revenues with these costs.

Finally, we reject CVPS's assertion that it is unfair to adjust for unbilled revenues now when they serve to increase the test year revenues. Our task here is to determine the appropriate rate treatment based upon the evidence before us, which shows that CVPS received these revenues. As CVPS acknowledged, an adjustment for unbilled revenues can be either positive or negative.³⁰⁰ We would expect to recognize adjustments to revenues (whether positive or negative) in the future.

2.  Cable Television Pole Attachment Revenues

Findings

267. CVPS collects pole attachments fees from telephone companies and third-parties, including cable television ("CATV") companies. CVPS also pays attachment fees to telephone companies for attachments of CVPS wires on telephone facilities. Anderson pf. at 3.

268. Pole attachment revenues received by CVPS are shown as a credit in the cost-of-service. The revenue for each attachment is based upon the actual number of jointly-owned and solely-owned poles (as of December 31, 2003) and whether the attaching company uses two feet of space (Tariff 2) or one foot (Tariff 1). Anderson pf. at 3; Schultz and DeRonne pf. at 61; Anderson reb. pf. at 6.

269. The two-foot rate is twice the one-foot rate. Anderson reb. pf. at 7.

270. CVPS has billed Adelphia at the two-foot rate. If these pole attachments were priced at the one-foot rate, the revenues would be reduced by $373,085 in both Rate Years 1 and 2. Anderson reb. pf. at 8.

271. CVPS has set aside reserves of $447,100 on its books to reflect the expectation that the Board will require it to charge CATV providers at the one-foot rate and to otherwise reduce its pole attachment rates in Docket 6605. Anderson pf. reb. at 7-9; tr. 11/3/04 at 253 (DeRonne).

Discussion

              CVPS derives revenues from companies that attach to the poles that CVPS owns, including jointly-owned poles. A substantial portion of the pole attachment revenue is from cable television companies. CVPS also pays attachment fees to telephone companies when it attaches its own wires to the telephone companies' poles.³⁰¹ The pole attachment revenues exceed the costs and provide a credit to the Company's cost of service.

              In preparing its cost-of-service filings, CVPS made a preliminary calculation that CATV pole attachment revenues were $866,585.³⁰² CVPS then made two adjustments to this figure, reducing the amount to $419,475. These adjustments reflect the Company's expectation that CATV payments will decline as a result of the Board's investigation into CVPS's pole attachment rates (Docket 6605). First, CVPS expects that the Board will only require CATV providers to pay for one foot of space on the pole as opposed to the two-feet rate that CVPS generally charges, reducing revenues in both rate years by $373,085. Second, CVPS assumes a further downward adjustment of $74,025 in both rate years due to an expectation that the Board will lower the pole attachment rates themselves.³⁰³ CVPS has recorded a reserve on its books based upon these expectations, which it asserts is required by GAAP.³⁰⁴ CVPS asse rts that, unless the Board makes the adjustments proposed by CVPS, the Company will not have a fair opportunity to earn its return if the ruling in Docket 6605 is adverse. Finally, CVPS states that the Board can take steps in Docket 6605 to protect the interest of customers if the Board rejects CVPS's position in that case.³⁰⁵

              The Department opposes both adjustments. According to the Department, it is not known and measurable that either of the outcomes CVPS expects will occur.³⁰⁶ The Department points out that CVPS has continued to bill its CATV attachers at the higher rate.³⁰⁷ Instead, the Department asks that, until Docket 6605 is resolved, the test year billed revenues from CATV pole attachments should be included in CVPS's rates.³⁰⁸

              The Department's assertions concerning reliance upon the potential outcome of Docket 6605 have some merit. At the present time, we conclude that CVPS's adjustments are not known and measurable.³⁰⁹ With the resolution of Docket 6605 unknown, we cannot know if CVPS will prevail on any or all of its arguments. Moreover, because of this uncertainty, it is impossible to measure the proposed adjustment to the test year revenue levels. CVPS's decision to record a reserve on its books for the potential loss of revenue does not convert the uncertainty into a known and measurable change. The result and magnitude of the financial impact are still unknown.

              We understand that the timing of Docket 6605 and this proceeding means that, if we do not reflect the revenue adjustment CVPS proposes and the Company ultimately loses its pole attachment argument, CVPS may earn less than it would if we accepted the adjustment. The known and measurable standard notwithstanding, CVPS has proposed that we allow its adjustment and then take action in Docket 6605 to protect the interests of consumers. If we can assure that ratepayers could be fully protected from paying rates based upon CATV revenue reductions that do not occur, we could allow CVPS's adjustment now. To achieve this result, the difference between the pole attachment revenues we allow in rates for both periods and the revenues that would derive from using the same billing determinants but applying the conclusions in Docket 6605 would need to flow back to ratepayers.

              CVPS did not specify how the Board could legally achieve this result, although we see two possible approaches. First, we could issue an accounting order requiring CVPS to track the difference between the amount of revenue we include in rates and the revenue collected based upon the final ruling. Such a decision would have the adverse effect of continuing the practice of using accounting orders for events that are not truly extraordinary. As we explain elsewhere in this Order, it would be preferable to limit the use of accounting orders to events that are consistent with GAAP's description of what constitutes an extraordinary event.

              A second approach, which we adopt, would require CVPS, as part of its compliance filing in this docket, to submit a specific proposal to protect the interests of consumers following any final order in Docket 6605. CVPS's proposal should ensure the difference in CATV revenues (including the effect of any possible retroactive adjustment) is returned to ratepayers in a timely fashion. If CVPS elects not to propose such a mechanism (consistent with Vermont law), we cannot conclude that CVPS's adjustment is known and measurable. In this case, CVPS's compliance filing should not include the adjustment to the CATV revenue proferred by the Company.

              Finally, we are concerned about the Company's apparent inconsistency in this proceeding. On the one hand, CVPS says that it is sufficiently likely to lose the CATV case that it must record a loss on its books.³¹⁰ If the likelihood of success is as dim as CVPS seems to suggest, it is not clear why it is reasonable to charge ratepayers for the cost of litigating what CVPS now characterizes as a losing position. We will consider this issue in CVPS's next rate proceeding. At present, we can only infer from CVPS's continued litigation that it views its prospects for success more favorably than its current position -- and the booking of a reserve -- would suggest, in which case the Department's argument carries greater weight.

K.  Agreed-Upon Adjustments

Findings

272. The $3,500 that CVPS paid for the production and distribution of a video entitled "Patriotism and You" should be removed from the costs of service for both Rate Years 1 and 2. Schultz and DeRonne pf. at 75; Gibson reb. pf. 11/15/04 at 30.

273. Safety training costs for Rate Year 1 should be increased $9,000. Safety training costs for Rate Year 2 should be increased $8,000. Schultz and DeRonne pf. at 67; exh. CVPS-4.

Discussion

              CVPS and the DPS have agreed on two miscellaneous adjustments.³¹¹ For the reasons explained below, we conclude that the adjustments are appropriate, and we hereby accept them. First, the Board has long held that shareholders, not ratepayers, should pay for utility companies' charitable and community service activities. Consistent with this policy, the costs associated with the "Patriotism and You" video should be charged to shareholders, not ratepayers. Second, the adjustment to safety training costs corrects an error made by CVPS in its original filing -- it had reflected the discount offered rather than the projected costs.

VII.  COST OF CAPITAL

Findings

274. CVPS's capital structure, rates for each capital component of the capital structure and weighted average cost of capital for Rate Year 1 is shown in the table below.

Description	Ratio	Cost Rate	Weighted Average Cost of Capital
Long Term Debt	40.29%	7.29%	2.94%
Preferred Equity	5.10%	6.43%	0.33%
Common Equity	54.61%	10.00%	5.46%
Total	100.0%		8.73%

Exh. DPS-L&A-11, Schedule SR4; Talbott and Roschelle pf. at 8.

275. CVPS's capital structure, rates for each capital component of the capital structure and weighted average cost of capital for Rate Year 2 is shown in the table below.

Description	Ratio	Cost Rate	Weighted Average Cost of Capital
Long Term Debt	39.75%	5.77%	2.29%
Preferred Equity	4.72%	6.31%	0.30%
Common Equity	55.53%	10.00%	5.55%
Total	100.0%		8.14%

Exh. DPS-L&A-12, Schedule 4; Talbott and Roschelle pf. at 8.

276. An allowed return on equity of 10 percent adequately compensates investors, given the level of perceived risks in CVPS's business. Talbot and Roschelle pf. at 5; tr. 11/5/04 at 45-46 (Talbot and Roschelle).

277. The 10-year Treasury bond yield currently ranges between 4 and 5 percent, the lowest level in over 40 years. Woolridge pf. at 2.

278. Capital costs, including equity costs, for U.S. corporations are at their lowest levels since the 1960's. Talbot and Roschelle pf. at 6; Woolridge pf. at 2.

279. CVPS's common and preferred equity ratio is 60 percent, approximately 20 percent higher than the equity ratios of other similarly-situated electric utilities. Exh. DPS-JRW -3.

280. The use of accounting orders which defer the recovery of prudently incurred, but unexpected, increases in purchased power is viewed by the investment community as an adequate substitute for purchased power adjustment clauses. Exh. DPS-Cross-19.

281. The Company's purchased power strategy reduces operational risk and minimizes its capital expenditure requirements. Exh. DPS-41; exh. DPS-Cross 22 at 17.

282. By purchasing a substantial amount of its power commitments under fixed long-term contracts, CVPS reduces its exposure to wholesale electric price volatility under FERC's Standard Market Design ("SMD"). Exh. DPS-Cross-26.

283. CVPS's bond ratings have been affirmed by Standard & Poor's (BBB-) and upgraded by Fitch (BBB+), in part, because of the improving regulatory climate in Vermont, a diverse customer mix, low operating risks, and interest coverage ratios commensurate with the ratings category. Exh. CVPS-JCC-12; exh. DPS-45; exh. CVPS-5 at 40 (2001 CVPS Annual Report); exh. CVPS-7 at 48 (2003 CVPS Annual Report).

284. CVPS has a demonstrated history of strong, stable cash flows and moderate financial leverage. Exh. DPS-Cross-22 at 16.

285. CVPS benefits from operating in Vermont because retail competition has not been approved, therefore the risk of bypass has been essentially eliminated. Exh. DPS-Cross-22 at 16.

286. CVPS benefits from customer diversity as its five largest customers represent only 5 percent of the Company's total electric revenue. Exh. CVPS-10 at 2.

287. CVPS is a traditional, regulated electric utility company which operates in a relatively low-risk business characterized by secure, predictable cash flows and solid capitalization. Exh. DPS-Cross-22 at 17.

288. Investors regard the stocks of smaller companies to be slightly more risky than the stocks of companies with larger capitalization due to the lack of liquidity.³¹² Talbot and Roschelle pf. at 11; tr. 11/5/04 at 65-66 (Talbot and Roschelle).

289. As of September, 2003, CVPS had a market capitalization of approximately $250 million. Talbot and Roschelle pf. at Schedule 2a.

290. CVPS has approximately 12.25 million shares outstanding, of which 5.5 million shares are owned by institutions. Woolridge sur. pf. at 3.

291. Approximately 5 percent of CVPS's outstanding shares (roughly 612,500) trade on a monthly basis. Woolridge sur. pf. at 3.

292. CVPS was ranked first in the nation in the Edison Electric Institute's 2003 index for five-year shareholder returns, providing shareholders a 205 percent return.³¹³ Talbot and Roschelle pf. at 7.

Discussion

              There are three essential steps in setting the weighted average cost of capital. First, we determine an appropriate capital structure. Second, we determine the cost of each capital component. Third, we determine the cost of each capital component according to its proportion of the total capital structure. The sum of these weighted capital components is the weighted-average cost of capital. In these proceedings, the capital structure and the costs of preferred equity and debt are not in dispute.

              While debt is less expensive than equity, there are limits to the amount of debt that can be used to finance utility operations before equity investors begin to demand higher returns. Therefore, an appropriate amount of equity is necessary to minimize overall capital costs. Based on the record evidence and agreement between the parties, we find that it is appropriate to use a capital structure in Rate Year 1 consisting of 40.29 percent long-term debt, 5.10 percent preferred equity and 54.61 percent common equity. For Rate Year 2, we find that it is appropriate to use a capital structure consisting of 39.75 percent long-term debt, 4.72 percent preferred equity and 55.53 percent common equity. We conclude, based on the record, that long-term debt and preferred equity costs in Rate Year 1 are 7.29 percent and 6.43 percent, respectively. In Rate Year 2, we conclude that long-term debt and preferred equity costs are 5.77 percent and 6.31 percent, respectively.

              In these proceedings, the parties disagree on the appropriate return on equity. CVPS, the Department and AARP recommend returns on equity of 11.0 percent, 8.75 percent and 10.0 percent, respectively. Based on the record evidence, we conclude that a return on equity of 10.0 percent appropriately compensates investors for the level of risk they may encounter by holding CVPS stock. Authorizing a 10.0 percent return on equity provides CVPS with the opportunity to generate risk-adjusted returns that are comparable to the potential returns of similarly-situated electric utilities. It also assures CVPS's investors that the Company will remain financially sound and have the ability to raise additional capital, if necessary.

              We recognize that we are authorizing a different return on equity in these proceedings than we recently authorized for GMP (10.50 percent) and Vermont Gas Systems, Inc. ("Vermont Gas") (10.98 percent).³¹⁴ Each time we determine a company's return on equity, we consider that company's particular situation. Our decisions regarding GMP and Vermont Gas reflect the circumstances facing those companies, circumstances that do not apply to CVPS. In GMP's case, roughly 20 percent of its retail revenues are generated from a single industrial customer. With such a concentration of revenues in one large industrial customer, we have no trouble concluding that investors perceive GMP as more vulnerable than CVPS. With regard to VGS, the Board authorized a 10.98 percent return on equity as an incentive to investors to assume greater risk for building out VGS' transmission pipe system into areas of Vermont that are current ly unserved.

              CVPS asserts that the cumulative effect of a series of company-specific risks warrant an 11.0 percent return on equity. These risks include the lack of a purchase power adjustment ("PPA") clause, FERC's Standard Market Design ("SMD") rules, negative perceptions of the investment community, incomplete implementation of a performance-based regulatory regime and the discontinuance of the Account Correcting for Efficiency ("ACE") mechanism. CVPS argues that the Board must also consider the effects of the DPS's proposed cost-of-service adjustments may have on investors' perceptions of CVPS's ability to earn a reasonable return on their investment.³¹⁵ We address each of CVPS's assertions below.

Purchase Power Adjustment Clause

              Purchase power adjustment clauses provide utilities with the ability to flow through increases or decreases in the cost of power directly to retail customers in between rate investigations. Vermont Supreme Court precedent prohibits the use of PPA clauses as such flow-through mechanisms are inconsistent with the customer notice requirements of 30 V.S.A. Section 225.³¹⁶ Accordingly, CVPS claims that a higher return on equity of 11.0 percent is appropriate. To support its argument that investors are demanding a higher return on equity, CVPS relies on a portion of a Standard & Poor's report that states:

Although short-lived the [Vermont Yankee Nuclear Power Plant] outage underscores one of the potential vulnerabilities that Vermont's [Investor Owned Utilities] face in a long-term outage. Neither utility (i.e. CVPS and GMP) has access to an automatic fuel and purchase adjustment clause.³¹⁷

              However, after reviewing the entire Standard & Poor's report, we reach a different conclusion than CVPS. Rather than advising investors to either demand higher returns on equity or sell their Vermont-based holdings, the report, instead, informs investors that both CVPS and GMP have the ability to obtain timely redress in the form of accounting orders in the absence of a PPA. As we explain above in Section IV, this Board has issued accounting orders due to extraordinary events. The report also provides investors with assurances that because CVPS has ample cash reserves and access to capital, the potential risk posed by Vermont's PPA prohibition is offset. The Company's diverse customer mix, stable load growth and low operating risks mitigate the amount of potential risk associated with the lack of a PPA.

              We also note that the Company, in its private placement memorandum to investors, downplayed the effects, if any, of Vermont's lack of a PPA. In the memorandum, CVPS stated that:

The company recognizes that adequate and timely rate relief is required to maintain financial strength, particularly since Vermont law does not allow power and fuel cost to be passed to consumers through a fuel adjustment clause. The company will continue to review costs and request rate increases when warranted.³¹⁸

              The positive attributes of CVPS's diverse customer mix, low operating risks and long-term fixed-priced purchase power contracts offset any additional risks facing CVPS as a result of the PPA prohibition.

Standard Market Design

              CVPS contends that FERC's SMD rules create new uncertainty due to increased volatility in wholesale power costs even for load serving entities who have secured all of their power resource requirements through fixed-price contracts.³¹⁹ The SMD rules, according to CVPS, have also created uncertainty in the wholesale ancillary services market, such as operating reserves. As an example of these additional risks in the operating reserves market, CVPS points to its experience during an extreme cold weather pattern in January, 2004. According to CVPS, the Company incurred extraordinary expenses over a three-day period when operating reserve charges increased dramatically due to short supplies of natural gas.³²⁰

              In response, the DPS claims that CVPS has overstated the SMD-related risks, if any. To the extent such risks do exist, the DPS contends that electric utilities are accustomed to mitigating their impact.³²¹ The DPS notes that CVPS mitigates such risks by procuring a substantial portion of its power requirements under long-term contracts. As a result, the DPS asserts that most of CVPS's power purchases are not subject to large price swings.

              The DPS also contends that, contrary to CVPS's assertions that these risks are meaningful, the bond rating agencies discount them. The DPS states that SMD-related risks actually received little to no attention in the investment analyst reports that CVPS submitted into the record.³²² Rather than express specific concerns over SMD rules, according to the Department, these same reports listed a series of positive attributes which enhance CVPS's credit rating such as regulatory support for supply cost recovery, the sale of Vermont Yankee, increases in operating efficiencies, and adequate capitalization ratios.³²³

              We conclude that CVPS has overstated the concerns of the investment community with regard to the potential impact SMD rules may have on investor returns. FERC's SMD rules are not specific to CVPS.³²⁴ Similar rules apply to investor-owned electric utilities in most of the United States. Thus, there is no basis for assigning to CVPS an additional risk premium compared to other electric utilities. In addition, CVPS purchases a substantial portion of its power under long-term contracts, the cost of which we are allowing to be recovered from ratepayers. Therefore, most of CVPS's power purchases are not affected by the volatility of the regional wholesale power market.³²⁵ And, while CVPS is exposed to weather-related spikes in operating reserve charges, there are opportunities to offset these costs by selling excess power into the wholesale market at favorable prices.

Perceptions of the Investment Community

              CVPS contends, that as a result of past decisions issued in 1998 regarding the recovery of Hydro-Québec power costs, the investment community perceives Vermont as a difficult jurisdiction. Past Board decisions, according to CVPS, are viewed as inconsistent and at odds with stockholders' interests. CVPS argues that such inconsistencies lead to the conclusion that investors should be allowed to earn a higher rate of return. To improve its image and dispel these negative perceptions, CVPS contends that it is necessary for this Board to authorize an 11.0 percent return on equity.

              Pointing to the same investment analyst reports that CVPS relies upon, the DPS claims that investment analysts have a positive view of the regulatory environment in Vermont.³²⁶ Additionally, the DPS states that despite the Company's assertions in this proceeding regarding negative perceptions of regulation in Vermont, CVPS portrayed a positive and improving regulatory environment in a recently issued Private Placement Memorandum.³²⁷

              CVPS's assertions regarding the investment community's negative perceptions of Vermont are unsupported by the record evidence and inconsistent with statements the Company has made to the investment community. Investors clearly consider CVPS's stock to be a solid investment, in fact it ranked first among all investor-owned utilities in the United States in the 2003 Edison Electric Institute's index for total shareholder returns over the five-year period ending December 31, 2003. Investors who purchased CVPS stock on January 2, 1999, earned a cumulative return of 205 percent by the end of 2003. Compared to a -3.0 percent cumulative return for the S&P 500 index over the same period, CVPS investors were clearly compensated well for the risks they assumed.³²⁸ Additionally, at the end of 2004, Fitch IBCA, a credit rating agency, upgraded outstanding CVPS bonds from BBB to BBB+ and considered the Company's outlook to be positive.³²⁹

              We also note that CVPS's own statements to the investment community in its $75 million private placement memorandum are inconsistent with the Company's assertions in this proceeding. In that Memorandum, CVPS characterized its operations as "relatively low risk" with "secure, predictable cash flows and solid capitalization" which are the result of a regulated rate structure that has produced "stable EBITDA"³³⁰ and "strong interest coverage ratios."³³¹ In addition, CVPS's cost of capital witness testified that the investment community's perceptions of Vermont were improving.³³² Based on the record evidence, we find CVPS's assertions in these proceedings to be inconsistent with its own statements to potential investors, and therefore, unpersuasive. Due to the recent bond rating upgrades and the cumulative five-year returns on CVPS stock compared to other investor-owned utility stocks, we can only conclude that the investment community has a favorable opinion of the Vermont regulatory environment.

SERVE Plan

              According to CVPS, the current SERVE³³³ plan is the functional equivalent of a partial Performance-Based Regulation plan ("PBR"). CVPS states that it could, however, be reasonably viewed as a step toward the creation of a more complete plan since performance standards and the risk of financial penalties for poor customer service are important features of a PBR mechanism as well as for CVPS's SERVE plan.³³⁴ Despite the similarities, CVPS asserts that the current SERVE plan imposes extra risks in the form of financial penalties for poor customer service but does not include the financial incentives for exceptional performance that other, more complete PBR plans provide.³³⁵ According to CVPS, there are more down-side risks inherent in the current SERVE plan than up-side risks, therefore, investors should be allowed to earn a higher return on equity.

              The DPS claims that CVPS has overstated the alleged down-side risks of the current SERVE plan. Similar to the alleged SMD concerns mentioned above, the DPS points out that investment analysts made no specific statement related to the current SERVE plan in the investment reports that CVPS entered into the record.³³⁶

              Based on the record evidence, we conclude that CVPS's SERVE plan does not impose upon the Company any additional risks that could not be readily offset. The record evidence clearly indicates that any potential down-side risks, if they exist at all, associated with the SERVE plan have been offset by other positive attributes of CVPS's operations such as low operating risks, stable EBITDA and secure, predictable cash flows.

Account Correcting for Efficiency

              These proceedings are the first earnings investigation since the discontinuance of the Account Correcting for Efficiency ("ACE"), a mechanism that provided the Company with a method of recovering net revenue losses resulting from system-wide demand-side management measures implemented by the Energy Efficiency Utility ("EEU"). As a result, CVPS asserts that an 11.0 percent return on equity is warranted because the elimination of ACE revenues exposes the Company to the risk that its earnings will erode.³³⁷ According to CVPS, as long as the unit price of providing electric service exceeds marginal cost, the loss of the ACE revenues adversely affects the Company's financial performance.³³⁸

              In response, the DPS asserts that the elimination of the ACE mechanism does not impose any additional risk on investors. Similar to CVPS's assertions related to the perceived amount of additional risks related to SMD and the SERVE plan, the elimination of the ACE mechanism was not specifically mentioned in the investment analyst reports submitted by the Company. The record evidence does not support CVPS's contentions that elimination of the ACE mechanism has increased risks. CVPS made no explicit reference to the elimination of the ACE mechanism in its Private Placement Memorandum to investors even though that document was issued in May, 2004, nearly 12 months after ACE was discontinued. Given the lapse in time, CVPS should have been fully aware of the financial implications of the ACE phase-out, if any, at the time it issued its Memorandum. Had there been a significant financial impact, then CVPS would have been obligated to disclose the nature of these potential impacts and fully describe the attending risks that the elimination of ACE would have presented to investors. The fact that the company did not specifically raise the issue in its Memorandum suggests to us that CVPS believes that the discontinuance of ACE is a non-material event.

              Contrary to CVPS's opinion that the discontinuance of the ACE mechanism exposes the Company to the potential risk of earnings erosion, we conclude that it is more likely that CVPS will actually benefit from system-wide energy efficiency measures. The EEU's efforts result in less energy consumption by CVPS customers. As a result, the company is able sell more excess power into the wholesale market at favorable rates. Such actions improve the financial performance of the Company, rather than impair it.

Liquidity Risk

              Investors in companies with small market capitalizations are typically exposed to additional risks as a result of their inability to consummate large stock transactions in a timely manner.³³⁹ CVPS is considered to be a small capitalized ("small-cap") company.³⁴⁰

              The DPS asserts that while CVPS is considered to be a small-cap company, there is no empirical evidence to support the contention that investors do in fact demand an extra liquidity risk premium. In the DPS's opinion, there is no basis for increasing its return on equity recommendation of 8.75 percent until CVPS has presented evidence of a liquidity premium.

              Investors' expected returns are not readily observable. It has been a long-standing regulatory practice to infer the amount of future expected returns by examining forecasted growth rates of similarly-situated companies and the level of risks these companies are expected to encounter. Similarly, the amount of liquidity risk that investors assign to small-cap stocks is unobservable. Therefore, we must also infer the amount of this type of risk.

The market capitalization of the list of similar-situated companies analyzed by AARP is as follows:³⁴¹

Company	Market Capitalization ($ Millions)
Avista	850
CVPS	250
Green Mtn Power	125
MGE	575
Otter Tail	690
Vectren	1,900
WPS	1,700
Average	870

              There are 12.25 million CVPS shares outstanding, of which approximately 45 percent are held by institutions who are more likely to place larger orders than non-institutional owners.³⁴² CVPS's market capitalization is approximately 28.7 percent of the mean average of the above-captioned companies. On this evidence, we conclude that CVPS investors face an additional risk compared to the investors of the other electric companies in the above-captioned group because of a perceived liquidity risk. The market capitalization of the Company is smaller than the other companies and a large percentage of the Company's stock are held by institutional investors who are inclined to trade relatively large blocks of stocks. It is, therefore, appropriate to increase the Company's return on equity above the recommendation of the DPS as compensation.³⁴³

Basis for Decision

              As with countless other rate cases before this Board, our decisions are guided by the law and regulatory precepts that have evolved over the last 100 years. These proceedings are no different. And, in spite of the changing nature of the law and regulation, our unwavering goal is to strike a balance between the interests of ratepayers who desire low-cost reliable service and investors who hope to maximize their returns on invested capital.

              The DPS, AARP and CVPS have recommended returns on equity of 8.75 percent, 10.0 percent and 11.0 percent, respectively. All of the recommendations were based on analyses using traditional methodologies³⁴⁴ of estimating required returns. Two of the three parties also relied, in part, on recently authorized returns on equity in other jurisdictions. The DPS's recommendation of 8.75 percent was predicated on the proposition that risk premiums were shrinking.

              Neither the law nor regulatory precepts prescribe a methodology for setting the appropriate return on equity. All that is required of us, is to authorize a return on equity that is fair and reasonable to all stakeholders. It is not necessarily the method used to establish an appropriate return on equity that is important but the end result.³⁴⁵ We conclude that adopting the DPS' recommendation would result in an unfair decision based on an unproven supposition that fails to strike a balance between the interests of ratepayers and investors. Therefore, we reject the DPS's recommendation. Instead, we conclude that, based on the record evidence, a return on equity of 10.0 percent provides CVPS with the opportunity to generate risk-adjusted returns that are comparable to similar-situated companies and assures the financial soundness of the Company.

VII.  OTHER ISSUES

A.  Treatement of Regulated Affiliates

Findings

293. CVPS owns interests in affiliates that are subject to the jurisdiction of FERC. These "regulated affiliates" are:

• the Vermont Electric Power Company ("VELCO");

• the Vermont Yankee Nuclear Power Corporation ("VYNPC");

• Connecticut Yankee;

• Maine Yankee; and

• Yankee Atomic

(the last four, collectively, are often referred to as "the Yankees"). Gibson pf. at 28; exh. CVPS-7 at 29-31.

294. CVPS owns 50.5 percent of VELCO's outstanding common stock. Exh. CVPS-7 at 30.

295. CVPS has a 58.85 percent ownership interest in VYNPC. Id.

296. CVPS has a 2 percent ownership interest in Maine Yankee, 2 percent ownership interest in Connecticut Yankee, and 3.5 percent ownership interest in Yankee Atomic. Id. at 31.

297. Vermont's consistent ratemaking treatment for decades has been to consider both investments and returns on rate-regulated affiliates above-the-line in a Vermont utility's cost of service. This means that equity investments, income, and tax effects of regulated affiliates are traditionally included in cost-of-service filings. Behrns sur. pf. at 16; Behrns pf. at 12.

298. CVPS proposes that past precedents be changed and that it now be allowed to treat its regulated affiliates below-the-line for ratemaking purposes. In CVPS's cost-of-service filings in these proceedings, the investments in the affiliates were removed from the Company's rate base, equity earnings in the affiliates was not credited, and there was no deduction for equity earnings of these affiliates in the income tax calculation. Gibson pf. at 27-28; Frankiewicz pf. at 21; Behrns pf. at 12.

299. The treatment of the regulated affiliates proposed by CVPS represents a change in the treatment previously afforded such affiliates in the Company's prior rate cases over many years, as well as in this Board's consistent treatment of other investor-owned utilities in Vermont. Deehan reb. pf. at 20; Behrns pf. at 11.

300. At present, the FERC-approved returns on equity for the Yankees are less than the Company's current allowed return on equity on its Vermont utility operations. The FERC-approved return on equity for VELCO is currently higher than the Company's current allowed return on equity on its Vermont utility operations. CVPS responses to Board's 1/24/05 Memorandum, dated 2/2/05, at Attachment PSB 2-1A.

301. Above-the-line ratemaking treatment for affiliates whose allowed return on equity is greater than CVPS's allowed return on equity, in general, decreases CVPS's overall retail revenue requirement. The converse is also true. Behrns sur. pf. at 16; tr. 1/13/05 at 178-180.

302. The effect of the established ratemaking treatment of the Yankees, generally, represents an increase to the Company's revenue requirement. Conversely, treating VELCO similarly reduces the Company's retail revenue requirement. Behrns pf. at 12.

303. Historically, costs for CVPS's decommissioning obligations for the Yankees were recovered in rates. Behrns sur. pf. at 16.

304. CVPS's costs for services provided by VELCO are recovered in rates. Exh. DPS-L&A-11 at schedule SR1; exh. DPS-L&A-12 at schedule SR1.

305. CVPS's regulated affiliates are very much integrated and a part of the Vermont jurisdictional income. Tr. 11/3/04 at 135 (Gibson).

306. The retail ratemaking treatment of CVPS's investments and earnings in its regulated affiliates has no effect on the rates or return on equity of those affiliates. Behrns sur. pf. at 16; tr. 1/13/05 at 179-180 (Behrns).

Discussion

              CVPS proposes to treat its FERC-regulated affiliates below-the-line³⁴⁶ for ratemaking purposes.³⁴⁷ CVPS acknowledges that this would be a departure from the way CVPS has treated its regulated affiliates in its prior rate cases. The Company argues that this change in the treatment of its regulated affiliates is appropriate for two reasons.

              CVPS's first argument is that, as a matter of law, the Board must treat CVPS's regulated affiliates below-the-line. For this proposition, CVPS relies upon an aspect of federal law known as the "Filed Rate Doctrine." That doctrine, as characterized by CVPS, holds that rate-regulated affiliates are subject to the exclusive ratemaking jurisdiction of FERC.³⁴⁸ CVPS now contends that treating CVPS's regulated affiliates above-the-line for Vermont ratemaking purposes denies the Company the ability to recover its FERC-approved rates (which include FERC's return on equity determinations) for the affiliates.³⁴⁹ CVPS also argues that above-the-line treatment constitutes "trapping" of costs for wholesale power, citing Mississippi Power & Light Co. v. Mississippi, 487 U.S. 354, 108 S.Ct. 2428, 101 L.Ed.2d 322 (1988).

              Second, CVPS claims that, as a matter of policy and discretionary judgment, the Board should approve its requested accounting treatment for its regulated affiliates. CVPS bases this argument on various changes in the electric industry in recent years.

              The DPS recommends treating both the costs and the benefits of CVPS's FERC-regulated affiliates above-the-line.³⁵⁰ The DPS maintains that this has consistently been the accepted practice for CVPS and all other Vermont utilities.³⁵¹ As explained by the DPS:

Vermont's traditional rate making treatment is to include above the line in CVPS's cost of service its investments and returns on investment [sic] that were made to supply energy to Vermont ratepayers, who have defrayed the cost of those investments, and who therefore deserve to share in any attendant economic gains.³⁵²

              The DPS contends that it is not advocating any positions that trigger Filed Rate Doctrine concerns. The DPS does not dispute CVPS's assertion that the Board lacks the authority or the jurisdiction to "challenge, alter or deny CVPS and its regulated affiliates the recovery of the affiliates' FERC authorized ROEs."³⁵³ The DPS maintains that it is not seeking to "prevent the recovery of costs including the ROE specified in the affiliates' rate schedules . . ."³⁵⁴ as CVPS contends.³⁵⁵ Additionally, the DPS counters each of the points CVPS makes concerning the Filed Rate Doctrine. To wit, the DPS states, and the record demonstrates, that it is not asking the Board:

• to interfere with any FERC-filed rate schedules;

• to interfere with any FERC-jurisdictional service relationship;

• to deprive FERC of its plenary authority over interstate wholesale rates;

• to interfere with the ability of either CVPS or its affiliates to "enjoy" the rates ordered by FERC;

• to find that FERC's actions have been unreasonable;

• to compel CVPS to seek any changes before FERC, or to "take indirect action to change the voluntarily entered and FERC-authorized arrangement;"

• to take action to preempt FERC in matters that are within the FERC's exclusive jurisdiction.³⁵⁶

The DPS further contends that no evidence in the record supports CVPS's claim that the DPS is seeking to deny CVPS its ability to recover from ratepayers the FERC-regulated costs it incurs from its affiliates. On the contrary, the DPS states that the evidence in the record shows that CVPS can and will recover from ratepayers the full, unadjusted costs of FERC-regulated utility expenses.³⁵⁷

              For the reasons explained below, we conclude that CVPS should, as in the past, account for the investments in its regulated affiliates above-the-line in rate base, and the earnings therefrom, including the income tax effect, above-the-line in its cost of service.

              CVPS's principal argument is that Vermont's traditional above-the-line accounting treatment for regulated affiliates violates the Filed Rate Doctrine. This argument fails to distinguish between the tariffed rates approved by FERC for services that CVPS receives from its regulated affiliates, and CVPS's equity investments and the equity in earnings related to those activities. State regulators may not interfere with the recovery of FERC-tariffed rates from ratepayers, but the state-jurisdictional ratemaking treatment of earnings by utilities from their FERC-regulated affiliates' operations is, as the DPS points out, squarely and entirely within state jurisdiction.³⁵⁸

              A recent survey of the Filed Rate Doctrine's history, purpose, and scope is set out in Pacific Gas and Electric Co. V. Lynch, 216 F.Supp. 2d 1016 at 1029-1035, (N.D. Cal. 2002). That case involved many billions of dollars affected by California's failed experiment with deregulation. The Court, in a thorough and persuasive opinion, notes that the root and essence of the Filed Rate Doctrine can be simply stated: "that regulated providers [must] charge end-users only the rate on file with the appropriate regulatory agency."³⁵⁹ The Court observed that, "historically, the filed rate doctrine's primary purpose has been to prevent price discrimination."³⁶⁰ Over time, in regard to electricity regulation, "the filed rate doctrine came to have a subsidiary application demarking the boundary between federal and state regulatory authority." Importantly, "the doctrine also operates to prevent sta te regulators, as well as courts, from taking action that fails in any manner to account for the fact that in most instances today, a utility must purchase power delivered to consumers pursuant to the rate filed with the appropriate federal agency."³⁶¹ Relying on that point, the Pacific Gas court ruled that California regulators could not ignore the net effect of federally-regulated power transactions (in that case a net loss) on the regulated utility's necessary retail revenue requirements. Applying that ruling in the present case means that we accept the Department's position and will consider the net effect of CVPS's federally-regulated power transactions (in this case a net gain) on the regulated company's retail revenue requirements.

              Nantahala does not suggest a different result. That case codified the FERC's exclusive jurisdiction over the rates charged to interstate wholesale customers. Treating CVPS's regulated affiliates above-the-line for Vermont ratemaking purposes does not, in any way, alter the rates charged to CVPS by its "wholesale-as-seller" affiliates. Mississippi Power & Light prohibited states from barring "regulated utilities from passing through to retail customers FERC-mandated wholesale rates."³⁶² Vermont's traditional above-the-line treatment of regulated affiliates is unrelated to the recovery of FERC-tariffed wholesale rates for utility services from Vermont retail ratepayers. In this case, we are allowing recovery from Vermont ratepayers of CVPS's costs for FERC-tariffed services from its regulated affiliates. Moreover, CVPS's contention that above-the-line treatment of the investment and earning s of its regulated affiliates constitutes "trapping" as described in Mississippi Power & Light is unfounded, because above-the-line treatment for retail rate setting does not affect the FERC-regulated affiliate's ability to recover its FERC-set rates. In short, CVPS's ratepayers have always paid, and will continue to pay wholesale rates the FERC finds just and reasonable, for power that is otherwise prudently obtained.

              Here, too, Pacific Gas offers some helpful insights. Rejecting a utility argument much like that presented by CVPS, the Court stated that:

Quoting selectively from some seminal filed rate cases, PG&E argues that the filed rate doctrine forbids state regulators from looking to sources of revenue other than retail rates when determining whether existing rates are sufficient to cover operating costs.³⁶³

Expressly rejecting that concept as a matter of law, the Court held, in the same paragraph, that the filed rate doctrine, itself:

. . . does not require that retail rates be excessively high when utilities are receiving revenue from other sources. Retail rate setting based on a regulated utility's "overall financial structure" may be reasonable.

In fact, after specifically considering a situation much like CVPS's -- the "offset" potential of revenues from utility sales into a regional power market, the Court explicitly stated that:

. . . if retail rates alone were insufficient to recover costs, but were sufficient in combination with other revenue, properly considered, then wholesale costs would not be trapped and there would be no violation of the filed rate doctrine.³⁶⁴

This, of course, is fully consistent with the basic Hope, Bluefield, and Duquesne line of cases stating that revenue determinations are tested by a functional end-result test compared to the utility's overall position.³⁶⁵

              We also find that CVPS's proposed treatment is at odds with the past and current practice of CVPS and all other utilities in Vermont.³⁶⁶ The record evidence -- including CVPS's rebuttal testimony -- does not show any reason why we should deviate from that practice now.³⁶⁷ Simply put, changes in the industry are not of a nature, nor of a magnitude relative to CVPS, that would warrant reversal of such a fundamental, equitable, practice.

              The fundamental rationale articulated by the DPS for continuing to treat regulated affiliates above-the-line is straightforward: ratepayers have paid for those investments through rates, and therefore deserve to share in the economic benefits of the investments. As CVPS's Chief Financial Officer recognized: "In my mind, those either [sic] power companies, the nuclear power companies, or VELCO . . . are very much integrated and part of the Vermont jurisdictional income . . . ."³⁶⁸ We are persuaded that this rationale continues to be good public policy, and in the general interest of Vermont ratepayers.

              One additional point deserves emphasis. We are particularly troubled by CVPS's attempt to treat its investment and equity earnings in VELCO as below-the-line, thus denying to retail customers the benefits of increasing profits in that sector. This effort is fundamentally inconsistent with VELCO's actual position in a very recent proceeding which involved the most significant VELCO project in half a century. In that proceeding, the Board reviewed, and ultimately approved, VELCO's request for the largest expansion of the VELCO transmission system in decades, funded by a very significant increase in its equity. In response to concerns raised by parties regarding who would benefit from the project, the Board concluded that:

The evidence before us demonstrates that the primary beneficiaries will be the citizens of Vermont, who will benefit from the improved reliability, economic development, and enhanced safety that results from a more robust electric grid.

It is true that VELCO will benefit from the project through an increase in its equity, dividends from which have traditionally been used to reduce the bills charged to Vermont's ratepayers by VELCO's utility owners.³⁶⁹

              It is difficult to believe that CVPS, owning more than 50 percent of VELCO's stock and with direct representation on VELCO's Board of Directors, could have been unaware of the position that VELCO asked us to rely upon in that proceeding. In any case, the Order of 1/28/05, makes clear the Board's reliance on the traditional practice of treating Vermont utilities' investment in VELCO above-the-line for Vermont ratemaking purposes.³⁷⁰ Yet CVPS did not even address the VELCO proposition in its testimony, its Brief, or its Reply Brief.

              Accepting the Department's position that CVPS should have included its regulated affiliates' equity in rate base, and the earnings in its cost of service, the following adjustments are required:

Rate Year 1

Utility	Investment	Return on Equity	Equity Earnings
Yankee Atomic Connecticut Yankee Maine Yankee Vermont Yankee      Subtotal VELCO Preferred VELCO Common      Subtotal Total	$           37,891 1,106,942 959,702 2,840,577 $      4,945,112 $         702,865 6,641,355 $      7,344,220 $    12,289,332	0.00% 6.00% 6.50% 7.50% 11.50% 11.50%	$                   0 66,417 62,381 213,043 $        341,841 $          80,829 763,756 $        844,585 $     1,186,426

Rate Year 2

Utility	Investment	Return on Equity	Equity Earnings
Yankee Atomic Connecticut Yankee Maine Yankee Vermont Yankee      Subtotal VELCO Preferred VELCO Common      Subtotal Total	$           37,891 1,106,942 959,702 2,840,577 $      4,945,112 $         702,865 15,093,950 $    15,796,815 $    20,741,927	0.00% 6.00% 6.50% 7.50% 11.50% 11.50%	$                   0 66,417 62,381 213,043 $        341,841 $          80,829 1,735,804 $     1,816,533 $     2,158,474

B.  Customer Service Agreement

Findings

307. CVPS and the DPS have reached an agreement regarding the customer service issues raised in these proceedings ("Customer Service Agreement"). Exh. DPS-CVPS-Joint-1.

308. Under the terms of the Customer Service Agreement, until CVPS and the DPS establish a further, more formal resolution, and beginning as soon as CVPS can implement changes (no later than 1/21/05), CVPS will permit former customers who have remaining unpaid balances from former accounts to add such arrearages to the balance of a newly established account, rather than requiring payment of the arrearage before a new account is established. The arrearage may be paid over a reasonable payment term. Exh. DPS-CVPS-Joint-1 at Paragraph 1.

309. The Customer Service Agreement also provides that CVPS and the DPS will engage in negotiations regarding the following issues:

• the arrearage issue described in finding 308, above;

• interpretation and application of the "reasonableness" criteria for payment arrangements, including, but not limited to, how to handle situations where individual representatives appear to be responding to consumers in ways that are inconsistent with CVPS's stated understanding of the rules;

• flexibility on medical notes;

• an escalation process for the DPS to work with CVPS in cases where the Company appears to the DPS to be taking an inflexible stand on billing and policy disputes, or where CVPS does not believe it can act in the way requested by the DPS, including, but not limited to, an understanding that CVPS will seek Board clarification of the issue of applicability of Section 229 to billing disputes should cases continue to arise where CVPS believes Section 229 is a barrier to settling a dispute; and

• credit and collection practices, generally.

Exh. DPS-CVPS-Joint-1 at Paragraph 2.

310. Under the terms of the Customer Service Agreement, CVPS and the DPS will report progress to the Board within 60 days of a Board order in these proceedings. Exh. DPS-CVPS-Joint-1 at Paragraph 3.

Discussion

              DPS and CVPS witnesses presented considerable evidence regarding several customer service issues. Subsequent to the admission of this evidence, the DPS and CVPS reached an agreement in which they state that they would like to engage in further discussions relating to these issues, and therefore ask the Board not to resolve any of the customer service issues raised in these proceedings.

              The terms of the Customer Service Agreement are described in findings 308-310, above. We have reviewed the Customer Service Agreement and conclude that it is reasonable. The Board has long recognized the value of negotiations between willing participants, and we are pleased that the DPS and CVPS have agreed to engage in further discussions regarding these customer service issues. Therefore, we hereby approve the Customer Service Agreement in its entirety, and we make no other ruling on any of the customer service issues raised in these proceedings.

C.  Rate Design

              In Docket 6866, we considered a Memorandum of Understanding ("MOU") between CVPS and the Department. One of the terms of that agreement was that CVPS would file a petition for a rate redesign within 60 days of the Board's Order approving the MOU. Under the terms of that agreement, CVPS would accompany the rate design filing with a fully-allocated cost-of-service study.

              As we explain above, following the Board's Order approving the MOU (with conditions),³⁷¹ CVPS sought reconsideration of the Board's Order. This ultimately led to the Department withdrawing its support for the MOU and requesting that the Board open an investigation into CVPS's rates.³⁷² As a result, the previous agreement for CVPS to submit an updated rate design no longer exists.

              It has been more than eight years since the Board last comprehensively reviewed CVPS's rate design. That investigation, Docket 5835, was the result of a rate design filing that the Board required as a condition of CVPS's last fully-litigated rate case.³⁷³ CVPS has experienced changes in its cost structure over that period of time, particularly since the New England power market (and the allocation of capacity costs) is now quite different than it was in Docket 5835 and CVPS has sold its substantial ownership stake in Vermont Yankee. We find it reasonable to reexamine CVPS's present rate design in light of these and other changes. Therefore, as a condition of this Order, we direct CVPS to file a new rate design, supported by a fully allocated cost-of-service study, within 90 days of this Order.

IX.  CONCLUSION

              Vermont law in Section 218(a) of Title 30 requires that utility rates be just and reasonable. The evidence in these proceedings demonstrates that CVPS's rates over the last year (Rate Year 1) exceed just and reasonable levels by 1.25 percent. In accordance with Section 227(b), CVPS must provide a refund to its customers to return the difference between these rates and the charges that CVPS imposed under its existing tariffs for the period from April 7, 2004, through March 31, 2005. CVPS also must reduce its rates by 1.88 percent (relative to the rates under existing tariffs) commencing April 1, 2005, on a service-rendered basis.

              These proceedings also address concerns that we raised in two prior decisions. As part of our approval of the Vermont Yankee sale, we required CVPS to submit a cost-of-service analysis in April of 2003 because of our expectation that the sale of Vermont Yankee would benefit CVPS and its ratepayers and could justify rate decreases. More recently, in Docket 6866, we conditionally approved a CVPS/Department agreement to freeze rates.³⁷⁴ The most significant of these conditions required CVPS to begin amortization of its large deferral accounts. In today's Order, both of these concerns are addressed. CVPS will begin amortization of its outstanding deferral accounts effective April 7, 2004. And our ruling on the overall rate levels ensures that the rates are just and reasonable, consistent with our intent in requiring the 2003 cost-of-service filing.

              To the extent the findings in this Order are inconsistent with any proposed findings, such proposed findings are denied.

X.  ORDER

              IT IS HEREBY ORDERED, ADJUDGED AND DECREED by the Public Service Board of the State of Vermont that:

              1. Central Vermont Public Service Corporation ("CVPS") is entitled to rates that will reduce retail revenues by approximately $3,304,000, or 1.25 percent below existing base rates, on service rendered on or after April 7, 2004.

              2. CVPS is entitled to rates that will reduce retail revenues by approximately $4,949,000, or 1.88 percent below existing base rates, on service rendered on or after April 1, 2005.

              3. CVPS shall, on or before March 31, 2005, submit a compliance filing calculating the precise decreases required by this decision. CVPS shall provide copies of the compliance filing to the parties in these proceedings.

              4. As part of its compliance filing in these proceedings, CVPS shall recalculate its overearnings for 2001, 2002, and 2003, using the Vermont Department of Public Service's ("DPS") cost-of-service-based calculation methodology. When CVPS recalculates its overearnings, it shall:

• remove 100 percent of transmission revenues before applying the wholesale allocation factor;

• include the portion of Construction Work In Progress on which it does not accrue an allowance for funds used during construction;

• treat all of its regulated affiliates above the line; and

• reflect our decisions regarding Distributed Utility Planning Demand-Side Management and the 2002 Vermont Yankee Mid-Cycle Outage that are described in Paragraphs 7 and 8, below.

              5. CVPS shall include in its compliance filing its proposal for refunding to ratepayers the exact amount, plus interest, that was over-collected from ratepayers during the period April 7, 2004, through March 31, 2005.

              6. As described in Section VI.J.2 of this Order, CVPS shall include in its compliance filing its proposal to protect the interests of its customers in the event that the Board issues an order in Docket 6605 that would result in CVPS earning more than $419,475 in Cable Television pole attachment revenues based on the same billing determinants used in the instant proceedings. If CVPS elects not to submit such a proposal, CVPS shall reduce the revenues authorized by paragraphs 1 and 2 of this Order by $447,100.

              7. CVPS shall remove recurring Distributed Utility Planning Demand-Side Management expenditures from the balance in its Distributed Utility Planning Demand-Side Management deferral account, thereby reducing the balance in this account to zero. In addition, CVPS shall return to ratepayers the difference between what CVPS collected in rates for Distributed Utility Planning Demand-Side Management recurring expenses and the Company's actual expenses in 2001, 2002, and 2003 ($184,479).

              8. CVPS shall reduce the amount of its deferral account associated with Vermont Yankee's 2002 Mid-Cycle Outage by $403,000.

              9. On or before March 31, 2005, CVPS shall file tariffs in conformance with the above findings and conclusions.

              10. If CVPS receives full or partial reimbursement for additional costs from Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc., under the Ratepayer Protection Plan approved in Docket 6812, the Company shall book the amount received as a regulatory liability for return to ratepayers in its next rate proceeding.

              11. If the decommissioning costs for Yankee Atomic, Connecticut Yankee, or Maine Yankee increase from levels now projected for 2006 and subsequent years, CVPS shall notify the Board.

              12. Beginning April 1, 2006, CVPS shall book and defer the difference between the decommissioning costs for Yankee Atomic, Connecticut Yankee, and Maine Yankee for Rate Year 2 on which we set rates and the actual decommissioning cost payments. CVPS shall amortize the balance in this account in its next rate case.

              13. CVPS shall follow the recording and reporting requirements of FERC Order 631 for Vermont jurisdictional ratemaking purposes. CVPS shall track and report its prior and future net salvage collections in a separate subsidiary account. CVPS shall show this separate account in future cost-of-service filings.

              14. CVPS shall conduct a new depreciation study, and file it with the Board and the DPS when it is completed, which shall be no later than December 31, 2006.

              15. CVPS shall spend $6,284,444 for tree trimming expenses in Rate Year 1, and $6,466,224 in Rate Year 2 and in each subsequent year that the rates we approve in this Order are in effect. CVPS shall spend $304,000 for pole treatment expenses in Rate Year 1 and $523,000 in Rate Year 2 and in each subsequent year that the rates we approve in this Order are in effect. If CVPS spends less than these amounts for tree trimming and pole treatment in a particular year, CVPS shall carry forward the unspent amounts to future years. If CVPS spends more than these amounts in a particular year, CVPS may carry forward the extra expenditures as a credit to future years.

              16. In CVPS's annual report required by PSB Rule 4.903B, CVPS shall include the amounts spent on tree trimming and pole treatment, the amounts to be carried forward into the subsequent year, and a comparison of the amounts actually spent to the amounts allowed in rates.

              17. The Customer Service Agreement between CVPS and the DPS that was admitted into evidence as exh. DPS-CVPS-Joint-1 is approved. Within 60 days of today's Order, CVPS and the DPS shall file a report with the Board regarding the progress of their negotiations pursuant to the Customer Service Agreement.

              18. CVPS shall file a new rate design, supported by a fully allocated cost-of-service study, within 90 days of this Order.

Dated at Montpelier, Vermont, this    29^th    day of     March    , 2005.

	s/ Michael H. Dworkin                        s/ David C. Coen                                  s/John D. Burke	) )        PUBLIC SERVICE ) )                  BOARD ) )             OF VERMONT )
OFFICE OF THE CLERK FILED: March 29, 2005 ATTEST:     s/ Susan M. Hudson                                                           Clerk of the Board               Notice to Readers: This decision is subject to revision of technical errors. Readers are requested to notify the Clerk of the Board (by e-mail, telephone, or in writing) of any apparent errors, in order that any necessary corrections may be made. (E-mail address: Clerk@psb.state.vt.us)               Appeal of this decision to the Supreme Court of Vermont must be filed with the Clerk of the Board within thirty days. Appeal will not stay the effect of this Order, absent further Order by this Board or appropriate action by the Supreme Court of Vermont. Motions for reconsideration or stay, if any, must be filed with the Clerk of the Board within ten days of the date of this decision and order.

1. The two periods overlap by six days. Thus, the rates that we review for the first period, although set on a full-year basis, will be displaced on April 1, 2005.
2. In this Order, we refer to the twelve months commencing April 1, 2004, as Rate Year 1 and the second twelve-month period as Rate Year 2. We will require CVPS to calculate the precise rate changes based upon the rulings in this Order and submit a compliance filing showing the results.
3. Docket 6545, Order of 6/13/02 at 13.
4. Docket 6545, Order of 6/13/02 at 135-136.
5. During the course of this proceeding, CVPS has reduced the amount of the rate increase that it seeks, so that the request is now for an increase of 2.9 percent. See CVPS Reply Brief at 14.
6. CVPS Brief at 3.
7. We issued our final order in the last fully litigated cases, Dockets 5701/5724, on October 31, 1994. Since that time, CVPS has had other rate increase requests, which were either settled or closed. Tr. 1/11/05 at 86 (Frankiewicz). See, e.g., Dockets 6120/6460, Order of 6/26/01; Dockets 6018/6120, Order of 3/2/01; Docket 5863, Order of 4/30/96.
8. Tariff Filing of Central Vermont Public Service Corporation, Docket 5132, Order of 7/31/87 at 31-35.
9. The agreement between CVPS and the DPS regarding power cost issues is addressed in Section VI.A, below.
10. CVPS's deferral of $3.8 million in 2004 earnings is described on page 108, below.
11. The DPS's revised recommendation on incentive compensation is discussed in Section VI.E.2, below.
12. The DPS's recommendation regarding plant costs is discussed in Section V.A, below.
13. Under Vermont law, our decision must be based upon the evidence presented by formal parties during the evidentiary hearings. However, Title 30 also provides for public (non-evidentiary) hearings; public comments play an important role by raising new issues or offering perspectives that we should consider.
14. Tr. 9/14/05 at 12-13 (French).
15. Dockets 6120/6460, Order of 6/26/05 at 4-5.
16. Dockets 6120/6460, Order of 6/26/05 at 3.
17. Gibson reb. pf. 11/19/04 at 5.
18. Schultz sup. pf. at 4.
19. Account 426 is composed of expenses that are not to be included in a cost-of-service filing. Tr. 1/12/05 at 17 (Gibson).
20. However, in a few specific instances, as noted in the discussion below, we find the DPS's methodology to be different from the cost-of-service methodology that we typically apply when setting rates. We have not accepted those specific elements in the DPS's methodology.
21. These decisions increase CVPS's expenses in 2001, 2002, and 2003, and decrease CVPS's deferral accounts.
22. The DPS's proposal does not result in unjust and unreasonable rates that would deny CVPS a reasonable opportunity to recover its allowed return, in violation of 30 V.S.A. Section 218, as CVPS contends. Rather, it provides CVPS a reasonable opportunity to recover its allowed return on investments that serve ratepayers.
23. See, findings 11 and 12, above. CVPS argues that its rates are subject to a presumption of reasonableness, and that the DPS has not provided evidence or a compelling basis to overcome this presumption with respect to the implementation of the earnings cap. We disagree; the DPS has shown that CVPS's methodology would reduce overearnings by requiring ratepayers to pay a return on items that do not provide service to them. That would be unreasonable.
    
    In addition, the DPS's proposed calculation methodology would not cause CVPS to write off $9 million twice, as CVPS asserts. Rather, the DPS's proposed methodology would ensure that ratepayers are not required to pay a return on the single $9 million writeoff that CVPS agreed to make.
24. Adoption of the DPS's recommendation would not deny CVPS benefits it received under the 2001 MOU, as CVPS argues. The Company still has the opportunity to earn an 11 percent return on investments that serve ratepayers, and CVPS is in a financially stronger and more stable position today than it was when the 2001 MOU was signed. See, findings 283 and 292, below, for more information regarding CVPS's improved financial situation.
25. Tr. 1/12/05 at 24 (Gibson).
26. CVPS Reply Brief at 141-142.
27. CVPS Reply Brief at 141.
28. CVPS was subject to an earnings cap in 1993 as the result of a settlement agreement that it entered into with the DPS in Docket 5651. The earnings cap provision from that settlement agreement stated:
    
    2(c). Central Vermont agrees to an effective Return on Equity ("ROE") applicable to its Vermont retail business to 12.0% and to credit to accrued [Demand-Side Management] costs any and all amounts earned in excess of that 12.0% ROE during 1993.
    
    Exh. CVPS-43 at 2.
29. The sole difference is that the last time, CVPS included its CV Realty subsidiary in its calculation while in the instant dockets, the same subsidiary is excluded. Exh. CVPS-44 at 5-6 (Henkes pf. 5/27/94, pages numbered 33-34). CV Realty is CVPS's smallest subsidiary, with a 13-month average common equity investment of $283,869, and net income of $2,938 in 2003. Exh. CVPS-JHG-18 at 4.
30. Exh. CVPS-48 at 5 (Henkes sur. pf. 8/5/94, page numbered 19).
31. Dockets 5701/5724, Order of 10/31/94 at 91.
32. In fact, the Board expressly held the issue open by stating that it would not make the DPS's proposed adjustment "at this time." Dockets 5701/5724, Order of 10/31/94 at 91.
33. As noted below, the Board uses the terms allowed return on equity and allowed return on common equity interchangeably.
34. CVPS cites Petition of Green Mountain Power Corporation re Increased Rates, 131 Vt. 284 (1973) in support of its position, arguing that this case shows that the Vermont Supreme Court distinguishes between "return on equity" and "return on common equity." In this decision, the Vermont Supreme Court refers often to GMP's "return on equity" and the phrase "common equity" is used only in two tables regarding CVPS's capital structure. However, the rate shown for GMP's common equity in the capital structure tables is the same as the rate later referred to by the Court as GMP's "return on equity." See the charts on page 295, and the text on pages 298-300. Thus, while this case is an example of the Vermont Supreme Court using the term "return on equity" in a cost-of-service context, the case provides no indication that the Vermont Supreme Court considers the two terms to be different. On the contrary, it appears to indicate that the terms can be used interchangeably.
35. See, e.g., Docket Nos. 5841/5859, Order of 6/16/97 at 78, 300-306 ("return on common equity" used for setting the rate, "return on equity" used in discussion of a penalty that reduced the previously determined rate); Docket Nos. 5700/5702, Order of 10/5/94 at 78-82 ("return on equity" and "return on common equity" used interchangeably); Docket No. 5532, Order of 4/2/92 at 84 (uses "cost of equity" and "return on common equity" interchangeably); Docket No. 5491, Order of 9/27/91 at 3, 4 (uses both "return on equity" and "return on common equity").
    
    Significantly, in Docket 5651, the earnings cap agreed to by CVPS referred solely to "return on equity." It was this earnings cap that the Board reviewed in Dockets 5701/5724, in which the Board accepted CVPS's overearnings calculation. The Company's present argument that its proposed methodology is integrally linked to the phrase "return on common equity" is inconsistent with that previous ruling.
36. In addition, if there were a distinction between the two terms, it would be significant that Paragraph 30 of the 2001 MOU, which describes the earnings cap, uses "return on equity," not "return on common equity."
37. Tr. 11/4/04 at 95 (Schultz).
38. CVPS argues that because the 2001 MOU was a bottom-line settlement with no approved cost of service or rate base, it is reasonable to conclude that the methodology for calculating overearnings would not require the development of a cost of service and rate base for each year that the earnings cap was in effect. CVPS Reply Brief at 140. We disagree. Many bottom-line settlements approved by the Board do not include approved costs of service and rate bases. The fact that the 2001 MOU followed this general rule does not indicate anything regarding the parties' expectations with respect to the methodology for calculating overearnings, and most certainly does not indicate that the calculation of overearnings should ignore established ratemaking principles.
39. For seven decades, rate-regulated companies that trade public stock have routinely kept separate sets of accounts for SEC, tax, and rate-regulation purposes. Reconciliation of the three should be feasible whenever accuracy must be checked; but, since each set of accounts is kept for a different purpose, it is necessary and proper to distinguish between rate-regulation accounts and reports to the SEC. Indeed, without that distinction, rate review would have no meaning since all results would already be resolved by prior SEC filings. See, e.g., J. Bonbright et al., Principles of Public Utility Rates, (PUR 1988) at 287; and J. Suelflow, Public Utility Accounting: Theory and Application, (MSU Press 1973) at 18-20 and at 40: "a regulatory body cannot be bound in its interpretation of results by a prescribed system of accounts."
40. Tr. 1/13/05 at 17-18 (Schultz).
41. In addition, we note that CVPS and the DPS each pointed out some minor errors in the other party's overearnings calculations. After the errors were pointed out, the opposing party admitted that they should be corrected. Since these minor errors are no longer contested, we do not address them further. We do, however, expect that the overearnings calculations performed by CVPS as part of their required compliance filing will reflect the agreed-upon corrections.
42. Gibson reb. pf. 11/19/04 at 11.
43. Frankiewicz pf. at 18; exh. CJF-1; exh. CJF-5.
44. Exh. DPS-L&A-11 at schedule 1; exh. DPS-L&A-12 at schedule 1. The only adjustment to Other Operating Revenues that the DPS has proposed is related to cable television pole attachment revenue. Exh. DPS-L&A-11 at schedule 20; exh. DPS-L&A-12 at schedule 20.
45. Gibson reb. pf. 11/19/04 at 10.
46. Schultz sup. pf. at 2-3.
47. Schultz sup. pf. at 3.
48. We clarify that our decision should not be interpreted as a ruling on whether the traditional practice regarding transmission revenues is appropriate in a cost-of-service proceeding. That issue has not been raised in these proceedings, and we do not address it. Rather, our decision is limited to the question of whether transmission revenues should be treated differently in an overearnings calculation than in a cost-of-service filing for the purpose of setting rates. We conclude that they should not.
49. Tr. 1/12/05 at 124-125 (Gibson).
50. Letter from Geoffrey Commons, Esq., DPS, to Susan M. Hudson, Clerk, Board, dated February 2, 2005, at 2.
51. CVPS Reply Brief at 236.
52. In re Green Mountain Power Corp., 162 Vt. 378, 387-388 (1994). In this Order, all references to In re GMP are to this decision, unless otherwise specified.
53. We note, however, that 30 V.S.A. Section 227(b) provides a specific exception to the Vermont Supreme Court's prohibition against retroactive ratemaking that is relevant to Docket 6946. Pursuant to 30 V.S.A. Section 227(b), when the Board opens an investigation into a utility company's rates, and issues its decision within seven months, the decision is retroactive to the day the Board opened the investigation. In Docket 6946, CVPS waived the seven-month statutory deadline, and agreed that as long as the Board issued its decision by March 29, 2005, the decision would still be retroactive to the day the Board opened the investigation.
54. CVPS asserts that if the MOU is a contract, there is no ambiguity in its wording. CVPS further argues that if there is ambiguity, then the rule of uniform practical construction supports CVPS because the DPS did not object to CVPS's performance of the agreement. We explain later in this section of our Order why we do not find CVPS's arguments regarding the timing of the DPS's challenge to be persuasive. That same rationale applies here.
55. CVPS Brief at 85.
56. CVPS Reply Brief at 145-146.
57. CVPS Reply Brief at 146-147.
58. Since we are not modifying the 2001 MOU or our order approving it, CVPS's arguments regarding In re Burlington Electric Department, 151 Vt. 543 (1989), do not apply. (That case involved a modification to a prior Board order without proper notice and hearing.)
59. In re Maine Public Advocate, supra at 183.
60. CVPS also challenges the timing of the DPS's proposal within the current case. The Company asserts that adoption of the DPS's proposal would be unfair because it wasn't made clear until three days before rebuttal hearings. We find that this contention is not supported by the record in these proceedings. While it is true that the DPS's last testimony on its recommended calculation methodology was filed three days before rebuttal hearings, the DPS first challenged CVPS's calculation methodology and described its proposed alternative in its direct testimony that was filed on October 1, 2004. In addition, as the DPS points out, its proposed methodology is consistent with the policy that the DPS recommended in Dockets 5701/5724, nearly 10 years ago.
61. CVPS Reply Brief at 130, quoting Paragraph 30 of the 2001 MOU.
62. CVPS Reply Brief at 148.
63. CVPS Reply Brief at 150-151.
64. CVPS Brief at 85. CVPS also argues that by the time CVPS filed its request for an accounting order related to 2002 overearnings, the Board could no longer require CVPS to recalculate its 2001 overearnings because CVPS's calculation was a "mistake" and such mistakes can't be corrected in a retroactive fashion. CVPS Reply Brief at 146-147.
65. CVPS Brief at 63-64.
66. CVPS Reply Brief at 139.
67. CVPS Reply Brief at 130.
68. Exh. Board-1; tr. 11/2/04 at 83 (Gamble).
69. See, finding 15, above.
70. The instant proceedings are CVPS's first rate proceedings since the accounting order was issued.
71. CVPS Brief at 54.
72. See, finding 4, above.
73. Docket 5983, Order of 6/8/98 at 20.
74. CVPS Brief at 69-72.
75. Docket 6107, Order of 1/23/01 at 121 (order paragraph 6); Docket 6867, Order of 12/22/03 at 43 (order paragraph 8).
76. CVPS Brief at 72.
77. DPS Reply Brief at 11.
78. Of the $209,468 amortized, $58,229 is allocated to Accumulated Deferred Income Tax Liability, and the remainder ($151,239) is allocated to the Income Statement (though not all allocated amounts affect Vermont retail rates). Exh. CVPS JHG-13 at Attachment PSB 1-1B.
79. See Section VI.A for the discussion of this adjustment.
80. Our ruling on the rate treatment of the $835,946 is set forth below in Section VI.A.
81. Our ruling on the rate treatment of the $2,345,547 is below in Section VI.A.
82. The Department corrected exh. DPS-L&A-12 at page 10 of schedule SR8 to reflect the removal of Rate Year 1 amortization of $187,164. Tr. 2/18/05 at 77-78 (Schultz).
83. See Section V.C, below, for the explanation of the zero balance in Distributed Utility Planning Demand-Side Management deferral account.
84. As explained in Section III, below, we require CVPS to recalculate its overearnings in 2001, 2002, and 2003, as part of its compliance filing in these proceedings. The balance in the 6460 Earnings Cap 02 & 03 regulatory liability account, the amortization amount, and the rate base effects will be determined by this recalculation.
85. See Section V.C, below, for the explanation of the zero balance in Distributed Utility Planning Demand-Side Management deferral account.
86. As explained in Section III, below, we require CVPS to recalculate its overearnings in 2001, 2002, and 2003, as part of its compliance filing in these proceedings. The balance in the 6460 Earnings Cap 02 & 03 regulatory liability account, the amortization amount, and the rate base effects will be determined by this recalculation.
87. In fact, we have been concerned with CVPS's increasing deferrals for some time. As CVPS noted: "The Board's had a concern actually all the way back to 5701/5724. It's the same concern of the high level of deferred debits, and reg assets . . . ." Tr. 1/11/05 at 117 (Frankiewicz).
88. Docket 6866, Order of 1/27/04 at 15-16.
89. Docket 6866, Order of 1/27/04 at 3.
90. The deferral accounts are not solely regulatory assets, which reflect costs deferred by CVPS for future recovery from ratepayers. They also include regulatory liabilities, i.e., amounts that CVPS must return to ratepayers.
91. CVPS Brief at 228.
92. Id.
93. As an example of an account deferred pursuant to GAAP, CVPS is required to pay the decommissioning costs for several nuclear plants of which it is a part owner. The rates for these payments are set by FERC, and will run through 2010. GAAP requires that CVPS record the total of this future stream of payments as a regulatory liability.
94. The accounting orders contain explicit provisions stating that they no have bearing on ratemaking treatment, including the amount (if any) that the Company can subsequently recover in rates.
95. These include recovery of Distributed Utility Planning Demand-Side Management and Distributed Utility Planning Account Correcting for Efficiency deferrals, the amount of the Vermont Yankee 2002 Mid-Cycle Outage deferral, and whether to expense or amortize incremental decommissioning costs for Connecticut Yankee and Yankee Atomic and for the VEPPI Cost Mitigation. See Sections V.C, V.D, and VI.A.
96. Frankiewicz reb. pf. at 5-7.
97. Gibson reb. pf. 11/15/04 at 12. It is not readily apparent how including an expense item that the Company did not intend to recognize is "more accurate" than simply reflecting the Company's proposal to start amortization in Rate Year 2.
98. Schultz and DeRonne reb. pf. at 23.
99. Our conclusion might have been different if the evidence had shown that CVPS had a revenue deficiency in Rate Year 1. If that had been the case, requiring CVPS to begin amortizing its deferral accounts in Rate Year 1 would have increased the revenue deficiency and might have affected the Company's ability to earn its allowed rate of return.
100. CVPS acknowledged this fact during the hearings. Tr. 1/12/05 at 29 (Gibson).
101. Frankiewicz reb. pf. at 8.
102. See also Federal Power Commission v. Hope Natural Gas, 320 U.S. 591 (1944).
103. Tr. 1/11/05 at 69 (Frankiewicz).
104. Except for Distributed Utility Planning Account Correcting for Efficiency (2 years) and Distributed Utility Planning Demand-Side Management (5 years). Gibson pf. at 37.
105. One exception is demand-side management expenses, for which the Board directed CVPS to track the amortization in a similar manner to what the Department recommends. See Section V.C for further explanation.
106. It is important to recognize that these amortizations are, themselves, the result of special accounting treatment that permits present recovery of past expenses. Reversing the amortization when the underlying regulatory asset or liability is fully amortized not only is consistent with the rationale behind that accounting treatment -- to reflect an expense or income over an extended, but not indefinite time period -- but also promotes more accurate recognition of such expenses and income.
107. See 30 V.S.A. Section 221.
108. Docket 5983, Order of 6/8/98, at 20.
109. Gibson reb. pf. 11/15/04 at 13-14.
110. Page reb. pf. at 8-9.
111. Taken to its logical extreme, CVPS's argument would justify special accounting treatment for all outages at power plants, except those that are recurring.
112. ". . . as soon as a bill comes in, and we pay it, absent an accounting order, it would have to be expensed. It comes out of both columns, regulatory liability and the regulatory asset, and if it's so extraordinary, you know, it's not deemed to be in rates, then it's not recovered. If it's expensed. That's why we have to have the accounting order. Certainly in the absence of a fuel and purchase power clause here in Vermont. " Tr. 1/11/05 at 124-126 (Frankiewicz) (emphasis added).
113. Page reb. pf. at 9; tr. 11/2/04 at 169-170 (Gibson).
114. Technically speaking, a utility's cost of capital equals the weighted-average cost of capital. See Section VII for more detail.
115. A utility's income taxes would also be reduced.
116. CVPS's proposed plant additions are shown on lines 2 through 9 of exh. CVPS-CJF-7.
117. This section of our Order refers to gross plant investment. In order to determine a utility's rate base, an additional step is required -- the gross plant investment must be reduced by the amount of accumulated depreciation on that plant. Also, reductions may be required if a plant investment was not prudently made or is not "used and useful" for the delivery of service.
118. CVPS-CJF-3.
119. DPS Brief at 4, 14.
120. In re GMP, supra, at 381.
121. G. White reb. pf. at 7.
122. See, finding 94, above.
123. See, findings 86-90, 95, 98-101, 105, 108, 111-112, and 117-118.
124. Dockets 5701/5724, Order of 10/31/94 at 37.
125. When plant is retired, the asset is removed from rate base and accumulated depreciation on that plant is removed from the utility's total accumulated depreciation.
126. Frankiewicz pf. at 23.
127. Schultz and DeRonne pf. at 21-22.
128. In Re GMP, supra.
129. In re GMP, supra, at 383.
130. CVPS Brief at 153.
131. CVPS Brief at 135.
132. There were minor modifications to 30 V.S.A. Section 225(a) in 1999; however, the anti-updating provisions of that section were not affected.
133. "A general trend is no substitute for evidence, especially when, as here, the utility seeking the rate increase has had an ample opportunity to introduce evidence as to its adjusted test year additions to plant, and did not do so." In re GMP, supra, at 384.
134. Tr. 1/10/05 at 193-196 (Chairman Dworkin, for the Board).
135. Docket 6596 Tariff filing of Citizens Communications Company, d/b/a Citizens Energy Services, requesting a rate increase in the amount of 40.02%, to take effect December 15, 2001, Order of July 15, 2002 (referred to herein as the "Docket 6596 Order"); Docket 6914 Investigation into the Existing Rates of Shoreham Telephone Company, Inc., Order of November 4, 2004 (referred to herein as the "Docket 6914 Order"). The DPS has used a similar methodology for years. Tr. 1/13/05 at 28-30 (Schultz). As most rate cases were settled, the Board did not delineate it in detail until 2002.
136. Schultz and DeRonne sur. pf. at 19.
137. The DPS's adjustments are to the adjusted test-year accumulated depreciation balances shown in CVPS's original cost-of-service filings in these proceedings. In other words, the DPS used its methodology to calculate the appropriate interim-year and rate-year adjustments to test-year accumulated depreciation balances to arrive at the rate-year average accumulated depreciation balance, then proposed an adjustment equal to the difference between that rate-year average accumulated depreciation balance, and the rate-year average accumulated depreciation balance shown in CVPS's original cost-of-service filings.
138. We acknowledge that this methodology is different than the one we approved 10 years ago in Dockets 5701/5724. The intent of the two methodologies was the same -- to implement the Vermont Supreme Court's decision in In re GMP, supra. However, after considering the evidence in more recent cases and the instant proceedings, we conclude that the DPS's methodology more closely adheres to the Vermont Supreme Court's decision.
139. Consistent with both Vermont Supreme Court and United States Supreme Court precedents, our overall revenue determination in this proceeding is based on a functional end-result test. See, Federal Power Commission v. Hope Natural Gas, 320 U.S. 591 (1944); Duquesne Light Co. v. Barasch, 488 U.S. 299 (1989); "It is not the theory, but the impact of the rate order which counts." Id. at 314. See also Verizon v. FCC, 535 U.S. 467, 526, 122 S. Ct. 1646, 1680 (2002): "we held, as usual that a rate setting methodology would normally be judged only by the overall impact of the rate orders."
140. CVPS Brief at 136-137.
141. Docket 5132, Order of 7/31/87 at 31. "[t]here is thus a very definite place for case-by-case evolution of statutory standards." Docket 5132, Order of 7/31/87 at 33, quoting SEC v. Chenery Corp., (Chenery II), 332 U.S. 194, 203 (1947).
142. Docket 5132, Order of 7/31/87 at 31, quoting Justice Cardozo in THE NATURE OF THE JUDICIAL PROCESS (1921) at 151, quoting, with approbation, Day v. Connecticut Co., 89 Conn. 74, 99.
143. We are concerned that the Company's Chief Financial Officer believes that the Board should ignore previous ratemaking orders issued in litigated cases involving companies other than CVPS. See tr. 1/11/05 at 152-153 (Gibson). This contrasts sharply with CVPS's argument that it is entitled to any favorable aspects of our treatment of GMP.
     
     While most settlement agreements involving CVPS and GMP expressly state that they are not precedential, orders in litigated cases are precedential for all parties within a jurisdiction, not just for those who were parties to the individual cases. This is the common regulatory standard throughout our nation.
144. Docket No. 5132, Order of 7/31/87 at 33-34.
145. CVPS Brief at 146.
146. CVPS argues that the Docket 6914 Order's description of the steps taken to calculate the adjustments was circular (for example, adding interim depreciation expense to average interim year accumulated depreciation).
147. CVPS Brief at 154.
148. Docket 5983, Order of 2/27/98 at 18-19 (footnote omitted).
149. Docket 5983, Order of 2/27/98 at 19.
150. CVPS also asserts that it would be retroactive ratemaking to apply the DPS's proposed methodology to CVPS in Rate Year 1 because the Board's decision in Docket 6914 was not issued until well after the filing of the cost-of-service studies in these proceedings. We conclude that this argument is incorrect. The timing of the Board's decision in Docket 6914 is irrelevant for the purpose of deciding the issue in these proceedings. As discussed above, well-established administrative law holds that policies may, and sometimes should, be changed at the same time they are applied. Thus, the Board could, if it found the evidence in these proceedings supported it, apply a new accumulated depreciation adjustment policy. The key question under Vermont law is whether that methodology is reasonably directed towards our goal of establishing just and reasonable rates. In re Green Mountain Power Corp., 142 Vt. 373, 380 (1983).
151. 30 V.S.A. Section 227(b) states, in relevant part:
     
     If the board does make its determination within such seven months then its final order shall be retroactive to the day that the proceedings were instituted and such final order shall contain a directive that the company, other than a common carrier of passengers by motor vehicle, shall repay to the persons from whom collected between the time the proceedings were instituted and the final order all sums which the board determines are in excess of the rates ultimately found to be just and reasonable.
     
     As described in more detail in the Procedural History, CVPS committed to extend the statutory seven-month deadline as part of its scheduling proposal, which the Board accepted.
152. CVPS Brief at 136-137.
153. CVPS Brief at 138.
154. As explained in Section VI.D, below, we also require CVPS to modify the adjustment to depreciation expense to reflect this correction.
155. Dockets 5701/5724, Order of 1/11/95 at 2, 3 (italics in original). "Conservation and Load Management" is an older term that is synonymous with Demand-Side Management.
156. CVPS Reply Brief at 96.
157. Tr. 1/12/05 at 162 (Frankiewicz).
158. CVPS Reply Brief at 96-97.
159. This decision is consistent with the Vermont Supreme Court's decision in In re GMP, supra, which prohibited the Board from reducing GMP's rate base to credit ratepayers for the amount of amortization expenses that exceeded the projected amounts for demand-side management expense in the adjusted test year. The key fact is that in the case decided by the Vermont Supreme Court, the Board had not stated that demand-side management expenses would be subject to special accounting treatment at the time the rates including those expenses were set. This is not the case with respect to CVPS. On the contrary, in Dockets 5701/5724, the Board granted the Company's request to establish a special accounting treatment for demand-side management expenses. Our decision today simply requires CVPS to implement the special accounting treatment that it, itself, had requested. If In re GMP, supra, were to prohibit such use of deferral accounting, this could have significant adverse affects on Vermont ut ilities, including CVPS (especially in light of CVPS's substantial deferred account balances discussed in Section IV, above).
160. Distributed Utility Planning ACE is designed to enable a utility to collect its net lost revenues resulting from the installation of energy efficiency measures, pursuant to Distributed Utility Planning, in its service territory between rate cases.
161. According to CVPS, the value of the deferral account as of March 31, 2004, excluding carrying costs is $124,623. Exh. CVPS-BWB-1 shows the amount of Distributed Utility Planning ACE that is accumulated in each month from January 2000 through December 31, 2005. The figure of $124,623 is arrived at by summing the values for each month through March 31, 2004.
162. According to the DPS, the ACE deferral balance, excluding carrying costs, as of December 31, 2005, (a date that is in the middle of Rate Year 2) is $167,269; according to CVPS, that figure is $172,914. Exh. DPS-CEW-2. Exh. CVPS-BWB-1.
163. See finding 144, above.
164. Exh. DPS-L&A-11 at page 3 of schedule 8.
165. Tr. 11/4/04 at 83 (DeRonne); exh. DPS-L&A-11 at page 3 of schedule 8.
166. Tr. 11/1/04 at 182-184 (Welch).
167. Gibson reb. pf. 11/15/04 at 18.
168. Tr. 11/4/04 at 86-87 (DeRonne).
169. $136,791 - $109,373. The $136,791 was the 13-month average deferral account balance included in CVPS's original cost-of-service filing for Rate Year 1 in these dockets, not the deferral account balance resulting from the revised calculations CVPS submitted in its rebuttal testimony.
170. $164,549 - $36,458. The $164,549 was the 13-month average deferral account balance included in CVPS's original cost-of-service filing for Rate Year 2 in these dockets, not the deferral account balance resulting from the revised calculations CVPS submitted in its rebuttal testimony.
171. The forced outage rate calculates the typical period in which a generating facility does not generate power or generates only at reduced power. During these periods, the power cost calculations assume the reduced power output and/or different mix of resource use and the potential need to purchase replacment power to service customer load. Planned outages, such as the Vermont Yankee refueling outage, are generally excluded from the calculation.
172. Connecticut Yankee and Yankee Atomic.
173. As discussed below, the parties ask the Board to decide whether these amounts should be expensed in Rate Year 1 or deferred and then amortized in Rate Year 2 (or some combination of the two). Exh. DPS-CVPS-Joint-2; exh. CVPS-CJF-15. See also, findings 160-162.
174. If the resale value of the power is below its cost, ratepayers fare less well and end up paying extra costs for power that is not needed to serve them. Even so, the net cost to retail customers would be less than if purchased power costs were considered and power sales revenues were not.
175. Exh. DPS-CVPS-Joint-2.
176. The parties have agreed that the period in which Vermont Yankee was not generating power due to the Mid-Cycle Outage should not be considered in calculating the forced outage rate on a going-forward basis. The reason for this agreement is that CVPS is being compensated already for the outage through the deferral of incremental costs which CVPS will begin amortizing as part of these proceedings.
177. DPS Brief at 26-27.
178. CVPS Brief at 109.
179. Page reb. pf. at 24.
180. The Department agreed with the $403,000 figure. Lamont reb. pf. at 5.
181. Exh. DPS-CVPS-Joint-2 at 1.
182. See finding 4, above.
183. See discussion on page 55, above.
184. As we discuss above, such use of accounting orders is inappropriate. Power plant outages generally are not extraordinary; in fact, the reason we include a forced outage rate is because we expect power plants to be out-of-service for specific reasons that cannot be anticipated.
185. Gibson pf. at 40.
186. In its Reply Brief, CVPS suggests that these costs are not reflected in the rates now in effect for Rate Year 1 and that they are not reflected on the Company's books. CVPS Reply Brief at 114. This is true, but misses the point. CVPS did include the 2004 Fire Outage costs as expenses in its Rate Year 1 cost of service.
187. Gibson pf. at 41; Page pf. at 13.
188. Exh. DPS-CVPS-Joint 2 at 1; exh CVPS-CJF-15 at 1.
189. Tr. 2/18/05 at 77 (Schultz).
190. Tr. 2/18/05 at 39 (Frankiewicz).
191. CVPS's argument would have had more validity if, in fact, we had found a revenue deficiency in Rate Year 1.
192. Frankiewicz reb. pf. at 10-11.
193. The Board has opened Docket 6812-A to consider CVPS's petition.
194. DPS Brief at 46.
195. Schultz and DeRonne pf. at 38-39.
196. CVPS Reply Brief at 155.
197. CVPS Reply Brief at 158.
198. The effect of the levelization is $718,826 in Rate Year 1 and $1,520,678 in Rate Year 2. Exh. DPS-L&A-11 at schedule 10.
199. Tr. 2/18/05 at 53 (Frankiewicz).
200. It is our assumption that this will result in a regulatory liability, i.e., the costs in rates will exceed decommissioning costs. This is consistent with the current FERC rate schedules under which CVPS pays these costs. If the Yankee decommissioning costs increase from levels now projected for 2006 and beyond, we require CVPS to notify the Board.
201. DPS Brief at 46.
202. Tr. 2/18/05 at 50 (Frankiewicz).
203. Tr. 2/18/05 at 50 (Frankiewicz). Mr. Frankiewicz suggested that there may be a minor working capital difference.
204. CVPS Reply Brief at 155, citing exh. CJF-14 and tr. 2/18/05 at 76 (Schultz).
205. CVPS states that the present value of these expected credits is $6.2 million. Deehan reb. pf. at 14.
206. CVPS reflects this payment as a $1,195,920 credit to power costs in each year. Exhs. CVPS-CAW-A2 and CVPS-CAW-B2. This credit does not include return of the $6.6 million gain, which CVPS proposed to pass on to shareholders.
207. In its cost-of-service filings, CVPS did not break out the payroll tax between the administrative and general expense category and other categories. On exh. CVPS-55 (which shows the test year figures analogous to the Rate Year 1 and 2 amounts), CVPS showed that 62.5 percent of its payroll expense under the service contract applied to administrative and general costs. We have allocated the payroll expenses in each rate year using the same percentages. Thus, in rate year 1, we have added 62.5 percent of the $78,000 in taxes -- $48,750 -- to the administrative and general category to reflect the tax effects of the allocation.
208. Tr. 11/2/04 at 144-145 (Gibson); tr. 11/3/04 at 85-86 (Gibson).
209. Schultz and DeRonne reb. pf. at 28.
210. Deehan reb. pf. at 9.
211. Deehan reb. pf. at 9; Schultz and DeRonne pf. at 59.
212. Schultz and DeRonne pf. at 59; Deehan reb. pf. at 9.
213. Deehan reb. pf. at 10.
214. Gibson pf. at 7.
215. The $14 million stranded cost estimate could increase over time if market prices fall from current levels, thus reducing CVPS's revenues from selling the excess power. Tr. 1/12/05 at 47-49 (Gibson).
216. Schultz and DeRonne pf. at 64-65.
217. Gibson pf. at 19.
218. CVPS included a reduction of $1,195,920 in each of Rate Years 1 and 2 to incorporate this amortization. Exhs. CVPS-CAW-A2 and CVPS-CAW-B2.
219. Deehan reb. pf. at 14.
220. Deehan reb. pf. at 14.
221. Schultz and DeRonne reb. pf. at 66.
222. CVPS Reply Brief at 191.
223. CVPS Reply Brief at 187-188.
224. Tr. 11/2/04 at 138-139 (Gibson). As we explain above, in rate proceedings, we traditionally do not bar recovery of power purchases and entitlements in excess of what is needed to serve CVPS's load. Instead, we attribute resale revenue to any power in excess of CVPS's actual needs. To the extent that the price of the power CVPS acquired to serve CVEC exceeded the resale value, Vermont ratepayers may have paid the difference. We have also generally allowed such treatment when wholesale transactions are terminated.
225. Deehan reb. pf. at 9-10.
226. This change is attributable to two factors. First, the market price for power has increased, allowing CVPS to resell the power for more and reducing the stranded cost loss. Second, CVPS was able to sell the power at cost for the intervening period, so that the CVEC customers paid a share of the costs.
227. Exh. CVPS-55; exhs. CVPS-CJF-2 and CVPS-CJF-6.
228. See finding 187.
229. In fact, the $6.6 million exceeds the deferred overearnings.
230. Schultz and DeRonne pf. at 57-58.
231. DPS Brief at 60.
232. CVPS Reply Brief at 182-183.
233. If a company does not have a legal obligation to retire or decommission a plant asset, the cost of removing that plant asset is considered a non-legal retirement obligation (referred to herein as a "non-legal ARO").
234. R. White reb. pf. at 9; DPS Brief at 82.
235. The DPS also states that CVPS's depreciation expense should be reduced because several of the average lives on which the depreciation rates are based are too short. However, the DPS does not propose alternative lives in these proceedings, stating instead that it expects CVPS's next depreciation study to address this issue. Majoros pf. at 6.
236. Majoros pf. at 6.
237. Majoros pf. at 36-37.
238. DPS Brief at 77.
239. CVPS Reply Brief at 216.
240. R. White reb. pf. at 3-4, 14-15.
241. CVPS Reply Brief at 216.
242. Tr. 1/10/05 at 75-76 (R. White); tr. 1/12/05 at 146 (Gibson).
243. We believe this issue may also have implications for CVPS's next depreciation study. In addition to changing depreciation rates, depreciation studies often lead to "rebalancing" the depreciation reserve among different plant accounts. We would expect that any future rebalancing would not shift funds from net salvage to depreciation or vice versa. Collections for past expenses should be kept separate from collections for estimated future expenses. This expectation is consistent with statements made by CVPS's chief financial officer during cross-examination. Tr. 1/12/05 at 114-115 (Gibson).
244. During cross-examination, the DPS's own witness admitted that under the DPS's recommendation, ratepayers at the time an asset is retired would pay all the net salvage costs for that asset. Tr. 1/10/05 at 140 (Majoros).
245. We are expressly not ruling on whether CVPS has overcollected net salvage during the period that its current depreciation rates have been in effect. There is insufficient evidence in the record to decide this issue. We expect, however, that the level of net salvage collections will be reviewed in CVPS's next depreciation study, and that net salvage rates will be adjusted downward at that time if the data shows that to be appropriate.
246. The DPS asserts that SFAS 143 and FERC Order 631 require the separation or unbundling of non-legal cost of removal allowances from depreciation rates, although the DPS admits that SFAS 143 provides an exception for regulated utilities, provided certain conditions are met. Majoros pf. at 24-25, 31.
247. Exh. CVPS-40 at 7, 42; FERC Order 631 at Paragraphs 37-39.
248. Schultz and DeRonne pf. at 49.
249. DPS Brief at 54.
250. Gamble reb. pf. at 34-35.
251. CVPS uses an average of 11 voluntary terminations per year, and the average time to fill most positions of 4 months to calculate its vacancy rate of 3.7. Gamble reb. pf. at 35.
252. On January 11, 2005, CVPS had only six positions advertised on its website (one of which was for an unregulated subsidiary). We recognize that these six positions do not include all jobs that the Company had posted as of January 11, 2005. However, there is no quantitative evidence in these proceedings regarding the number of jobs that the Company had posted internally as of that date, or of the number of jobs that were recently filled with outside hires who had not yet started work.
253. The record does not indicate how many of the approximately 16 new positions that the Company filled in calendar year 2004 were related to succession planning.
254. The italics indicate the errors. As can be seen by comparing finding 232 with finding 226 which indicates the correct weights for the three measures, the percentage weights for "utility earnings per share" and "whether CVPS meets its service quality standards" were reversed.
255. DPS Brief at 52.
256. Schultz and DeRonne sur. pf. at 41-42.
257. CVPS Reply Brief at 169.
258. CVPS Reply Brief at 170-172.
259. CVPS Reply Brief at 172-173.
260. CVPS stated that for 2005, the weighting of the Company portion of the EIP has been changed to: (1) 33 1/3 percent utility earnings per share; (2) 33 1/3 percent cash flow; and (3) 33 1/3 percent whether CVPS meets its service quality standards. Substituting these percentages in the calculation performed on page 3 of exh. CVPS-JFG-33 results in an overall weight of between 34 percent and 39 percent for customer-oriented goals. These percentages are still considerably less than half of the EIP's overall weight.
261. Schultz and DeRonne sur. pf. at 38.
262. The only other basis upon which we could estimate the EIP's expected costs in the rate years would be to use past EIP payout levels as a guide for future expected payout levels. According to CVPS, the EIP's actual payout for 2002 performance was 68 percent of the maximum possible payout for regular employees, and 69 percent of the maximum possible payout for key contributors. The EIP's actual payout for 2003 performance was 70 percent of the maximum possible payout for regular employees, and 71 percent of the maximum possible payout for key contributors. Gamble pf. at 32-33.
     
     Even though the payout levels for these two years were both near 70 percent of the maximum possible, we do not find it reasonable to assume that this level will continue. If the Company is correct that the EIP is designed so there is only a 50 percent chance of meeting the target payout, that is true for each year that the EIP is in effect; past payout levels would not be any indication of future payout levels. (Similarly, if one flips a coin four times and the first three times it comes up heads, the probability that it will come up heads again is still 50 percent. The events are independent, and past results do not affect the probability of future events.)
263. Confidential exh. CVPS-JFG-29 was filed with Ms. Gamble's supplemental testimony describing the results of CVPS's recent negotiations with its employee union. The new union contract covers the period January 1, 2005-December 31, 2008. Gamble sup. pf. at 3.
264. "Below-the-line" is a regulatory term of art that is used to refer to items that are charged (or credited) to shareholders. "Above-the-line" is the term of art used to refer to items that are charged (or credited) to ratepayers. Literally, "the line" refers to the line on the utility's income statement (Net Utility Operating Income) that is the dividing point between items that are charged (or credited) to ratepayers versus shareholders.
265. As the Board stated in Dockets 5841/5859:
     
     We require utilities operating in this state to keep clear and detailed records that provide justification for corporate costs that are allocated to an affiliate. . . . It is thus critical that a company like Citizens, whose corporate structure is characterized by a variety of affiliates and profit centers, be able to fully document and justify transactions among the entities. In view of this structure, it is essential that the Company demonstrate the reasonableness of all charges to Vermont ratepayers. If such expenses cannot be fully substantiated and documented, we would have no choice but to exclude them from rates in the future.
     
     Dockets 5841/5859, Order of 6/16/97 at 231 (emphasis in original).
266. Schultz and DeRonne pf. at 51.
267. Gibson reb. pf. at 29.
268. Gibson reb. pf. at 28; tr. 11/3/04 at 29-30 (Gibson).
269. This adjustment results in an allocation factor of 67.365 percent -- 0.7485 * 0.9 = 0.67365 or 67.365 percent.
270. It would be inappropriate for a utility's failure to keep accurate records regarding the allocation of its officers' time to result in higher retail rates and increased collections from ratepayers, which could lead to higher earnings per share which, in turn, could result in increased incentive compensation for the utility's management.
271. CVPS Reply Brief at 178.
272. Exh. DPS-L&A-11 at schedule 12; exh. DPS-L&A-12 at schedule 12.
273. The DPS has proposed a $53,332 reduction to payroll tax expense in Rate Year 1, and a $82,150 reduction to payroll tax expense in Rate Year 2. For comparison purposes, multiplying the same payroll adjustment shown on exh. DPS-L&A-11 at schedule 12, by CVPS's proposed effective tax rate results in a $57,274 reduction to payroll tax expense in Rate Year 1, and a $88,222 reduction to payroll tax expense in Rate Year 2.
274. We were surprised to learn of this disagreement for the first time in CVPS's brief. During the direct hearings, Board staff asked the DPS's cost-of-service witness whether the DPS's proposed adjustment to 401(k) expense was the result of a dispute with the methodology the Company used to calculate its proposed adjustment, or whether it was simply the result of the DPS's recommended payroll adjustment. The DPS's witness replied that the DPS's proposed adjustment was just a flow-through of the payroll adjustment. Tr. 11/4/04 at 93 (Schultz).
275. CVPS Reply Brief at 181.
276. We note that the DPS originally stated its recommended effective employer match rate in its direct prefiled testimony. CVPS had the opportunity to present evidence regarding its calculation of its 401(k) expense adjustment and its recommended effective employer match rate in the rebuttal phase of these proceedings, but the Company did not do so.
277. DPS Brief at 58.
278. Exh. DPS-Cross-8 at 1; Gamble reb. pf. at 39-40.
279. See finding 244, above, for a list of the other reasons.
280. Gamble pf. at 47-48.
281. Gamble reb. pf. at 38-39.
282. DPS Brief at 65.
283. Schultz and DeRonne pf. at 69.
284. Deehan reb. pf. at 26.
285. CVPS allocated 74.85 percent of its officers' time to regulated operations and maintenance. We accepted the DPS's 10 percent reduction to that allocation. 0.7485 * 0.9 = 0.67365 or 67.365 percent.
     
     We recognize that the payroll allocation factor does not just separate costs between regulated and unregulated activities. Rather, it separates regulated operations and maintenance activities from regulated capitalized activities and unregulated activities. However, given CVPS's own statements that officers generally do not spend time on capital projects (Gibson reb. pf. at 29), we do not believe this significantly distorts the allocation factor.
286. Exh. DPS-L&A-11 at page 1 of schedule SR2.
287. 393,000 - (393,000 * 0.67365) = 128,256
288. Tr. 11/1/04 at 30 (Dickinson).
289. Docket No. 4230, Order of 12/8/78 at 19.
290. The Department's uncontested testimony states that the effect of the cost savings from the video conferencing plant disallowance occurs in Rate Year 2 only. However, the Department's schedules reflect these savings in both Rate Years. See exh. DPS-L&A-6 at schedule SR 22. The Department's Brief also reflects this adjustment in the totals for both years. We assume that the Department's schedules and brief represent its position.
291. CVPS witness Monder testified that the savings were actually $6,630. Monder reb. pf. at 9. However, in its Reply Brief, CVPS accepts the Department's figure of $1,658. CVPS Reply Brief at 206.
292. Anderson reb. pf. at 2.
293. Schultz and DeRonne pf. at 41.
294. DPS Brief at 47-48.
295. Id. at 48.
296. CVPS Brief at 346.
297. CVPS Reply Brief at 165; Anderson reb. pf. at 3-4.
298. Schultz and DeRonne sur. pf. at 47.
299. Tariff filing of Citizens Communications Company, d/b/a Citizens Energy Services, Docket 6596, Order of 7/15/02 at 91-94.
300. Tr. 1/12/05 at 158-159 (Gibson).
301. Anderson pf. at 3.
302. Anderson reb. pf. at 6; Schultz and DeRonne pf. at 61.
303. CVPS Brief at 342; Anderson reb. pf. at 8; Schultz and DeRonne pf. at 61-62.
304. Anderson pf. reb. at 7-9.
305. CVPS Brief at 343.
306. Schultz and DeRonne pf. at 62.
307. Schultz and DeRonne reb. pf. at 48.
308. DPS Brief at 60.
309. Significantly, CVPS does not argue that the adjustment it proposes is known and measurable. Instead, CVPS relies upon the other arguments described above.
310. By contrast, in the hearing on CVPS's request for an accounting order in these dockets, CVPS took the position that the outcome of the instant cases could not be reasonably quantified.
311. In addition, CVPS and the DPS agreed that a $31,000 adjustment to the costs of service for both Rate Years 1 and 2 that was originally proposed by the DPS should not be made. The $31,000 was the amount of a penalty that CVPS paid as a result of the Board's decision in Docket 6758 (Investigation into Fourteen Utilities' Provision of Service to Customers Pursuant to Expired Special Contracts or at Special Rates Without Board Approval). The DPS originally stated that the penalty was inappropriately included in the filed costs of service, but later agreed with CVPS that the penalty was not included. Schultz and DeRonne pf. at 74; Gibson reb. pf. 11/15/04 at 30; Schultz and DeRonne sur. pf. at 49.
312. Liquidity refers to the ability of stockholders to buy and sell shares of a particular company in a timely manner. Woolridge sur. pf. at 3.
313. The index includes changes in stock prices and dividend re-investments for the period from January 1, 1999, to December 31, 2003.
314. Docket 6867, Order of 12/23/03 at 42 (order paragraph 6); Docket 6829, Order of 10/7/2003 at 4.
315. CVPS Reply Brief at 229.
316. In re Allied Power & Light Co., 132 Vt. 354 (1974).
317. Exh. DPS-Cross-19.
318. Exh. DPS-Cross-22 at 24.
319. CVPS Brief at 19.
320. CVPS Brief at 19-20.
321. DPS Brief at 92, 94.
322. DPS Brief at 94.
323. DPS Brief at 94.
324. Tr. 11/4/04 at 249 (Cater).
325. Exh. DPS-Cross-26 at 59.
326. DPS Brief at 91.
327. In connection with the issuance of $75 million first mortgage bonds, CVPS issued a Private Placement Memorandum to generate investor interest and solicit CVPS bonds.
328. Talbot and Roschelle pf. at 7; exh. CVPS-10 (2003 CVPS Proxy Statement at 15).
329. Exh. DPS-45 (Fitch Press Release, December 14, 2004.); exh. CVPS-5 at 56 (2001 CVPS Annual Report); exh. CVPS-7 at 48 (2003 CVPS Annual Report).
330. EBITDA stands for Earnings Before Interest, Taxes, Depreciation and Amortization expenses.
331. Exh. DPS-Cross-22 at 17. We note here that in fairness that the May, 2004 Memorandum predates the submission of the Department's prefiled testimony on October 1, 2004.
332. Tr. 11/4/04 at 225 (Cater).
333. "SERVE" stands for Serving Everyone with Reliability, Value and Excellence. Established in October, 2003, the SERVE plan represents the Company's Service quality and reliability plan. G. White pf. at 3.
334. CVPS Brief at 22.
335. CVPS Brief at 22
336. DPS Brief at 93-94.
337. Cater pf. at 14.
338. Cater pf. at 14-15.
339. Woolridge sur. pf. at 3.
340. Talbot and Roschelle pf. at 13.
341. Talbot and Roschelle pf. at schedule 2a.
342. Woolridge sur. pf. at 3.
343. We note that GMP is also a small-cap stock for which we authorized a return on equity of 10.5 percent in Docket 6867. As stated earlier, our authorization of a 10.5 percent return on equity was based on a different set of facts and circumstances that do not apply to CVPS.
344. These methods were the Discounted Cash Flow, Capital Asset Pricing methodology and historical risk premium methodology.
345. In re FPC v. Hope Natural Case Co., 320 U.S. 591, 602 (1944).
346. See footnote 264 for a definition of "the line."
347. There is no dispute regarding the proposed accounting treatment for CVPS's unregulated affiliates, such as Catamount Resources Corporation. They have been, and continue to be, accounted for below-the-line.
348. See, Nantahala Power & Light Co. v. Thornberg, 476 U.S. 953, 970 (1986).
349. CVPS Brief at 328 and 331.
350. The DPS expressly denies CVPS's assertion that it is recommending that only some of the Company's regulated affiliates be treated above-the-line. Tr. 1/13/05 at 178-180 (Behrns).
351. Behrns pf. at 12.
352. DPS Reply Brief at 26, citing Behrns sur. pf. at 16.
353. DPS Reply Brief at 24.
354. CVPS Initial Brief at 330.
355. Behrns sur. pf. at 16.
356. DPS Reply Brief at 24.
357. DPS Reply Brief at 24.
358. See, 30 V.S.A. Section 209(3); 16 U.S.C. Section 824(a), and Re Central Maine Power Co., 20000WL 347057 (ME.P.U.C. 2000), at 3:
     
     By contrast, FERC does not have authority over the allocation in a retail ratemaking proceeding of gains received by a utility from its investment in a FERC-regulated utility . . . . The allocation of revenues for purposes of retail ratemaking is an area clearly within the jurisdiction of state utility commissions.
359. Pacific Gas, supra, at 1031.
360. Id.
361. Id. at 1032.
362. Mississippi Power & Light, supra, at 372.
363. Pacific Gas, supra, at 1048.
364. Id. at 1048.
365. See footnote 139 and cases cited therein.
366. In fact, CVPS's position in this docket is contrary to CVPS's own testimony two years ago:
     
     Central Vermont will continue to account for its ownership interests and other passive investments held by Custom [Investment Corporation][VYNPC was at issue in Docket 6835], dividends, interest and gains received therefrom, and tax treatment and benefits, as "above the line" for ratemaking purposes. All tax savings will result in a lower cost of service for Central Vermont, thus keeping rates lower than they otherwise would be without the savings from this corporate structure.
     
     Docket 6835, Jean H. Gibson pf. 4/7/03 at 8. (emphasis added). Having asked us to rely upon that concept when it wished to have retail ratepayers compensate it for underperforming regulated affiliates in the past, CVPS is poorly placed to ask us to reverse that policy now.
367. See Deehan reb. pf. at 19.
368. Tr. 11/3/04 at 135 (Gibson).
369. Docket 6860, Order of 1/28/05 at 223 (emphasis added).
370. In addition, we note that CVPS is the only one of VELCO's owners that has requested below-the-line treatment of its investment in VELCO.
371. Docket 6866, Order of 1/27/04.
372. See Docket 6866, Order of 4/7/04.
373. Docket 5835, Order of 3/17/97 at 2.
374. As we explain in the Introduction, CVPS and the Department did not agree to the conditions, so the rate freeze never took effect.
375. Docket 6545, Order of 6/13/2002, at 165 (ordering paragraph 16).
376. Tr. 1/10/05 at 193-196 (ruling discussed by Chairman Dworkin)

Appendix A: Hearing Schedule

Technical Hearings held in 2004:
November 1-5, 2004

Technical Hearings held in 2005:
January 10-13, 2005
February 18, 2005

Appendix B: Procedural History

              On June 13, 2002, in our Order in Docket 6545 (approving the sale of the Vermont Yankee Nuclear Power Station to Entergy Nuclear Vermont Yankee, LLC), the Board required that:

Central Vermont shall file, in April, 2003, an updated cost-of-service based upon a test year ending December 31, 2002, with appropriate additional information as necessary to determine whether a rate decrease is appropriate in 2003 or 2004.³⁷⁵

Docket 6866

              Pursuant to the Board's Order in Docket 6545, CVPS filed cost of service studies on April 15, 2003. After a period of investigation by the Department, on July 11, 2003, the Department and CVPS filed a Memorandum of Understanding ("MOU") between them, which froze CVPS's rates for 2004, lowered CVPS's allowed return on equity from 11 percent to 10.5 percent for both 2003 and 2004, and established an earnings cap for 2004. The Board opened Docket 6866 to consider the MOU on July 22, 2003. After intervention by AARP, testimony, hearings, and briefs, the Board approved the MOU on January 27, 2004, but only on the condition that CVPS and the Department both affirmatively accept certain enumerated conditions. On February 3, 2004, CVPS notified the Board that it could not accept the modifications. CVPS asked for reconsideration. The Board convened a workshop based upon CVPS's motion. Subsequently, the Department reques ted, on March 26, 2004, that the Board open an investigation into CVPS's rates. The Board granted CVPS's motion to reconsider, in part, but the approval of the MOU never took effect as the parties to it did not accept the Board's conditions.

Docket 6946

              On April 7, 2004, pursuant to 30 V.S.A. Section 227(b), the Board opened the investigation requested by the Department -- Docket 6946. This docket covers rates for the period from April 7, 2004, through April 6, 2005. The Board convened a prehearing conference on April 28, 2005. At that time, CVPS proposed a schedule for the rate investigation that included CVPS's express agreement to waive the statutory seven-month deadline for resolution of this proceeding. On April 30, 2005, we accepted a slightly revised proposed schedule that was agreed upon by CVPS and the DPS.

Docket 6988

              On July 15, 2004, CVPS filed revised tariffs and cost-of-service schedules, requesting an increase in its retail rates of 5.01 percent, effective August 29, 2004, to be implemented on April 1, 2005.

              On August 12, 2004, the Board opened Docket 6988, which suspended CVPS's tariff filing and opened an investigation into the filing.

Parallel Proceedings

              By Order dated September 8, 2004, in Docket 6988, the Board agreed to consolidate Dockets 6946 and 6988 for purposes of hearings, discovery, and other scheduling matters. The test year in both dockets is calendar year 2003.

              AARP was granted intervention in both Dockets.

              The Board conducted a public hearing on September 14, 2004, using eight Vermont Interactive Television ("VIT") sites.

              The Board held technical hearings as duly noticed and scheduled on November 1, 2, 3, 4, and 5, 2004.

              After the filing of CVPS's rebuttal testimony, on December 10, 2004, the Department filed objections to the admission of certain prefiled testimony and exhibits. The Department supplemented this motion on December 27, 2004. The Department asserted that portions of CVPS's rebuttal testimony violated the provision of Section 225(a) that prohibits a company from updating a rate request or the proof that supports it. CVPS filed its response to the Department's objections on January 5, 2005. At the technical hearing on January 10, 2005, the Board granted the Department's request in large part, with the exception of two exhibits, based upon our conclusion that the portions of the testimony to which the Department objected represented impermissible updates.³⁷⁶

              The Board continued technical hearings on January 10, 11, 12, and 13, 2005.

              On January 19, 2005, CVPS filed a request that the Board: (1) arrange for mediation; (2) issue an accounting order; (3) bifurcate these proceedings; and (4) hold a workshop. On January 28, 2005, the Board denied CVPS's request on all elements except the requested accounting order, for which the Board scheduled and heard oral argument on February 2, 2005.

              Also on February 2, 2005, CVPS and the Department filed responses to questions from the Board regarding proposed treatment of regulated affiliates in the Company's cost of service, rate base, and overearnings calculations. In its request to the parties, the Board stated that, absent objection, it intended to incorporate the responses into the record. No party objected to the responses being included in the record; we hereby admit them.

              On February 8, 2005, CVPS and the Department filed a corrected settlement concerning some, though not all, of the issues regarding power costs.

              On February 10, 2005, CVPS filed a notice that there were errors in the testimony of CVPS witness Joan Gamble. On February 11, 2005, the Board directed the parties to assess the impact of the error, and scheduled a hearing on (1) the basis and implications of the error, and (2) the power cost settlement.

              The Board issued an accounting order on February 18, 2005, authorizing CVPS to defer recognition of a portion of its 2004 earnings, subject to several conditions.

              Also on February 18, 2005, Hearing Officer Ann Bishop held a continued technical hearing regarding the power cost settlement and the errors in Joan Gamble's testimony.

              On March 16 and 17, 2005, Board staff participated in two conference calls with the parties regarding scheduling issues. As a result of those conference calls, on March 18, 2005, CVPS filed a letter clarifying that it waived the statutory seven-month deadline for resolution of Docket 6946 until March 29, 2005. On the conference calls, the parties asked if the Board would provide them with an advance electronic copy of the spreadsheet the Board used to keep track of the cost-of-service and rate base decisions embodied in its final order. The parties stated that this would be a convenience for them given the short time period in which to prepare and review the required compliance filing, given the new rates' effective date of service rendered on and after April 1, 2005. On March 23, 2005, CVPS filed a letter requesting that the Board require the parties to treat the electronic spreadsheet as confidential information unti l today's Order was issued.

              On March 25, 2005, the Board sent the parties an electronic copy of this spreadsheet, and required the parties to keep it confidential until today's Order was issued. In addition, the Board reminded the parties that in the event of a conflict between the spreadsheet and today's Order, the Order will control.