REPORT ON WAPA LEAC VIPSC DOCKET 289 FACTORS FOR …€¦ · LEAC rates, the current LEAC petition is less than two pages long. The LEAC rate . 3 protocol recovers for WAPA fuel-related

1

REPORT ON WAPA LEAC

VIPSC DOCKET 289

FACTORS FOR JANUARY 1, 2013

DATE: DECEMBER 15, 2012

TO: ALL COMMISSIONERS

CC: BOYD SPREHN AND TANISHA BAILEY-ROKA

FROM: JAMSHED MADAN, LARRY GAWLIK AND ED MARGERISON

RE: JANUARY-MARCH 2013 LEAC FILING

I. EXECUTIVE SUMMARY

On November 20, 2012, the Virgin Islands Water and Power Authority (“WAPA”) filed,

five days later than anticipated, a request for implementation of a new Levelized Energy

Adjustment Clause (LEAC) for rates to be effective January 1, 2013. In addition to being

untimely filed, the filing itself did not contain the complete requirements. However, the

Minimum filing Requirements (MFRs), which are to be filed concurrent with the petition

as ordered by the Public Services Commission (“PSC” or “Commission”) over the past

several LEAC proceedings were submitted in advance of the delayed filing.

The root causes of the $0.032799 per kWh change in LEAC Rate from the October

through December 2012 LEAC Rate will be discussed in detail later in this report;

however, to aid the Commission in its review of WAPA’s rate petition, we have provided

below in Table 1 a quick overview identifying the key cost components contributing to

this change. As is shown, the key cost components can be segregated into three major

cost components—fuel oil prices, forecast of production efficiency and impacts of

deferred fuel recovery and other smaller cost components.

Table 1 Differential Analysis

Component Contribution % of Difference

Fuel Oil Prices ($0.00463) -14.1%

Efficiency Forecast $0.02676 81.6%

Deferred Fuel/Others $0.01067 32.5%

Total $0.03280 100.0%

2

As will be detailed more thoroughly in the body of this report, the price of fuel oil is

forecast to decrease during the January through March 2013 period and the principal

LEAC cost components contributing to the $0.032799 per kWh rise in the Electric LEAC

rate are the projected decrease in the production efficiency of the St. Thomas power plant

and, to a lesser degree, the recovery of the deferred fuel oil balance.

The individual impacts of these changes result in an overall increase in the proposed

LEAC rate for the period January through March 2013. As shown, the fuel pricing

component represents a decrease of approximately 14% as a result of a lower forecast

market price for fuel oil. The two remaining components contribute to the increase in the

proposed electric LEAC rate. The change in WAPA’s forecast of its production

efficiency at the St. Thomas plant, which WAPA now forecasts a lower efficiency than

used in the previous LEAC period, accounts for about 82% or the overall proposed

increase in the upcoming LEAC rate.

The final major cost component impacting the $0.032799 per kWh increase in the

Electric LEAC rate over the current LEAC rate is the deferred fuel recovery for the

January through March 2013 period and other costs (i.e., regulatory costs, debt service on

GO note, regulatory asset, pilot refund, and rate financing mechanism, discussed below).

This LEAC cost component reflects a 32% increase in its contribution to the proposed

LEAC rate as compared to the current LEAC rate.

We note for the Commission that the filing was missing the LEAC reconciliation for

Fiscal 2012 (twelve months ending June 2012), which is a critical document as it is the

basis to analyze issues related to the accuracy of the large “deferred fuel balances” that

impact the LEAC rates charged to consumers. This item albeit late has been subsequently

provided. Significantly, the petition also lacked updated information regarding the Rate

Financing Mechanism (RFM) that has been approved and implemented by the

Commission and provides WAPA approximately $17 million annually to pay for the (i.)

short-term lease of a trailer-mounted emergency combustion turbine to provide reliable

power, (ii.) deferred and extraordinary maintenance, (iii.) spare parts for existing

generating units, and (iv.) the services of an Independent Advisory Contractor (IAC) to

assist WAPA in restoring its existing generation to a reliable and efficient state of

operations. In providing the funds requested for the RFM the PSC established quarterly

reporting and other requirements that are to be filed concurrent with each LEAC

application until amended by the PSC. Again, much of this information, albeit very late,

has been recently filed after post filing discussions with WAPA. Numerous

conversations, emails, and teleconferences with WAPA post its LEAC filing have been

for the most part useful, but have again compressed severely the time available for full

analysis of all of the issues that were raised by this filing.

All of the problems identified above, which have been persistent for several consecutive

LEAC filings, indicate that the filings for LEAC rate changes continue to be inadequate.

Although there were many new policy and other issues presented in the calculation of the

LEAC rates, the current LEAC petition is less than two pages long. The LEAC rate

3

protocol recovers for WAPA fuel-related and other charges from consumers of

approximately $ 292 million in FY 2013.1 These filings are the major vehicle through

which WAPA gets revenues and recovers it fuel related costs. By contrast base revenues

are approximately 25% of fuel revenues and changes requested for those revenues in

amounts that are significantly less than the cumulative changes requested for fuel related

charges are accompanied by detailed testimony supported by major witnesses. GCG has

continually recommended that the PSC require that the LEAC petitions contain more

supporting testimony and detailed information, be reviewed for filing adequacy and be

much more transparent as to the root causes for the changes in the requested LEAC rates.

Unlike the current petition, which is perfunctory and does not accurately reflect the

primary causes of the proposed increase in the LEAC rate, all changes in any underlying

circumstance should be spelled out in detail with appropriate supporting schedules and

analysis.2

Our initial comments on the major points addressed by WAPA in its petition and those

that should have been addressed are as follows:

WAPA indicates in its petition that “the increase in the LEAC rate is caused primarily by

the recent increases in oil prices resulting from the closure of the Hovensa Refinery and

the subsequent loss of the discount that we had received under previous agreements. A

further factor is the under recovered fuel costs from prior periods which also has been

growing with the increase in fuel prices.”

GCG analysis shows that WAPA’s own projections for fuel prices in this proceeding of

the price per barrel for deliveries of No. 2 fuel oil for the current quarter of October

through December is $133, $141, $135 per barrel respectively and WAPA’s projection

for January through March 2013 (the upcoming LEAC period) of the price per barrel for

deliveries of No. 2 fuel oil is $135 per barrel each month. WAPA’s statement that oil

prices are the primary cause the high LEAC rates and increases in the rate is simply

incorrect. The fuel oil price forecast used by WAPA in this LEAC rate petition for the

period January through March 2013 is essentially the same to slightly less than the fuel

oil price forecast used for the October-December 2012 LEAC rate filing. The root causes

of the proposed $0.032799 per kWh change in LEAC rate from the October through

December 2012 LEAC rate will be discussed in detail later in this report; however, to aid

the Commission in its review of WAPA’s rate petition, we can identify the key cost

components contributing to the increase in the LEAC rate in this proceeding principally

as the forecast of production efficiency and impacts of deferred fuel recovery and other

smaller cost components. These will be discussed in detail in the body of the report and

are the same root causes that have been identified in prior proceedings.

WAPA’s statements on the cause of its high level of unrecovered fuel are inaccurate at

best and misleading at worst. Each quarter with the filing of a new proposed LEAC rate

1 See Electric Summary Schedule in FY 2013 Excel workbook attached to this report. 2 For example as will be discussed shortly there is a new proposal from WAPA as to how to treat Reverse Osmosis (RO) costs that relate to the production of water in this filing. There is not a mention of this change in the petition.

4

WAPA files a projection of its anticipated operational performance for that quarter—it

never meets its projected performance level and as a result consumes more fuel than it

forecast being required. This is in spite of WAPA projecting its operational performance

(i.e., heat rate for each of the plants or the kWh produced with a gallon of fuel) well

below industry standards for the plants on WAPA’s system; below the standards set by

WAPA’s consultants, Harris Group; and well below the equipment manufacturers’

standards for operation. GCG analysis that is detailed later in this report,

demonstrates that for every month in calendar year 2012 WAPA has considerably

under-performed (worse than) its own projections for operational performance. This

results in the LEAC rate under-recovering fuel expense, caused not by any PSC action,

but by poor WAPA plant operations. GCG recommends that in each LEAC application

WAPA provide an analysis in its petition showing its performance in the current and

recent LEAC periods compared to what it had projected and the resulting impact on its

deferred fuel balance—similar to the analysis we have provided later in this report. Poor

operational performance continues to plague WAPA and cause high rates for consumers

and businesses and further increases to recover the additional cost of fuel burned due to

poor plant efficiency. Our report contains an extended discussion on this issue. It is an

important issue that is not fully transparent to the public. WAPA has taken the position

that it is hampered by continually having to absorb increasing deferred fuel balances,

implying that these increases in its deferred fuel balances are created by the PSC

awarding insufficient LEAC rate relief. This is just not the case. The price of fuel oil as

included in the LEAC has been sufficient to provide for the market price of oil. This is

shown in a detailed analysis in the report below. However, in each LEAC rate filing

WAPA proposes a level of operation performance of its plants that the PSC reviews and

adopts and then WAPA never meets the operational efficiency criteria that it has

projected. This is a condition of WAPA’s own making.

In the past WAPA has posed the following question to the PSC team: if the projections

look like they cannot be met, why does the PSC team not make an appropriate

adjustment? The answer is several-fold.

First, the projections made by WAPA certainly look like they should be attained. We

would expect WAPA to meet the operating efficiencies it projects. As plant

rehabilitation work is completed we would expect a much higher standard of efficiency to

be attained. Current operations do not meet the interim efficiency standards set by

WAPA’s own consultants, the Harris Group. Failure to meet these interim operational

efficiency standards has cost VI consumers, businesses, and the economy hundreds of

millions of dollars over the years that should have been avoided. As we will show, in this

LEAC rate filing WAPA has projected operational efficiency on St. Thomas in line with

recent (inefficient) operating efficiencies and will therefore be in a position to meet these

operating standards, but on St. Croix has projected operating efficiencies much better

than recent (inefficient) operations and WAPA will have difficulty meeting those

projections. Of course, we would prefer that WAPA indeed meet all of the projections.

It should be clearly understood that a major portion of the increase in the proposed LEAC

rate (January to March 2013) is due to WAPA first making an optimistic operating

projections in the prior LEAC (October through December 2012) and then not meeting

5

those projections. No deferred fuel addition has been “imposed” on WAPA by an

unreasonable PSC order.

With regard to the RFM WAPA indicates this filing also includes the factor to cover a

Rate Financing Mechanism previously approved by the Commission to provide for an

emergency generator and repairs of existing units at $0.023 per Kwh. The temporary GE

TM 2500 has been installed at the Randolph Harley Power Plant on St. Thomas and has

been in operation since May 28th

. Of significant note is that the savings in fuel with the

new dispatches and overhaul schedules have been well in excess of the cost of the

program. These calculations have been provided in greater detail in the discoveries and

filings with the temporary and base rate.

GCG does not believe that the RFM that grants WAPA approximately $17 million

annually has been implemented as per the PSC Order, nor have the results been

significant yet. The RFM was implemented through a Stipulation reached between the

PSC staff and WAPA, which was subsequently approved by the PSC. A key feature in

that Stipulation was the requirement that WAPA bring on board an Independent Advisory

Contractor (IAC) through a Request for Proposal (RFP) process with collaboration with

the PSC staff and approval of the RFP document by the PSC. There has been little or no

collaboration with the staff and WAPA has recently presented a draft RFP document to

the PSC for direct review and approval without any involvement of the PSC staff. GCG

has reviewed this document and believes that it does not comport to the requirements of

Attachment 6 to the RFM Stipulation to which WAPA had previously agreed. In recent

discussions with WAPA executive management it was stated that WAPA did not fully

understand the requirements of the Stipulation. Having been on the other side of the

process to stipulate with WAPA it is hard to understand this position. GCG recommends

that the process move forward as per the Stipulation. WAPA has indicated that it wishes

to move forward, but to date has not been willing to discuss its draft RFP with the PSC

staff and its objections to the RFP drafted by PSC staff which meets the requirements of

the stipulation.

WAPA has indicated that it believes that the IAC would be beneficial. GCG agrees and

recommends implementation of these advisory services after a satisfactory RFP has been

approved by the PSC. The Stipulation requires collaboration to produce the RFP which

must then be approved by the PSC. GCG believes the advice of the IAC will help

improve efficiency at the plant as it has in other jurisdictions. As stated earlier, poor

plant efficiency continues to be a very major factor in the high LEAC factors that WAPA

charges consumers. GCG recommends that WAPA and GCG deliver to the PSC an

agreed to RFP scope as required by the Stipulation no later than January 31, 2013.3 In the

event that there is no agreement and no document is delivered GCG recommends that the

PSC consider what appropriate rate action it wishes to take including the possibility of

deferring the further implementation of the RFM until there is compliance with the terms

of the Stipulation and PSC order.

3 In response to discovery in the recent emergency rate filing WAPA stated that it believed that the RFP would be on the street by October 2012.

6

WAPA made no mention in the LEAC petition that it was using a new methodology to

treat RO costs allocations between the electric and water departments and that has been

included in the calculations for the proposed LEAC rates. It is important to understand

that (i) the prior allocation methodology was both disclosed and approved by the

Commission; (ii) RO production has been in effect for quite a while, over two years on

St. Croix (beginning with temporary plants) and at least since January 2012 on St

Thomas, following last winter’s loss of IDE water production; and (iii) in the 2009 rate

investigation, WAPA agreed to file a new rate case on in the installation of RO

production to develop a new cost allocation methodology.RO production has been in

effect for a while. The new contract for RO production with Seven Seas has been in

effect since January 2012 for St. Thomas and since March 2012 for St. Croix. Production

for each Island was roughly 1.5 million gallons per day (GPD). In January 2013 a new

permanent RO facility on St. Thomas is projected to be operational and a similar new

system on St. Croix is projected sometime near the end of 2013 having been delayed once

again apparently after the last indicated dated to the PSC of mid 2013. The following are

key features of the RO contracts that impact the electric and water departments:

There is no charge to Seven Seas for electricity to produce water. The electric

department supplies electricity to produce potable water which is charged to water

consumers. WAPA staff agrees that the electric cost to produce water that is

charged to water consumers should be credited to the electric department and that

it has not been included in the schedules submitted in this and LEAC filing. It

should be understood that the populations of electric and water consumers are not

the same. Virtually every household and business has electricity; however, the

water consumer population is significantly smaller. The credit that should have

been given to the electric department is approximately $5 million annually or

approximately $400,000 per month. We have made that adjustment to credit

electric consumers in our schedules with apparent WAPA agreement.

The water department makes two different kinds of water for the electric

department and credits the cost to make the water to the water department as it

should from the total cost of water for the water department. However, WAPA

did not charge the electric department for the cost of this water as it should have.

We have made the corrections to make the appropriate charges to the electric

consumers in our schedules with apparent WAPA agreement.

The net of the two adjustments to the electric department is a net benefit to

electric consumers who will avoid a double charge as a result of these errors. No

change is required for the water department.

The errors and adjustments not only apply to the next quarter, January through

March 2013, but also apply for the appropriate time period in 2012 where

corresponding adjustments should have been made. GCG recommends that this

analysis be undertaken by WAPA and presented to GCG no later than January 31,

2013. The impact of this change should be recognized in the next LEAC.

7

WAPA unilaterally determined the appropriate rate the electric department

should charge the Water department for the supply of electricity. WAPA did

not choose any of the existing customer tariffs for this rate. Rather it looked at

production costs for the fiscal year ending June 2012 and divided by gross

generation to get rate of approximately 32 cents per kWh. WAPA has not

provided a proposed tariff for PSC review and approval of what is essentially a

retail electric tariff applicable to the production of potable water. GCG does not

agree with this approach4 or the failure to account for this consumption on the

basis of a PSC approved tariff and recommends that PSC staff and WAPA

attempt to make a joint proposal to the PSC at the next LEAC proceeding and file

on this basis pending PSC approval. GCG believes that the rate cannot be “fixed”

as the fuel cost itself keeps changing and there is no consideration of the high cost

of maintenance of WAPA power plants. The use of gross generation appears to be

incorrect.5 One option would be to treat the water department like a large

commercial customer; however, this is somewhat questionable since the water

department is not the end-user of the electricity being provided—it is simply the

beneficiary of the water produced by a private party. GCG believes that full

disclosure by WAPA of what it wanted to implement together with discussions

with staff might have avoided the errors in this proceeding. This is simply a

further example of the lack of transparency that hampers the regulatory

environment.

In addition to the issues raised with the implementation of the RO contracts, GCG

recommends that spending $2.2 million per quarter on water production from the existing

IDE plants should be appropriately justified by WAPA before they should be permitted

any further inclusion the water LEAC. From January 2013, 100% of all water production

(3 million GPD) on St. Thomas should be through the RO plants. In addition to the fuel

costs there are also other operating costs for the IDE plants. There are no additional costs

for the Seven Seas contract.

The current temporary RO units (1.5 million GPD) on St. Thomas may still be available.

On St. Croix production for some time has been through temporary units (1.5 million

GPD). RO production appears to have been very reliable. On both Islands there will be

production of 4.5 million GPD of RO capacity beginning January 1, 2013. By contrast

there will remain 1.5 million GPD of water production from the IDE plants on St. Croix.

In the past WAPA has offered the justification of operating the plants as a backup for any

RO problems. As stated above the temporary units from St. Thomas are possible

available and GCG recommends that WAPA should explore whether there is a basis for

keeping them on standby or in fact deploying them on St. Croix. It is our understanding

that some of the St. Thomas units were originally on St. Croix before they were deployed

to St. Thomas because of the earlier water emergency.

4 As well as the lack of disclosure. 5 Even assuming the logic of what WAPA represented it wanted to do, the use of Net Plant Generation would be more appropriate.

8

II. ELECTRIC DEPARTMENT

WAPA filed its request for a new electric LEAC rate to be implemented effective January

1, 2013. WAPA indicates that the proposed new rate will be another increase in both the

LEAC rate and overall bills. WAPA computes that the new electric department LEAC

rate should be $0.416033 per kWh or an increase from the current factor of $0.383234

per kWh. If this factor is approved by the PSC, this would result in an increase for the

average residential consumer of about $13.12 or about 6.76 percent of the total monthly

bill. The following table presents the summary of WAPA’s filing and compares that to

GCG’s findings as described in this report:

Table 2

WAPA LEAC-Electric

($000’s)

WAPA

GCG

As Filed

As Updated

($000s)

($000s)

A Cost of Fuel $ 64,145

$ 63,074

B Regulatory Costs (Dkt 289) 55

40

C P&I on New 4-Yr GO Note 126

126

D Regulatory Asset Costs 215

215

E Pilot Refund 0

0

F Elect. Charged Water 0

(1,210)

G Ultra Pure Water Charge 0

255

H

Water Production

Charge/RO 0

358

I Plant Repair RO Contract 0

60

J Rate Financing Mechanism 4,168

4,168

Current LEAC Costs $ 68,708

$ 67,086

K Deferred Fuel Costs 6,689

6,828

TOTAL Costs $ 75,397

$ 73,913

Total mWh 181,228

181,228

Proposed LEAC Factor $ 0.416033

$ 0.407847 /kWh

Current LEAC Factor $ 0.383234

$ 0.383234 /kWh

Increase $ 0.032799

$ 0.024613 /kWh

Average Residential Usage 400

463 kWh

Monthly Increase $ 13.12

$ 11.40

Current Average Bill $ 193.97

$ 193.97

Percent Increase 6.76%

5.88%

9

GCG is uncertain as to why WAPA has reduced the average usage per residential

customer to 400 kWh per month. In the past WAPA has used 500 kWh for average usage.

Our analysis shows that the current average residential use is 463 kWh and we show bill

impacts for residential consumers based on this figure.

Cost of Fuel:

For the forecast of fuel costs, WAPA assumed the current Hovensa contract pricing terms

and discount would remain in place until November 30, 2012. Thereafter, the new

pricing under the terms and conditions of the new fuel contract with Trafigura AG will be

in effect for Number 2 oil. The new contract was just made available during the

proceeding and a full understanding of the terms and overall impacts compared to the

Hovensa contract may take several LEAC filings to sort out. The following table shows

the actual or forecasted delivered price of both Number 6 and Number 2 oil. The vast

majority of fuel used by WAPA is Number 2 oil.

Table 3a

Cost Per Barrel

Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13

Actual Actual Actual Forecast

STT #6 $ 103.37 $ 102.83 $ 102.07 $ 101.95 $ 102.82 $ 107.68 $ 107.15 $ 106.68 $ 106.22

STX #6 $ 93.65 $ 93.65 $ 98.32 $ 98.98 $ 114.10 $ 119.48 $ 118.90 $ 116.70 $ 117.86

STT #2 $ 106.29 $ 120.23 $ 126.00 $ 133.11 $ 140.71 $ 134.86 $ 135.21 $ 135.20 $ 134.91

STX #2 $ 106.69 $ 123.67 $ 125.30 $ 136.22 $ 140.71 $ 134.86 $ 135.21 $ 135.20 $ 134.91

For the delivery of Number 6 oil, WAPA has used the pricing template it has used in the

past. Starting with a forecast of Brent Crude, WAPA adds $3 per barrel as a

transportation allowance and then multiplies that total by a historic ratio of Number 6

oil(s) price versus Brent Price. Using February 2012 as an example:

Table 3b

Cost per Barrel Forecast # 6

February 20136

STT #6 STX #6

Brent Blend Futures $ 111.71 $ 111.71

Shipping Allowance 3.00 3.00

Base Price $ 114.71 $ 114.71

Market Ratio 93% 103%

NY Harbor Price $ 106.68 $ 118.38

6 There is programming error in the WAPA workbook. The actual price used by WAPA was $116.70 for February purchases on St Croix. GCG has corrected the error in update of fuel price.

10

Currently, WAPA does not have a contract to provide Number 6 oil to the Territory.

WAPA has stated that it believes that current supply on hand will suffice for the interim,

once the current inventory has been modified to reflect differing Environmental

Protection Agency (“EPA”) requirements for St Thomas and St Croix.

The overwhelming majority of purchase for the forecasted LEAC period (January

through March 2013) is Number 2 oil. The algorithm used for forecasting the price on

Number 2 oil has changed as a result of the new fuel contract. As indicated above GCG

has only recently received a copy of the contract.

Under the provisions of the new fuel contract, WAPA will pay a price that is equal to the

average price of the price of No 2 oil as published in the Platts Oilgram Price Report7 and

the forecasted price of Heating Oil (“HO”) as published Argus US Products. These

prices are presented in dollars per gallon. Once the average is determined, the cost of

gallon is converted to cost per barrel and then an allowance of $9.97 per barrel is added

to recover delivery and other costs incurred by Trafigura as well as profit.

WAPA sought advice from its fuel consultant as to a reasonable surrogate to forecast

future deliveries under the pricing provision of its new contract. The consultant

suggested using a report available on-line from CME Group, i.e. “Energy Futures

Report.” The following algorithm shows how WAPA forecasted the price for February

2013 delivery.

Table 3c

Cost per Barrel Forecast # 2

February 2013

CME Group HO/gal. $ 2.98

Conversion gal. to

barrel 42

Shipping/markup $ 9.97

Delivered Price $ 135.20

WAPA prepared the LEAC filing in November 2012 and used the latest projection of HO

futures from this source. In the weeks between the preparation of the filing and the

preparation of this report, the price of HO has dropped creating a difference in

forecasting supply of Number 2 oil. The following table shows the difference in the

January through March projection of HO pricing

7 “US Gulf Coast Waterborne”

11

Table 3d

Heating Oil Price Futures

$/Gal

GCG has reflected the downward in price for HO to reflect the December 11 projection

by CME Group. This has been the practice accepted by the Commission in order to

reflect the most recent prices available at the time of preparation of the report.8

Efficiency of Plant Operations and Deferred Fuel

We indicated above that we would provide information on the relationship between the

efficiency of WAPA plant operations relative to the efficiencies projected by WAPA

itself and the Deferred Fuel Balances.

It is imperative that the Commission, consumers, businesses, and WAPA fully understand

the causes of the WAPA’s excessive deferred fuel balance. There appears to be a lack of

transparency on the facts related to this issue that has resulted in a misunderstanding of

the factors contributing to the deferred fuel balance. In order to examine this matter in

detail, we have prepared an analysis of calendar year 2012 to isolate the root causes of

the growing deferred fuel balance. This timeframe was chosen because it is current and

because it has been the focus of much of the discussions in the media and WAPA

pronouncements at Board Meetings and before the USVI Legislature.

The level of WAPA’s deferred fuel balance is impacted by a number of variables.—

virtually all of which are controllable by WAPA. WAPA remains totally dependent on

fuel oil in the short-term and will have little control of the world market “price level” it

pays for fuel oil. However, the deferred fuel balance is not impacted so much by the

“price level” WAPA pays for fuel oil, but more so by the “forecast” of efficiency of

expected for LEAC periods. Although WAPA has no control over the level of world oil

prices, it does have control of the forecast of oil costs used in the development of the

LEAC rate. As it relates to the deferred fuel balance the principal factors impacting the

level of the balance are the “forecasts” of (i.) oil pricing and (ii.) the efficiency of WAPA

power plants. These two factors have the greatest impact on the overall deferred fuel

balance of the LEAC rate. Both of these components of the LEAC rate and are prepared

by WAPA and provided in its quarterly LEAC petitions to the Commission.

8 In our review, we noted that the forecasted generation for the months of November and December 2012 on St Croix failed to meet demand. We have corrected this error in our calculations. This error has occurred before.

Jan-13 Feb-13 Mar-13

Forecast

As Filed $ 2.98 $ 2.98 $ 2.97

As Updated $ 2.90 $ 2.91 $ 2.91

12

In looking at the forecast of fuel oil prices used in the development of the LEAC rates in

effect for the period January through November 2012 we have prepared Figure 1 which

shows the relationship between the

fuel pricing forecasts used in the

LEAC rates and the actual fuel oil

prices incurred. The fuel oil pricing

forecasts are prepared on the basis of

an established methodology that

incorporates published oil industry

pricing benchmarks with adjustments

for shipping and other well-

established factors. WAPA files its

various LEAC petitions with the latest

available information concerning the published oil industry pricing benchmarks. The

pricing levels are sometime adjusted prior to the Commission taking action on a

particular LEAC factor if the pricing benchmarks have moved up or down by what would

be deemed to be a material amount. This occurred once in 2012 with the July through

September 2012 LEAC and resulted in a downward adjustment in the fuel pricing for that

period.

As can be seen in Figure 1 the fuel oil price forecast for the first part of 2012 was in

excess of the price that WAPA actually paid during this time period. Then in the latter

part of 2012 the price forecast used in the development of the LEAC was below the cost

of fuel incurred by WAPA during this period. As would be expected and as shown in

Figure 2 during the first part of 2012

the fuel oil price used in the LEAC

rate calculation contributed to

decreasing the deferred fuel oil

balance and resulted at its peak in an

over-recovery of the fuel pricing

component of the LEAC by slightly

over $8 million. Likewise during

the latter half of 2012 the fuel

pricing component gave back the

majority of the amount over-

recovered during the first half of 2012 and for the year-to-date ending November 2012

resulted in a cumulative over-recovery for 2012 at slightly less than $600 thousand.

Overall for 2012 the fuel oil pricing component used in the LEAC had no negative

impact on the deferred fuel balance and did an excellent job at simulating the price of fuel

oil for 2012. In fact, the fuel oil pricing forecast slightly contributed to decreasing the

deferred fuel oil balance.

$90

$100

$110

$120

$130

$140

Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12

Figure 1Fuel Pricing--Forecast vs. Actual

($/BBL)

Fuel Oil Price Forecast

Actual Fuel Oil Price

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

Jan-12 Mar-12 May-12 Jul-12 Sep-12

Do

llars

in $

10

00

's

Figure 2Cumulative Fuel Pricing Over-recovery

Fuel Pricing Over-recovery

13

Given that the first of the two principal variables impacting the deferred fuel balance

actually contributed positively, and not negatively, to the deferred fuel balance for year-

to-date 2012 it is logical to conclude that the forecast of power plant efficiency must have

been the sole variable contributing negatively and that this is the principal root cause for

why WAPA continues to find itself in a position of a cash crisis.

To aid the Commission, consumers, businesses and WAPA in understanding the impact

of actual power plant performance to the forecast of power plant performance submitted

by WAPA with each of its quarterly LEAC filings we prepared an analysis for the period

January through November 2012.

This analysis for the St. Thomas

plant is shown in Figure 3 and for the

St. Croix plant is shown in Figure 4.

As can be seen in both the figures for

the St. Thomas and St. Croix power

plants WAPA over-estimated (lower

BTU/kWh values) represents a

superior efficiency level of the

efficiency of plant performance

significantly when compared to the actual performance of its power plants for the period

January through November 2012. In every month of 2012 it failed to meet the

performance (efficiency) projections that it had included in each of its LEAC filings

submitted to the Commission over the course of 2012. In fact, an examination will show

that WAPA has failed to meet the quarterly performance projections used in any of its

LEAC filings during the past three-years.

The Commission has relied on the performance forecast provided by WAPA in setting

each LEAC rate during the past three-years and has used the exact forecast, without

adjustment, provided by WAPA in its quarterly filings. The reasons for such actions have

been summarized in the Executive

Summary section. Unfortunately,

WAPA has failed to achieve the level

of performance it has included in its

LEAC rate filings at its power plants

which has caused it to under-recover

its fuel expense, this under-recovery

has grown substantially during

calendar year 2012. Once an under-

recovery has occurred WAPA makes

a recommendation that the under-

recovery be recovered over generally six or 12 months as it has done in this current filing.

An under-recovery implies that WAPA has spent more cash for fuel than it forecast not

because the price of fuel was higher but because its operations were not as efficient as it

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13

Figure 3STT Plant Efficiency

(BTU's/kWh)

WAPA Forecasts

Actual Performance

Current Forecast

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000

Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13

Figure 4STX Plant Efficiency

(BTU's/kWh)WAPA Forecasts

Actual Performance

Current Forecast

14

had forecasted. The power plant inefficiencies coupled with the slow payment practices

of certain governmental customers are to root causes of WAPA current cash crisis. It is

worth noting that in Figures 3 and 4 we have included the performance forecast for the

LEAC period January through March 2013.

Given the substantial adverse impact in power plant performance between the forecast

WAPA provided in each of its LEAC rate filings for 2012 and its actual performance we

analyzed the impact on the deferred

fuel balance. This information is

provided in Figure 5. As shown in

this figure the cumulative deferred

fuel balance was adversely impacted

in every month of 2012 as a result of

WAPA failing to achieve the

performance forecast it provided the

Commission for inclusion in the

LEAC rate. The net impact on the

deferred fuel balance associated with

WAPA power plant performance being worse than its own projections during the period

January through November 2012 was approximately $33 million. It is critical that the

Commission, consumers, and business recognize that this $33 million is just the impact

on the deferred fuel balance. While this is a large amount it only reflects part of the

impact on consumers, businesses, and the local economy associated with power plant

efficiency. The impact that should be expected from the proper management, operations

and maintenance of WAPA’s power production facilities is far greater than the $33

million and will be discussed further herein.

We also note for the Commission in Figure 3 for St. Thomas that WAPA has changed the

level of its power plant performance forecast for the LEAC period January through

March 2013 to be more in line with its actual experience for 2012. While this will have

the impact to reduce the continued accumulation in the deferred fuel balance, it does call

into question the consumer benefits that were anticipated from the RFM surcharge to the

LEAC rate. The January through March 2013 forecast clearly does not reflect any

benefits from the RFM when compared to the performance achieved during the period

January through April 2012 i.e. the period immediately prior to putting in place the RFM.

This raises the question: where are the benefits consumers are paying for in the RFM?

This matter is discussed later herein. Finally, we must comment on the January through

March 2013 performance forecast in Figure 4 for the St. Croix plant. The forecast for

this period shows that the St. Croix power plant is somehow forecast to operate at a

significantly better level of efficiency than at any time during 2012, and for that matter

any time during the past three-years. We would caution that this forecast of performance

is probably overly optimistic and will likely lead to further increases in the deferred fuel

balance.

-$35,000

-$30,000

-$25,000

-$20,000

-$15,000

-$10,000

-$5,000

$0

Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12

Do

llars

in $

10

00

's

Figure 5Cumulative Efficiency Under-recovery

Efficiency Under-recovery

15

Impact of Efficiency on Cost of Fuel

The projection of fuel oil pricing, discussed above, is a critical factor, but is only one of

the key variables embodied in the development of the January-March 2013 (and prior)

LEAC rates. Other key variables include the dispatch and efficiency of WAPA’s power

plant facilities. Along with fuel oil prices, a change in the dispatch and efficiency of

power plants will have an impact on the LEAC rates since they impact the quantity of

fuel consumed. Any change in the efficiency of WAPA power plant facilities directly

impacts the amount of fuel which must be procured and burned, and the overall level of

the LEAC rate. The performance of WAPA’s power plants is projected in each LEAC

filing for the purpose of deriving the cost of fuel for operations. To the extent that

WAPA more optimistically estimates its power plant performance than the plants actually

perform during a LEAC rate period the mismatch between the estimates and actual

performance will result in an under-recovery of its fuel expense that will be recovered as

“deferred fuel expense” in future LEAC rates. As shown earlier in this report this has

been a recurring problem due to a long history of continuing optimistic forecasts of

power production efficiencies resulting in an additional under-recovery of over $33

million during 2012.

Similar to the earlier figures provided concerning power plant performance and the

impact on WAPA’s deferred fuel balance, we have also included Figures 6 and 7 which

show for calendar year 2012 the relationship between WAPA’s forecast of production

efficiency and actual efficiency

achieved during the year. Figure 6

presents production efficiency data

for January through November for

the St. Thomas power plant. The

data is divided into the four discrete

LEAC periods—January through

March, April through June, July

through September, and October

through November. The dashed line

shows WAPA’s forecast of

production efficiency for each month of the year. Likewise, the top line shows WAPA’s

“actual” production efficiency attained. It should be noted that the level of production

efficiency attained is far below the industry average, and even further below current

trends in production efficiency. An acceptable level of system efficiency would be in the

range of 9500 to 10,000 BTU’s/kWh, meaning that WAPA burns about 50% more fuel

than an average system or 80% more than an efficient system.

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000


Figure 6St. Thomas Plant Efficiency

Forecast vs. Actual(BTU's/kWh)

WAPA's Efficiency Forecast

Actual Efficiency Achieved

16

Similarly, Figure 7 shows data for January through November 2012 for the St. Croix

power plant. Like the figure for St. Thomas the data is also divided into the four discrete

LEAC periods for calendar year 2012.

Like the earlier figure, there are two

lines shown for the period January

through September and one line for

the period October through

November. The dashed line shows

WAPA’s forecast of production

efficiency for each month of the year.

Likewise, the top line shows WAPA’s

“actual” production efficiency

attained. It should be noted that the

level of production efficiency attained while better than that for St. Thomas is also far

below the industry average, and even further below current trends in production

efficiency. It should also be noted than in recent months the projection and actual lines

have been trending toward each other; however, as pointed out earlier in this report the

projections for January through March 2013 have been adjusted to levels that are

probably unattainable.

.

As shown in Figures 6 and 7 the forecast of production efficiency for both the St. Thomas

and St. Croix power plants for 2012 and accepted by the PSC for calendar year 2012,

were more optimistic than the actual results obtained during each of the LEAC periods

and have resulted in a substantial under-recovery of fuel costs. While we accepted the

WAPA production forecast for review, we continue to have concerns as voiced in each of

our past reports that the forecast particularly for St. Croix may again be overly optimistic

for the January through March 2013 LEAC period. As shown earlier in this report the

forecast of production efficiency for the upcoming LEAC period is more favorable than

WAPA has achieved at any time during 2012. In fact, the St. Croix forecast of

production efficiency for January through March 2013 indicates that WAPA will achieve

an efficiency level that it has not achieved at any time during the last five-years. We note

that the January through March 2013 production efficiency forecast for St. Thomas is at

least closing the gap between past forecast and actual data, which should be attainable.

However, any failure to meet these production forecasts will result in WAPA continuing

to increase its deferred fuel balance. While the efficiencies projected are attainable,

WAPA simply has not performed at these efficiency levels for a long period of time.

We’ve brought this matter to WAPA’s attention a number of times. Accordingly, we

have not adjusted the efficiency assumptions made in WAPA’s submission. This would

have increased the LEAC rate request even further.

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000


Figure 7St. Croix Plant Efficiency

Forecast vs. Actual(BTU's/kWh)

WAPA's Efficiency Forecast

Actual Efficiency Achieved

17

Fuel Diversification and Energy Efficiency

The lack of fuel diversification and high level of inefficiency of WAPA’s power plant

facilities continue to expose VI consumers to risks of supply interruptions and pricing

volatility. While WAPA has made some progress in the area of fuel diversification with

its recently authorized solar projects this progress will have a limited impact on

diversification. We see the establishment of a path that could establish clear energy

efficiency standards and benchmarks consistent with industry best practices and fuel

diversification benchmarks and milestones. The WAPA board has already determined a

strategy for reducing the cost of energy in the Virgin Islands. This strategy includes both

fuel diversification and energy efficiency objectives. The Commission should consider

measures to aid in the accomplishment of these strategies. The strategies adopted by the

WAPA board could form a basis for the Commission exercising its rate setting powers to

move WAPA toward greater fuel diversification and more efficient operations of its

existing facilities. These strategies adopted by the WAPA board include:

Implementing measures to enhance production efficiency at existing power

generation facilities.

Convert base-load power production from fuel oil to liquefied natural gas and/or

propane

Develop grid interconnection between the Virgin Islands and Puerto Rico;

Maximize development of solar and wind resources; and

Pursue biomass energy and ocean thermal energy as potential diversification of

base load energy.

WAPA is to be commended for adopting the fuel diversification and energy efficiency

strategies described above. It is critical that objective measures, benchmarks and

milestones be developed so that the process for implementation of these strategies is fully

transparent to consumers, businesses, and the Commission. To provide for accountability

and transparency to the public and to insure that WAPA does not slip into a mode of

simply relying on its ability to pass through whatever its fuel cost are without regard to

the underlying efficiency (the current situation) some form of incentive should be

considered to get these type of programs implemented. As a first step, we recommend

that WAPA be required to provide the Commission with the existing tactical and

implementation plans, activities and milestones it will undertake to implement the five

strategic fuel diversification and energy efficiency objectives identified by the WAPA

board.

Docket 289 Costs

WAPA has forecasted the cost of the regulation for the LEAC to be $55 thousand over a

three-month period with no allocation to the water department. WAPA also projects a

similar amount for the three months ending December 2012. WAPA has failed to

allocate a portion of these costs to the water department, which should be done. It is

18

important to understand that WAPA has been currently recovering from both electric and

water consumers the actual and projected cost of regulation as it applies to this item and

is currently in arrears in paying these costs. We have allocated an appropriate portion of

these regulatory costs to the water department as we have done in the past that has been

adopted by the PSC. The net effect of this adjustment is to include $40 thousand of

projected regulatory costs in the electric LEAC rate and to include the remaining $15

thousand in the water LEAC rate.

General Obligation Note

In the derivation of the electric LEAC rate, WAPA shows constant monthly payments of

principal and interest $42 thousand per month and in every month after the refinanced

note in August 2012. WAPA is assuming a 48 month collection period for the electric

department and a shorter period for the water customers (16 months @ $198 thousand per

month). This increases the short-term burden of the water consumers, but decreases the

costs for the first sixteen months for electric consumers. After seventeenth months, the

monthly payment goes back to $240k for the electric department and the water

department would have no further burden.

WAPA has made this proposal in order to accelerate payments and reduce the amounts

owed to the electric department by the water department. As of October 2012, the water

department owed the electric department $9.8 million, including the water department’s

responsibility on the GO note. We have accepted WAPA’s proposal.

Regulatory Asset and PILOT

Both of these items are fixed monthly amounts and have been approved by the PSC for

inclusion in the LEAC computation. It appears that the PILOT refund will be fully

amortized by December 2012 and no further credit is being given starting in January. As

currently projected, the regulatory asset amortization will not cease in June of 2013.

Therefore an allowance of the amortized costs related to the regulatory asset is

appropriate for the next LEAC. GCG has accepted the projection of these costs in its

update of the LEAC request contained in this report.

Ultra-Pure Water Cost

WAPA has proposed a credit (reduction) to the water department of the costs of

production of water by the Reverse Osmosis (“RO”) unit on St Thomas. The RO unit

produces ultra pure water that is used exclusively for the generation of electricity and is

not distributed by the water department for consumption by water consumers. While

WAPA has filed the water department LEAC rate request using this as a reduction in fuel

costs for water consumers, based on our discussions with WAPA we find that it failed to

include these as costs to the electric consumers. GCG agrees that this cost is a

responsibility of the electric department. As a result, GCG has included the cost in our

calculation of the electric department LEAC rate and made an adjustment to the

forecasted electric LEAC costs as well as an allowance for costs incurred since July 1,

2012. A more complete explanation may be found in the water department LEAC rate

19

discussion. GCG recommends that the credits and debits for the period July 1, 2012

through December 31, 2012 that were not used as current charges in the LEAC

determinations should be reviewed in the next LEAC proceeding for the period April 1,

2013 through June 30, 2013.

Water Production Costs

As with the Ultra-Pure water costs, WAPA has included a second credit to the water

department LEAC. This is a charge for production of water from the RO units on both

Islands for the benefit of the generating plants to the benefit of electric consumers. While

WAPA has provided a credit to the water department for the production of this water, it

again failed to charge electric consumers in its LEAC request for the electric department.

GCG believes that this expense is appropriately charged to the electric department and

has included additional costs in its update of the WAPA LEAC electric department. A

more detailed explanation may be found in the discussion of this matter contained in the

narrative described the water department contained below. Consistent with the above we

recommend that the debits and credits for the periods should be reviewed in the next

LEAC.

Plant Repair RO Contract

WAPA has also requested a third credit to the water department related to the installation

of the RO equipment on St Thomas. In the contract with Seven Seas, it was requested

that the water intake valves of the generating units be repaired or replaced. This charge

should be the responsibility of electric consumers. GCG has included these costs as

estimated by WAPA. WAPA has not provided work papers showing how this was

calculated and we recommend that the PSC should require work papers before its next

LEAC petition is filed. Consistent with the above we recommend that the debits and

credits for the periods should be reviewed in the next LEAC.

Rate Financing Mechanism

Rate Financing Mechanism (RFM) costs of $4.3 million is included in the cost of fuel for

this quarter. Annually this is a $17 million recovery. These costs reflect the: (i.) short-

term lease and operating costs exclusive of fuel of a trailer-mounted emergency

combustion turbine to provide reliable power, (ii.) deferred and extraordinary

maintenance, (iii.) spare parts for existing generating units, and (iv.) the services of an

Independent Advisory Contractor (IAC) to assist WAPA in restoring its existing

generation to a reliable and efficient state of operations. The costs has been computed as

the product of 2.3 cents and kWh sales. WAPA has been recovering these costs

beginning in April 2012, according to the LEAC workbooks for Fiscal 2012 and Fiscal

2013.

The RFM, a temporary power plant maintenance funding allowance, was agreed upon by

prior Stipulation between WAPA and the PSC Staff on September 27, 2011 and

20

subsequently approved by the PSC Order.9 It was estimated that at the time of PSC

approval of the RFM mechanism that consumers would obtain an economic benefit of no

less than $50 million annually through more efficient operation of WAPA generating

units. Pursuant to PSC Order the RFM funds collected from consumers by WAPA can

only be used to pay the leasing, operating and maintenance costs of the GE trailer

mounted (TM 2500) emergency generating unit, the systematic completion of the

rehabilitation and chronic deferred maintenance of certain WAPA generating units, the

acquisition of spare parts, and the services of an Independent Advisory Contractor (IAC),

an expert in the maintenance and efficient operation of generating units. The total RFM

revenue component approved in the PSC order accepting the Stipulation was based on the

product of 2.3 cents per kWh times the then current kWh sales forecast. An RFM

component of the LEAC has been included in all LEAC rates since April 1, 2012. Under

the terms of the Stipulation, the PSC is to approve the inclusion of the RFM component

in each quarterly LEAC based upon its review and approval of specific information

provided by WAPA pursuant to the Stipulation concerning, among other things, the

proposed uses of the funds and benefits to be derived by consumers.

The leased unit (also referred as “Unit 25”) is one of the authorized uses of funding

through the RFM. Unit 25 has been in operation since late May 2012 and has been

operating at an efficiency level of approximately 11,700 BTU/kWh and a 63% utilization

factor since that time. Unit 25 operates more efficiently than any of WAPA’s other

combustion turbines and is contributing to improving performance of St. Thomas power

production. The availability of this unit is a significant factor in the abrupt and modest

improvement in the St. Thomas plant’s fuel efficiency in the June timeframe, shown in

Figure 6 above. Also, the emergency leased unit allows WAPA to have available the

capacity to perform vital and crucial maintenance on its other St. Thomas facilities for the

purpose of improving unit availability and performance—the primary purpose of WAPA

acquiring the emergency unit.

The September 27, 2011 Stipulation and subsequent Commission Order approved the

RFM as a temporary “supplemental” financing source. The RFM was approved to

provide WAPA a source of funding so that consumers could be assured of near- and

long-term benefits. These consumer benefits are to be measured by the PSC using

specific benefit-cost assessment metrics that target improvements to WAPA production

efficiencies and improvements to allow its facilities to provide a continuous and

uninterrupted supply of electricity. The Order requires that WAPA timely provide

certain information concurrent with its quarterly LEAC Rate filings to the PSC. The

RFM component included as part of any LEAC rate is to be specifically ordered quarterly

by the PSC. The amount of the RFM authorized by the PSC for inclusion in the LEAC

rate shall only be used for specifically “authorized” emergency power, generation

maintenance management activities, performance improvements, and spare parts. The

9 PSC Order 02/2012, dated October 25, 2011.

21

authorized uses of these RFM funds may be amended by the PSC at any time—ideally

concurrent with the setting of a new LEAC Rate.

As an accountability measure for the PSC, concurrent with every future quarterly LEAC

rate filing, the prudence and applicability to the FMP funding mechanism, should be

quantitatively supported, since the rate setting responsibility of the Commission requires

review of the status of RFM activities. For the PSC to meet its obligation authorizing the

amount of the RFM in each LEAC Rate cycle, WAPA is required to provide the PSC

certain quarterly RFM information which the PSC will consider in its LEAC rate

deliberations. Pursuant to Commission order approving the Stipulation, WAPA is

required concurrent with each LEAC filing to support the PSC’s inclusion of a RFM

amount in the LEAC Rate. The following is a list of these requirements to which WAPA

has agreed and the PSC approved:

1. An 18-month forward look at WAPA demand and resource balance which will

identify WAPA’s projected available generating capacity and surpluses or

(deficits) for St. Thomas/John district. Albeit late information provided. Without

any explanation the information shows that WAPA is apparently planning on

keeping the emergency unit well past the 18-month lease period.

2. An 18-month forward look at the estimated expenditures that WAPA request be

approved by the PSC for funding with the RFM supplemental financing

component included in the LEAC Rate. The 18-month forward looking list of

expenditures is to include the proposed activities that WAPA proposes the PSC

approve funding in the current LEAC rate as related to emergency generation,

performance and capital improvement projects, deferred preventative

maintenance, purchasing spare parts, and the IAC. Albeit the information was

provided late, we would note the information is sparse and does not reflect what

we would consider a reasonable level of rehabilitation and maintenance activity.

3. A detailed financial report providing the PSC monthly derived RFM revenues, a

summary of all authorized Commission expenditures incurred, and the monthly

ending balances in the RFM fund. All financial activities are to be held in a

separate account. No financial report was provided to the PSC.

4. A detailed analysis of the economic and other benefits to be derived by

residential, business, and government consumers as a result of the proposed

emergency generation, performance of critical deferred maintenance, and the

inclusion of the RFM in LEAC Rates. The analysis is to show for each facility its

estimated operating hours, available capacity, power production, unit efficiency,

fuel use and fuel costs. This analysis was originally to be provided to the PSC in

November 2011—it was not—and is to be updated with each quarterly LEAC

Rate filing. This element is critical since the RFM concept is based upon WAPA

providing benefits in excess of the RFM costs. To date, actual St. Thomas

performance data for 2012 does not support a reasonable level of benefits

22

necessary to justify the level of RFM funding being provided. Hopefully, this

situation will improve.

5. Status of the implementation of a comprehensive and sustainable maintenance

management protocol (MMP) which is to be completed no later than December

31, 2012. No updated information was provided.

Following the Commission September 24, 2012 Order, WAPA did make progress in

providing the quarterly information and reports required by the Stipulation and for the

PSC to continue the funding of the RFM component of the LEAC Rate. For instance, it

made a filing on October 24, 2012 which addressed the reporting activities required by

the Stipulation. However, this is now the fifth LEAC Rate proceeding since the

Stipulation was approved by the PSC and the third LEAC Rate proceeding since the PSC

authorized WAPA to begin collecting RFM revenues as part of the LEAC rate and once

again WAPA has not addressed, concurrent with its current LEAC rate filing, each of the

activities required quarterly by the Stipulation, nor has it made any meaningful progress

in complying with the IAC requirements outline in Attachment 6 to the Stipulation.

Lastly, the RFM temporary funding mechanism established by the PSC requires

accountability, public transparency, and rate setting assessment. To those ends, WAPA

should retain an IAC specializing in power generation who shall provide technical

expertise in the oversight, review and reporting on critically deferred maintenance,

performance and capital improvement projects, and the overall efficiency and reliability

of power plant facilities. At WAPA’s request, on July 17, 2012 the PSC staff provided

WAPA with a detailed IAC work scope for use in the IAC procurement process.

Subsequently, an extended conference call was held to walk through the draft work scope

at which time WAPA indicated it would respond with its comments in writing within a

brief period of time. WAPA continues to indicate that the IAC can have no operating

authority; however, it is understood by the PSC staff that the IAC shall have no

operating responsibilities. This understanding was written into the first draft work

scope provided by the PSC staff. The obligations, duties, and reporting responsibilities of

the IAC are outlined in Attachment 6 of the Stipulation approved by PSC Order. No

progress has been made in securing an IAC.

The parties have held no discussions since the update provided in our previous LEAC

report; however, the parties have agreed to meet on December 17, 2012 for the purpose

of discussing this matter. This matter needs to be resolved at the earliest date since

currently the PSC has no independent means by which it can assure consumers the

accountability, public transparency and assessment that the funds collected are be used

for the purposes granted.

The PSC should consider the failure of WAPA to comply with conditions of its previous

Order concerning the deficiencies in WAPA’s compliance with the quarterly filing

requirements and retention of an IAC when deliberating on its LEAC Rate request for the

23

January through March 2013 period and GCG recommends that the PSC indicate that if

it does not receive an RFP with the appropriate scope as defined in Attachment 6 to the

Stipulation that continuation of the RFM could be deferred until the document is received

and all other requirements of the RFM are current.

Under-Recovery Amortization

In the original filing, WAPA estimated that there will exist an under-recovery balance as

of December 31, 2012 of $26.8 million (over and above the GO note amortization) for a

total of $33.9 million. WAPA proposes to amortize (collect) the under-recovery balance

not financed with the GO note over a period of twelve months ending December 2013 at

a rate of $2.2 million per month. We have accepted the proposed amortization period for

recovery of this deferred fuel expense.

As the Commission is well aware, there has never been a full reconciliation between the

deferred fuel expense on the books of WAPA and the deferred fuel expense in the LEAC,

although an audited adjustment was made for Fiscal 2010 and Fiscal 2011. The electric

department unaudited financial statements for September 2012 show a deferred fuel

balance (current and non-current) of nearly $50 million. The LEAC balance (including

the GO financing) shows a deferred fuel balance of $31.5 million.

Through the discovery process and conferences, WAPA has acknowledged that another

accounting entry needs to be made and has provided a sample journal of proposed

accounting entries to correct this problem. Although management states that once these

entries are made for Fiscal 2012 audit and similar adjustment are made for the months

subsequent to June 2012, the accounting balance and LEAC deferred fuel balances will

be identical, no data has been provided. As of this report, GCG does not know whether

these adjustments impact the earnings of WAPA as did occur in the aforementioned

adjustments for Fiscal 2010 and Fiscal 2011. Once the entry has been made and the

balance of deferred fuel expense are in “sync,” GCG recommends that WAPA should

provide the PSC the impact(s) of these adjustments will a full explanation of any impacts

related to those entries for Fiscal 2012 and Fiscal 2013.

Sales, Losses and Uses

The projection of sales, losses and uses are provided in the LEAC Schedule 4.1

workbook. For the Electric Department WAPA projects a line loss percent of 8.3% on St

Thomas and 7.6% on St Croix. These amounts are greater than the 6.6% line loss

standard the Commission set in 2005 for WAPA to achieve by 2009. In addition, the

Commission approved in Docket No. 575 a line loss surcharge for the purpose of

reducing line losses to the standard established by the Commission. In Docket 575, the

Commission awarded WAPA a specific surcharge for a program to reduce line losses of

$0.00291 per kWh. This surcharge went into effect on July 1, 2009 and has continued in

place since that time. The cash from this surcharge is to be solely used for projects

designed to reduce the level of line loss which would in turn reduce the level of oil

24

required to produce enough generation to meet demand. To date, losses have not been

reduced to the standard set by the Commission. Meanwhile, the Commission has allowed

WAPA to collect millions of dollars in a line loss surcharge for the purpose of reducing

line loss to this level. In spite of these factors, we have accepted the loss percentages

used by WAPA in its LEAC filing. However, we recommend that WAPA be required to

provide the Commission:

1. A complete reconciliation of the revenues and reserves from the Line Loss

Reduction Surcharge and the intended use of those funds no later than February

15, 2013.

2. A plan demonstrating the activities, milestones, and interim performance levels

showing its approach to achieving a loss level of 6.6% no later than February 15,

2013

3. If such information is not provided on the date recommended, we recommend that

the line loss surcharge be suspended.

25

III. WATER DEPARTMENT

WAPA also filed for a change in its WLEAC for water consumers. WAPA assumptions

deriving the WLEAC concludes that water LEAC rates should be increased from $11.14

per kGal to $13.72 per kGal for an overall bill increase $6.18 for a residential consumer

using 2400 kGal per month or about 7.9% of average monthly bill. The following table

shows the computation of the proposed WLEAC rate and compares that to GCG update

of the filing:

Table 4

WAPA LEAC-Water

($000’s)

WAPA

GCG

As Filed

As Updated

($000s)

($000s)

A Cost of Fuel $ 2,224

$ 2,190

B P&I on New 4-Yr GO Note 594

594

C RO Lease Costs 1,374

1,374

D Elect. Charge Water 1,210

1,210

E Ultra Pure Water Charge (255)

(255)

F Water Production Charge/RO (358)

(358)

G Plant Repair RO Contract (60)

(60)

H Docket 289 Costs 0

20

Sub-Total $ 4,729

$ 4,715

I Base Rate Recovery (913)

(913)

Current LEAC Costs $ 3,816

$ 3,801

J Deferred Fuel Costs 535

800

TOTAL Costs $ 4,350

$ 4,601

Total kGal (000) 317,153

317,153

Proposed WLEAC Factor $ 13.72

$ 14.51 /kGal

Current WLEAC Factor $ 11.14

$ 11.14 /kGal


$ 3.37 /kGal

2,400

2,400 Gal


$ 8.08

Current Average Bill $ 78.60

$ 78.60

Percent Increase 7.9%

10.3%

Cost of Fuel

WAPA projects that the cost of fuel for the three month period ending March 2013 is

$2.2 million. The cost of fuel is allocated using an algorithm established decades earlier.

Within the spreadsheets of the LEAC fuel allocation is basically a “black box.” Our

26

understanding is that WAPA generally applies experienced fuel allocation from historic

periods for forecasting purposes. There is no specific methodology within the LEAC

spreadsheets that could be easily adjusted for differing forecast techniques. As discussed

in the electric department testimony, this cost of fuel is for the operation of the IDE

plants that for the LEAC period will produce approximately 1.5 million GPD at a cost

that is approximately three times higher than the actual RO cost. It is recommended that

a transfer of the temporary RO equipment on St. Thomas to St. Croix be evaluated. The

transfer of equipment from St. Croix to St. Thomas when there was a water emergency

was accomplished in a very short period of time. It is recommended that the PSC require

such an analysis from WAPA by January 31, 2013.

RO Costs

WAPA now has three RO units in operation under two separate contracts on both St

Thomas and St Croix. WAPA has included the payments to Seven Seas (the owner and

operator of the units) as a cost to be recovered from water consumers in the LEAC. The

total costs included in the three month forecast is $1,374,000. To make this forecast,

WAPA assumes that the St Thomas and St Croix units will be fully operational producing

water for consumers at a rate of approximately 1.2 million gallons per day (MGD) on St

Croix and 2.1 MGD on St Thomas. At a purchase rate from Seven Seas of $3.43 per

kGal on St Croix and $4.77 per kGal on St Thomas, this results in a total monthly charge

of $261 thousand and $337 thousand per month for St Croix and St Thomas, respectively.

These amounts are consistent with the historic production and costs of both units and we

have accepted these projections.10

The PSC has approved inclusion of these costs in the

WLEAC in the past. At the time of the initial operations, these incremental costs were

not a component of base rates.11

Electricity Charged Water

WAPA has introduced a new item for which it seeks recovery from the water consumer.

WAPA has included $1.2 million of costs to be recovered from the consumer for the

electricity used in the production of water through RO that is not paid for by Seven Seas.

To estimate this amount, WAPA assumes a rate of $0.32 per kWh on both an actual (July

2012 through December 2012) and forecasted basis (January 2013 through March 2013).

In the filing, WAPA assumed that this new cost would be effective January 1, 2012.

Later discussions with WAPA indicated that it wished to institute this new collection

effective July 1, 2012. Once this change in assumptions is adjusted the net effect was to

increase the deferred fuel balance for the water department as of June 30, 2012.

WAPA management decided to implement this effective July 1, 2012. WAPA no longer

received compensation directly from Seven Seas related to the electricity required to

10 While we have accepted the forecast given the limited time to evaluate, we need further discussion of the actual way to present costs in future LEACs. 11 When reviewing the calculations on Schedule 7 to determine these costs, WAPA noticed that it had some

programming errors on Schedule 7. We have made the corrections.

27

produce water from the RO system. Under the new contract, WAPA is responsible for

the provision of electricity for the production of water. WAPA measures the usage

required by these units and prices that usage at a rate of $0.32 per kWh. WAPA has

stated that this rate was internally derived by taking the total production costs

(predominantly fuel without any allowance for plant O&M expenses) and dividing by the

total gross generation at the plant using Fiscal 2012 to determine that amount. The PSC

should require that WAPA provide the calculations of this rate. WAPA is proposing to

recover the costs of the additional electricity from the water department. WAPA

proposes that this recovery begin July 1, 2012. To estimate these costs for the LEAC

period ending March 2013, WAPA estimates the total electricity provided to produce

both potable and ultra-pure water and multiplies that total by the $0.32 per kWh. We

agree in concept to the general principles of this adjustment and have accepted the

adjustment from July 1, 2012, but believe that some adjustment may be required for the

year ending June 2012 depending upon when the cessation of payment by Seven Seas

occurred for each Island.

Amount Billed for Ultra-Pure Water

In the RO contract on St Thomas is a provision for the production of “ultra-pure” water

which is used as feed water in the production of electricity from the steam units on St

Thomas. WAPA is proposing to credit water consumers for this cost since this is

included in the total cost of water produced and should properly be a charge to electric

consumers only. For the LEAC period, WAPA proposes to credit the WLEAC $255

thousand based upon the forecasted production of ultra-pure water. To calculate and

estimate the cost of this item, WAPA uses contractual terms that require that Seven Seas

produce a minimum of 12.5 million gallons on the first pass and 2.5 million gallons on

the second pass. This is “priced out” at a rate of $032 per kWh. The amount is just

coincidental to the electric charge of $0.32 per kWh, but is per kGal. The total amount is

then credited to the water department, and we have included these costs in the electric

department LEAC on both an actual and forecasted basis.

Electric Plant Internal Use of Water

WAPA is proposing to credit the water customer a total of $358 thousand for water

produced on St Thomas that is used in the operations of the plant and according to

WAPA would be appropriately charged to the electric department. This is a water

production cost for the amount of production as opposed to the electricity required, which

was described as Ultra-Pure Water.

Plant Repair Intake Valve

WAPA is proposing to further credit water consumers another $60 thousand for Amount

Billed Electric Station #2. This is neither an electricity usage charge nor water

production direct charge. WAPA has informed us that during the installation process

Seven Seas was required to repair and replace the water intake valves on the St Thomas

power plant. WAPA estimates the value of this additional service and has amortized

over a period of time. This is truly an electric production costs and as such we have

28

accepted this credit and have include the costs in the adjusted electric LEAC factor, but

WAPA should provide appropriate work papers and explanation.

Under-Recovery

As with the electric department, the deferred fuel expense shown on the LEAC summary

should mirror the book balance in every month (or at least be able to be reconciled). This

again is not the case. WAPA originally projected an under-recovery of about $1 million

(net of the GO financing) for the period ending December 31, 2012 which it is proposing

to amortize over the next six-months. While we have accepted the amortization period,

the opening balance of deferred fuel beginning July 2012 has been adjusted to reflect the

credit for electricity that was originally in the Fiscal 2012 water LEAC, which reduced

the opening balance of deferred fuel expense as of July 1, 2012. To reflect

management’s decision to begin this credit effective July 1, 2012, we have reversed those

credits in Fiscal 2012 as did WAPA in its revised Fiscal 2012 reconciliation, but reserve

the right to review these credits as indicated earlier.

29

IV. RECOMMENDATION AND PROPOSED ORDER

As a result of our investigation into this filing and for reasons presented herein, our

recommendations are that:

1. A LEAC rate of $ 0.407847 per kWh should be set for the Electric Department.

2. A WLEAC rate of $14.51 per KGal should be set for the Water Department.

3. WAPA should provide all MFR requirements for future quarterly LEAC filings

including the expanded requirement to provide information regarding billing and

collection activity and outstanding balances for the previous two quarters for all

accounts government and non-government by customer class (MFR5);

4. WAPA should provide a detailed and fully transparent narrative to accompany each

LEAC filing describing the request in detail and highlighting the reasons for

underperformance or better than expected performance of the generating units and the

resultant fuel costs. The complete filing including all MFRs should be filed no later

than the 15th day of the second previous month from the initiation of the proposed

LEAC. It is further recommended that a delay or incomplete filing should result in

the day-for-day delay of the implementation of the requested new LEAC factor as

determined by the PSC.

5. The PSC should require that a proposed RFP for the IAC consistent with the

requirements of Attachment 6 to the RFM Stipulation, and produced in collaboration

with the PSC staff, should be filed no later than January 31, 2103. In the absence of

such a filing the PSC should consider suspending implementation of the RFM until a

satisfactory document is filed.

6. WAPA be required to provide a complete reconciliation of the revenues and reserves

from the Line Loss Reduction Surcharge and the intended use of those funds no later

than February 15, 2013. WAPA should include a plan no later than February 15,

2013 demonstrating the activities and interim performance levels showing its

approach and milestones to achieving a loss level of 6.6%. If such information is not

provided we recommend that the line loss surcharge be suspended.

7. WAPA should provide an analysis to support the continuation of the IDE units into

calendar year 2013 and why the temporary units on St. Thomas should not be

deployed to St. Croix.

8. WAPA should provide a full reconciliation of all the appropriate credits and debits

related to the production of RO water from the inception of the new contracts on each

Island by January 31, 2013.

9. WAPA should file a full report showing the full reconciliation of the deferred fuel

accounts on its books and the deferred fuel accounts used in the LEAC calculations

by January 31, 2013. All adjustments related to reconciliation should be provided.

10. WAPA shall provide the Commission no later than January 31, 2013 the tactical and

logistical implementation plans and measures it will take to achieve the five fuel

30

diversification and energy efficiency strategies recently adopted by its Board, as well

as the milestones for implementation.

11. The PSC staff shall be required to include on its website the following:

WAPA power production efficiency figures showing projected and actual

monthly power plant efficiency and availability for no less than 12-months.

Summary of RFM improvements currently underway and projected as well as a

forecast of performance benefits of such improvements.

Appropriate links, if any, to WAPA’s website on matters dealing with power and

water costs, service improvements and operating performance.

The staff shall be responsible for updating this information monthly.

12. The effective date for the approved electric and water system LEAC rates shall be the

later of January 1, 2013 or the date upon which WAPA becomes current (to within 30

days of invoices received for administrative assessments and 60 days for docket

specific assessments) on all Commission administrative and docket specific

assessments.

The Virgin Islands Water and Power Authority

LEAC Projection for Fiscal 2013EXHIBIT A 1 January LEAC

1 Increase Deferred Fuel Balance (Water) for Removal of Credits For Electricity in FY12

2 Correct Programming Errors on Schedule 7 and Schedule 3

3 Debit and Credit Electric Department for Items Adjusting Water Department

3 Adjust Deferred Fuel Expense (Electric) to reflect Item #3 (Auto)

5 Update Price Forecasts for January through March 2013

6 Allocate a Portion of Regulatory Expense to Water Department

7 Adjust November and December Production on STX to meet demand

Adjustments:

VIRGIN ISLANDS WATER AND POWER AUTHORITY

Summary of LEAC - Electric Department

Schedule 1

Page 1 of 2

Six Months Partial Six Months

Actual Actual Actual Forecast Forecast Forecast Per. Ending Forecast Forecast Forecast Forecast Forecast Forecast Per. Ending TOTAL

Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jun-13 FY2013

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p)

Energy Sales:

1 St. Croix.....Mwh 24,949 24,917 23,346 24,599 23,221 23,995 145,027 23,995 21,673 23,995 23,221 23,995 23,221 140,100 285,127 Schedule 3, page 1

2 St. Thomas....Mwh 39,432 36,885 36,856 35,523 37,188 38,428 224,312 38,428 34,709 38,428 37,188 38,428 37,188 224,370 448,683 Schedule 2, page 1

3 Total Sales....Mwh 64,382 61,802 60,201 60,122 60,409 62,423 369,340 62,423 56,382 62,423 60,409 62,423 60,409 364,470 733,810 Line 1 + Line 2

Cost of Fuel:

4 St. Croix.......$ 7,132 8,786$ 7,977$ 8,547$ 8,897$ 9,056$ 50,395$ 8,156$ 6,036$ 6,703$ 7,401$ 7,695$ 8,089$ 44,080$ 94,475$ Schedule 3, page 1

5 St. Thomas......$ 10,715 12,047 11,255 13,119 15,005 15,209 77,350 14,625 13,504 14,050 14,233 14,908 14,288 85,608 162,958 Schedule 2, page 1

6 Total Fuel Cost 17,847$ 20,833$ 19,232$ 21,666$ 23,902$ 24,265$ 127,745$ 22,781$ 19,540$ 20,753$ 21,634$ 22,603$ 22,377$ 129,688$ 257,433$ Line 4 + Line 5

8 Regulatory Expenses 0 0 0 13 13 13 40 13 13 13 13 13 13 80 120 Footnote 2

9 Current Fuel Costs 17,847$ 20,833$ 19,232$ 21,679$ 23,915$ 24,278$ 127,785$ 22,794$ 19,553$ 20,766$ 21,647$ 22,616$ 22,390$ 129,768$ $257,553 Sum (L6-L8)

Non-Fuel Expense Items in Factor (Current)

10 Refinanced GO Note Principal & Interest 677 677 42 42 42 42 1,522 42 42 42 42 42 42 251 1,774 Schedule 6

11 Regulatory Asset @ 72k per month 72 72 72 72 72 72 429 72 72 72 72 72 72 429 859 PSC Order #31/2010

12 Less PILOT refund @ 124k per month (124) (124) (124) (124) (124) (124) (744) - - - - - - - (744) PSC Order #31/2010

13 Rate Financing Mechanism (.023 per kwh) 1,481 1,421 1,385 1,383 1,389 1,436 8,495 1,436 1,297 1,436 1,389 1,436 1,389 8,383 16,878 PSC Order #02/2012

14 Electricity Charged Water (Fuel) (338) (194) (294) (322) (400) (401) (1,949) (403) (403) (403) (403) (403) (403) (2,420) (4,369) Schedule 7

15 Ultra Pure Water Charge 70 53 50 52 67 72 365 85 85 85 85 85 85 511 876 Schedule 7

16 Water Procuction Charge/RO 98 75 71 73 94 101 512 119 119 119 119 119 119 716 1,228 Schedule 7

17 Plant Repair RO Contract 19 19 16 18 20 20 113 20 20 20 20 20 20 119 232 Schedule 7

18 Over/Under recovery{Note 1} - 2,276 2,276 2,276 2,276 2,276 2,276 13,655 13,655 Footnote 1

19 Total Cost to be Recovered 19,803$ 22,832$ 20,450$ 22,873$ 25,075$ 25,495$ 136,528$ 26,440$ 23,061$ 24,412$ 25,247$ 26,262$ 25,990$ 151,413$ 287,941$ Sum (L10-L18)

20 Quarterly LEAC Factor..($/Kwh) 0.306524 0.383234 0.407847 0.422937 LEAC FACTORS

21 LEAC Factor Recovery 19,735$ 18,944$ 18,453$ 23,041$ 23,151$ 23,923$ 127,246$ 25,459$ 22,995$ 25,459$ 25,549$ 26,401$ 25,549$ 151,413$ 278,659$ Line 3 x Line 16

22 Debt Service Recovery (677) (677) (42) (42) (42) (42) (1,522) (42) (42) (42) (42) (42) (42) (251) (1,774) Line 10

23 Regulatory Asset & PILOT 52 52 52 52 52 52 315 (72) (72) (72) (72) (72) (72) (429) (115) Line 11 + Line 12

24 Electricity Charged Water 338 194 294 322 400 401 1,949 403 403 403 403 403 403 2,420 4,369 Line 14

25 Ultra Pure Water Charge (70) (53) (50) (52) (67) (72) (365) (85) (85) (85) (85) (85) (85) (511) (876) Line 15

26 Water Procuction Charge/RO (98) (75) (71) (73) (94) (101) (512) (119) (119) (119) (119) (119) (119) (716) (1,228) Line 16

27 Plant Repair RO Contract (19) (19) (16) (18) (20) (20) (113) (20) (20) (20) (20) (20) (20) (119) (232) Line 17

28 Rate Financing Mechanism (.023 per kwh) (1,481) (1,421) (1,385) (1,383) (1,389) (1,436) (8,495) (1,436) (1,297) (1,436) (1,389) (1,436) (1,389) (8,383) (16,878)$ Line 13

29 Adjustments (2) (3) (10) (15) Input

30 Net LEAC Recovery (Fuel) 17,777$ 16,942$ 17,226$ 21,847$ 21,991$ 22,706$ 118,488$ 24,089$ 21,764$ 24,089$ 24,225$ 25,031$ 24,225$ 143,423$ 261,912$ Sum(L21+L29)

31 (Over)/Under Recovery - Fuel only 70$ 3,891$ 2,006$ (168)$ 1,924$ 1,573$ 9,296$ (1,294)$ (2,211)$ (3,322)$ (2,578)$ (2,414)$ (1,835)$ (13,655)$ (4,359)$ Line 9 - Line 30

32 Deferred Fuel Balance (Open) 26,547 18,084$ 21,975$ 23,982$ 23,814$ 25,738$ 27,310$ 26,016$ 23,805$ 20,483$ 17,905$ 15,490$ Line 32 prior month

33 Monthly (Over)/Under 70 3,891 2,006 (168) 1,924 1,573 (1,294) (2,211) (3,322) (2,578) (2,414) (1,835) Line 31

34 Loan on Deferred Fuel-Open (8,533)

35 Additional due WAPA (Customer) 18,084$ 21,975$ 23,982$ 23,814$ 25,738$ 27,310$ 26,016$ 23,805$ 20,483$ 17,905$ 15,490$ 13,655$

36 Unamortized Loan Balance 7,902 7,269 7,234 7,200 7,166 7,132 7,098 7,064 7,029 6,995 6,960 6,925 Schedule 6

37 Total Due WAPA (Deferred Fuel) 25,986$ 29,244$ 31,216$ 31,014$ 32,904$ 34,443$ 33,114$ 30,869$ 27,512$ 24,899$ 22,450$ 20,580$ L17+L18

NOTE: 1

C:\Users\Larry Gawlik\Documents\1Larry's Business Files\Georgetown\4Virgin Islands\2012 Activities\Jan - Mar 13 LEAC\GCG Analysis\final\Final Report\12 12 15 Fiscal 2013_GCG_As Filed


Water LEAC Calculations

Schedule 1

Page 2 of 2

Six Months Six Months




Water Sales

1 St. Croix.....kGal 53,946 57,435 56,585 65,268 55,546 57,398 346,178 57,398 51,843 57,398 55,546 57,398 55,546 335,129 681,307 Schedule 4, page 2

2 St. Thomas....kGal 42,476 66,084 50,200 40,017 50,171 51,844 300,792 51,844 46,827 51,844 50,171 51,844 50,171 302,700 603,493 Schedule 4, page 2

3 Total Sales....kGal 96,421 123,519 106,785 105,285 105,718 109,242 646,970 109,242 98,670 109,242 105,718 109,242 105,718 637,830 1,284,800 Line 1 + Line 2

Cost of Fuel:

4 St. Croix.......$(000) 317$ 326$ 365$ 323$ 375$ 382$ 2,089$ 340$ 259$ 287$ 309$ 321$ 337$ 1,852$ 3,941$ Schedule 3

5 St. Thomas......$(000) 543 423 215 396 464 470 2,512 452 418 435 440 461 442 2,648$ 5,159 Schedule 2

6 Total Fuel Cost 860$ 749$ 579$ 720$ 839$ 852$ 4,600$ 792$ 676$ 721$ 749$ 782$ 779$ $4,500 $9,100 Line 4 + Line 5

7 Allocated 289 Costs 0 0 0 7 7 7 20 7 7 7 7 7 7 41 61 Schedule 1.1

8 Cost of Purchased Water (STX) 103 94 100 99 120 120 636 121 121 121 121 121 121 726 1,362 Schedule 7

9 Cost of Purchased Water (STT) 319 311 261 300 328 331 1,851 337 337 337 337 337 337 2,022 3,873 Schedule 7

Electricity Charge (STX-STT) 338 194 294 322 400 401 1,949 403 403 403 403 403 403 2,420 4,369Less: Amt. billed for Electricity Used for Ultra Pure

Water (70) (53) (50) (52) (67) (72) (365) (85) (85) (85) (85) (85) (85) (511) (876)

Less: Amt. billed Electric for Internal Plant Use (98) (75) (71) (73) (94) (101) (512) (119) (119) (119) (119) (119) (119) (716) (1,228)

Less: Amt. billed Electric for STT Station #2 (19) (19) (16) (18) (20) (20) (113) (20) (20) (20) (20) (20) (20) (119) (232)

10 Adjustment 0 0 Input

11 Total Costs 1,432$ 1,202$ 1,097$ 1,304$ 1,513$ 1,518$ $8,067 1,436$ 1,320$ 1,365$ 1,393$ 1,426$ 1,423$ 8,362$ 16,429$ Sum (L6-L10)

12

Base Rate Recovery 278 356 308 303 304 315 1,863 315 284 315 304 315 304 1,837 3,700 Line 3 x 2.88

13 $2.88

14 Unrecovered Costs-Fuel & PW 1,154$ 846$ 790$ 1,001$ 1,209$ 1,204$ 6,204$ 1,121$ 1,036$ 1,050$ 1,088$ 1,111$ 1,119$ 6,525$ 12,729$ Line 12 - Line 13

15 Refinanced GO Note Principal & Interest 82 82 198 198 198 198 956 198 198 198 198 198 198 1,188 2,144 Schedule 6

16 Over/Under recovery - 267 267 267 267 267 267 1,599 1,599 See Footnote

17 Total Costs 1,236$ 928$ 988$ 1,199$ 1,407$ 1,402$ 7,160$ 1,586$ 1,500$ 1,515$ 1,553$ 1,576$ 1,583$ 9,313$ 16,473$ SUM(L14-L17)

18 Quarterly LEAC Factor..($/Kgal) $8.29 $11.14 $14.51 $14.69 LEAC Factors

19 LEAC Factor Recovery 799$ 1,024$ 885$ 1,173$ 1,178$ 1,217$ 6,276 1,585$ 1,431$ 1,585$ 1,553$ 1,605$ 1,553$ 9,313 15,589 Line 3 * Factor

20 Base Rate Recovery 278 356 308 303 304 315 1,863 315 284 315 304 315 304 1,837 3,700

21 Less Debt Service Recovery (82) (82) (198) (198) (198) (198) (956) (198) (198) (198) (198) (198) (198) (1,188) (2,144) Line 15 + Line 6

22 Less Regulatory Expense - - - - - -

23 Less Cost of Purchased Water (572) (453) (518) (578) (668) (659) 3,447 (637) (637) (637) (637) (637) (637) 3,822 7,268

24 Adjustments (13) 0 (0) (13) - - (13)

25 Net LEAC Recovery-Fuel 410$ 845$ 477$ 700$ 617$ 674$ 1,064$ 881$ 1,064$ 1,023$ 1,085$ 1,023$ 13,783$ 24,400$ SUM(L21-L23)

26 (Over)/Under Recovery 450$ (96)$ 103$ 20$ 223$ 178$ $877 (272)$ (204)$ (343)$ (274)$ (303)$ (243)$ Line 18 - Line 23

27 Beginning Balance 3,924$ 1,172$ 1,077$ 1,179$ 1,199$ 1,421$ 1,599$ 1,327$ 1,123$ 779$ $506 $203 Line 28 (prior Column)

28 Monthly (Over)/Under 450 (96) 103 20 223 178 (272) (204) (343) (274) (303) (243) Line 24

29 Loan on Deferred Fuel (3,202) Schedule 6

30 Add'l Due to WAPA/(Customer) 1,172$ 1,077$ 1,179$ 1,199$ 1,421$ 1,599$ 1,327$ 1,123$ 779$ 506$ 203$ (40)$ Sum (Line 27 - Line 29)

31 Unamortized Loan Balance 3,125 3,048 2,884 2,725 2,565 2,404 2,243 2,082 1,916 1,753 1,588 1,423 Schedule 6

32 Total Due WAPA (Deferred Fuel) 4,298$ 4,125$ 4,063$ 3,923$ 3,987$ 4,003$ 3,570$ 3,205$ 2,695$ 2,259$ 1,791$ 1,383$ Line 30 + Line 31

Beginning Balance 4,003$ Less: Loan on Under-recovery (2,404)

Additional Under-recovery 1,599$

Amortization Period (mos) 6

Monthly Amortization 267$

C:\virgin\wapa\dkt289 December 2003\S1.2\S1.2 -Water Summary


ST THOMAS GENERATING UNITS

Schedule 2

Page1 of 2





Sales - Mwh 39,432 36,885 36,856 35,523 37,188 38,428 224,312 38,428 34,709 38,428 37,188 38,428 37,188 224,370 448,683

Net Available for Sales 40,523 39,954 37,090 35,526 40,275 41,618 234,985 41,618 37,590 41,618 40,275 41,618 40,275 242,993 477,978

Gross Generation-Mwh 43,053 41,859 38,997 41,027 43,175 44,614 252,725 44,614 40,297 44,614 43,175 44,614 43,175 260,489 513,214

Sum of Units 43,053 41,859 38,997 41,027 43,175 44,614 44,614 40,297 44,614 43,174 44,614 43,174

Diff (0) 0 0 0 0 0 0 (0) 1 0 1

Unit No. 13 - No. 6 Oil

1. Generation - Mwh 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2. Heat Rate 0 0 0 0 0 0 0 0 0 0 0 0

3. Heat Content / Bbl. 6.07 6.07 6.07 6.07 6.34 6.34 6.34 6.34 6.34 6.34 6.34 6.34

4. Fuel - Bbls. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0


5. Generation - Mwh - - 430 - - - 430 577 577 577 577 577 577 3,460 3,889

6. Heat Rate - - - - - - - - - - - -

7. Heat Content / Bbl. 6.071 6.071 6.071 6.071 6.34 6.34 6.34 6.34 6.34 6.34 6.34 6.34

8. Fuel - Bbls. 0 0 0 0 - - 0 - - - - - - 0 0

9 Total No. 6 Oil-Bbls. 0 0 0 0 0 0 0 - 0 0 0 0 0 0 0

Cost of Fuel Consumed -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$

10 Begin. Inv. - $/Bbl. 103.37$ 102.83$ 102.83$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$

11 Beginning Inv. - Bbls. 23,910.76 24,035.67 24,214.24 24,244 24,452 24,452 24,452 24,452 24,452 24,452 24,452 24,452

12 Beginning Inv. Cost 2,471,606$ 2,471,606$ 2,489,969$ 2,471,606$ 2,492,761$ 2,492,761$ 2,492,761 2,492,761 2,492,761 2,492,761 2,492,761 2,492,761

13 Purchases - Bbls. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

14 Deliv. Price-$/Bbl. 103.37$ 102.83$ 102.07$ 101.95$ 102.82$ 107.68$ 107.15$ 106.68$ 106.22$ 105.75$ 105.27$ 104.79$

15 Cost of Purchases -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -

Inventory Adjustment 125 178.57 29.94 207.51

$ Cost of Inventory Adjustment

16 Tot. Inventory Cost 2,471,606 2,471,606$ 2,489,969$ 2,471,606$ 2,492,761$ 2,492,761$ 14,890,310$ 2,492,761 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$ 14,956,568

Ending Inventory $ 2,471,606$ 2,471,606$ 2,471,606$ 2,471,606$ 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$ 2,492,761$

17 End. Inventory-Bbls. 24,035.67 24,214.24 24,244.18 24,452$ 24,452$ 24,452$ 24,452$ 24,452$ 24,452$ 24,452$ 24,452$ 24,452$

18 Inventory (wtd avg) 103.37$ 102.83$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$ 101.95$

% No. 6 allocated to Water 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Fuel Allocated to Water

19 Fuel - $ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$

20 Fuel - Bbls. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

21. Electric Usage - Bbls 0 0 0 - 0 0 0 0 0 0 0 0 0 0 0

22. Cost of No. 6 Oil -$ -$ -$ -$ -$ -$ -$ -$ - -$ -$ -$ -$ $0 $0

C:\virgin\wapa\Dkt289 December2003\S1.2\Schedule 2 - STT


ST THOMAS GENERATING UNITS

Schedule 2

Page2 of 2


Per. Ending Per. Ending TOTAL




23. Generation - Mwh 20,882 19,618 18,315 18,267 19,056 19,101 115,240 19,101 19,056 19,056 19,056 19,101 19,056 114,425 229,664

24. Heat Rate 14,052 14,856 14,261 14,912 14,752 14,752 14,752 14,752 14,752 14,752 14,752 14,752

25. Heat Content/Bbl. 5.90 5.91 5.86 5.82 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91

26. Fuel - Bbls. 49,702 49,308 44,569 46,841 47,569 47,681 285,672 47,681 47,569 47,569 47,569 47,681 47,569 285,640 571,311


27 Generation - Mwh 0 0 0 0 0 0 5,878 0 0 6,671 0 0 0 6,671 12,549

28 Heat Rate 0 0 0 0 12,882 12,882 12,882 12,882 12,882 12,882 12,882 12,882

29 Heat Content/Bbl. 5.90 5.91 5.86 5.82 5.93 5.93 5.93 5.93 5.93 5.93 5.93 5.93

30 Fuel - Bbls. 0 0 0 0 0 0 0 0 0 14,493 0 0 0 14,493 14,493

Unit No. 18 - No. 2 Oil HRSG

31 Generation - Mwh 13,840 13,292 12,676 8,594 11,508 11,511 71,421 11,511 11,508 11,508 11,508 11,511 11,508 10,051 81,472

32 Heat Rate 16,217 16,902 15,519 15,894 17,511 17,511 17,511 17,511 17,511 17,511 17,511 17,511 16,602

33 Heat Content/Bbl. 5.90 5.91 5.86 5.82 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91

34 Fuel - Bbls. 38,016 38,008 33,567 23,490 34,099 34,108 201,288 34,108 34,099 34,099 34,099 34,108 34,099 204,613 405,900

Unit No. 15 - No. 2 Oil HRSG

35 Generation - Mwh 0 0 0 5,166 5,808 7,200 18,174 6,623 6,623 0 5,231 6,623 5,231 30,332 48,507

36 Heat Rate 0 0 0 16,203 16,602 16,602 16,602 16,602 16,602 16,602 16,602 16,602

37 Heat Content/Bbl. 5.90 5.91 5.86 5.82 5.93 5.93 5.93 5.93 5.93 5.93 5.93 5.93

38 Fuel - Bbls. 0 0 0 14,394 16,256 20,151 50,802 18,538 18,538 0 14,641 18,538 14,641 84,895 135,696

Unit No. 14/12/7 - No. 2 Oil

39 Generation - Mwh 2,743 553 75 289 0 0 3,660 0 0 0 0 0 0 0 3,660

40 Heat Rate 17,437 17,054 18,905 18,380 19,678 19,678 19,678 0 14,895 14,895 14,895 14,895

41 Heat Content/Bbl. 5.904 5.911 5.860 5.815 5.910 5.910 5.947 5.930 5.930 5.930 5.930 5.930

42 Fuel - Bbls. 8,101 1,596 241 915 0 0 10,853 0 0 0 0 0 0 0 10,853

Unit No. LN 2500 - No. 2 Oil

Generation - Mwh 5,588 8,396 7,501 8,711 6,802 6,802 43,800 6,802 2,532 6,802 6,802 6,802 6,802 36,544 80,344

43 Heat Rate 11,718 12,123 11,504 11,794 11,600 11,600 11,600 11,600 11,600 11,600 11,979 11,561

44 Heat Content/Bbl. 5.90 5.91 5.86 5.82 5.91 5.91 - 5.91 5.91 5.91 5.91 5.91 5.91

45 Fuel - Bbls. 11,090 17,219 14,726 17,666 13,350 13,350 87,402 13,350 4,970 13,350 13,350 13,786 13,305 72,112 159,514

45 Total No. 2 Oil-Bbls. 106,909 106,131 93,104 103,306 111,275 115,290 636,016 113,677 105,176 109,512 109,660 114,113 109,615 661,752 1,297,768

Cost of Fuel Consumed 11,258,244$ 12,469,948$ 11,469,493$ 13,515,135$ 15,468,596$ 15,679,558$ 79,860,974$ 15,077,097$ 13,921,724$ 14,484,189$ 14,673,050$ 15,369,517$ 14,729,910$ 88,255,486$ 168,116,459$

46 Begin. Inv. - $/Bbl. 102.95$ 105.31$ 117.50$ 123.19$ 130.83$ 139.01$ 136.00$ 132.63$ 132.37$ 132.26$ 133.81$ 134.69$

47 Beginning Inventory - Bbls. 39,636 27,290.44 42,799 36,508 54,235 37,960 22,669 23,993 35,918 29,178 40,770 36,061

48 Beginning Inv. Cost 4,080,658$ 2,873,867$ 5,028,693$ 4,497,464$ 7,377,873$ 5,276,917$ 3,083,059$ 3,182,213$ 4,754,302$ 3,859,083$ 5,455,203$ 4,856,885$

49 Purchases - Bbls. 94,563 121,639 86,814 121,782 95,000 100,000 619,798 115,000 110,000 110,000 110,000 115,000 110,000 670,000 1,289,798

50 Deliv. Price-$/Bbl. 106.29$ 120.23$ 126.00$ 133.11$ 140.71$ 134.86$ 131.97$ 132.31$ 132.23$ 134.21$ 135.00$ 134.28$

51 Cost of Purchases 10,051,452$ 14,624,773$ 10,938,264$ 16,211,015$ 13,367,640$ 13,485,700$ 78,678,845$ 15,176,251$ 14,553,836$ 14,545,058$ 14,763,584$ 15,524,977$ 14,770,514$ 89,334,220$ 163,492,189$

Inventory Adjustment (749.43)


52 Total Inventory Cost 14,132,110$ 17,498,640$ 15,966,957$ 20,708,480$ 20,745,513$ 18,762,617$ 18,259,310$ 17,736,049$ 19,299,360$ 18,622,667$ 20,980,180$ 19,627,399$

Ending Inventory $ 2,873,867$ 5,028,693$ 4,497,464$ 7,377,873$ 5,276,917$ 3,083,059$ 3,182,213$ 3,814,325$ 4,815,172$ 3,949,617$ 5,610,663$ 4,897,489$

53 Ending Inventory 27,290 42,799 36,508 54,235 37,960 22,669 23,993 28,817 36,406 29,518 41,657 36,445

54 Inventory (wtd avg) 105.31$ 117.50$ 123.19$ 130.83 139.01$ 136.00$ 132.63$ 132.37 132.26$ 133.81$ 134.69$ 134.38$


#2 Fuel Allocated to Water

43 Fuel - $ 542,980$ 423,330$ 214,546$ 396,409$ 464,058$ 470,387$ 2,511,708$ 452,313$ 417,652$ 434,526$ 440,191$ 461,086$ 441,897$ 2,647,665$ 5,159,373$

44 Fuel - Bbls. 5,156 3,603 1,742 3,030 3,338 3,458.71 20,328 3,410 3,155 3,285 3,290 3,423 3,288 19,853 40,180

55 Electric Usage - Bbls. 101,753 102,528 91,363 100,276.28 107,936 111,832 615,688 110,266 102,021 106,226 106,370 110,689 106,327 641,900 1,257,588

56 Cost of No. 2 Oil 10,715,264$ 12,046,618$ 11,254,948$ 13,118,727$ 15,004,538$ 15,209,171$ 77,349,265$ 14,624,784$ 13,504,072$ 14,049,663$ 14,232,858$ 14,908,431$ 14,288,012$ $85,607,821 $162,957,086

57 Total Electric Fuel Cost 10,715,264$ 12,046,618$ 11,254,948$ 13,118,727$ 15,004,538$ 15,209,171$ 77,349,265$ 14,624,784$ 13,504,072$ 14,049,663$ 14,232,858$ 14,908,431$ 14,288,012$ $85,607,821 $162,957,086

Fuel Allocated to Water 542,980$ 423,330$ 214,546$ 396,409$ 464,058$ 470,387$ 2,511,708$ 452,313$ 417,652$ 434,526$ 440,191$ 461,086$ 441,897$ 2,647,665$ 5,159,373$

TOTAL FUEL COST 11,258,244$ 12,469,948$ 11,469,493$ 13,515,135$ 15,468,596$ 15,679,558$ 79,860,974$ 15,077,097$ 13,921,724$ 14,484,189$ 14,673,050$ 15,369,517$ 14,729,910$ 88,255,486$ 168,116,459$

% of Total Fuel Allocated to Water 4.8% 3.4% 1.9% 2.9% 3.0% 3.0% 3% 3% 3% 3% 3% 3%

C:\virgin\wapa\Dkt289 December2003\S1.2\Schedule 2 - STT


Generating Units St Croix

Schedule 3

Page 1 of 2



Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 FY2013 FY2012


Sales - Mwh 24,949 24,917 23,346 24,599 23,221 23,995 145,027 23,995 21,673 23,995 23,221 23,995 23,221 140,100 285,127

Net Available for Sales 26,354 26,305 25,886 24,601 24,986 25,819 153,950 25,819 23,320 25,819 24,986 25,819 24,986 150,748 304,697

Gross Generation-Mwh 29,742 28,894 28,588 29,508 27,085 27,987 171,805 27,987 25,279 27,987 27,085 27,987 27,085 163,410 335,215

Sum of Units 29,742 28,894 28,588 29,508 27,084 27,988 27,987 25,279 27,987 27,085 27,987 27,085 163,409

Difference 0 (0) 0 0 0 (0) 1 (0) 0 (0) 0 (0) 1


1. Generation - Mwh 10,098 7,831 9,676 8,841 6,771 6,997 0 8,396 13,848 14,931 8,125 8,396 6,771 60,468 60,468

2. Heat Rate 4,779 502 8,629 7,047 6,771 6,997 0 0 14,500 14,500 14,500 14,500 14,500

3. Heat Content /Bbl. 6.09 6.09 6.14 6.16 6.11 6.11 0.00 6.11 6.11 6.11 6.11 6.11 6.11

4. Fuel - Bbls. 7,926 645 13,594 10,111 7,507 8,017 0 0 11,872 11,872 0 0 0 23,743 23,743


5. Generation - Mwh 654 191 960 1,573 1,354 1,399 0 0 0 0 1,354 1,397 1,354 4,106 4,106

6. Heat Rate 0 0 2,900 0 2,900 2,900 0 2,900 2,900 2,900 2,900 2,900 2,900

7. Heat Content /Bbl. 6.09 6.09 6.14 6.16 6.11 6.11 0.00 6.11 6.11 6.11 6.11 6.11 6.11

8. Fuel - Bbls. 0 0 453 0 643 665 0 0 0 0 643 664 643 1,950 1,950

9 Total No. 6 Oil-Bbls. 7,926 645 14,047 10,111 8,151 8,681 49,561 0 11,872 11,872 643 664 643 25,693 75,254

Total Cost of Fuel 742,243$ 60,429$ 1,364,203$ 993,952$ 841,763$ 896,563$ 4,899,153$ 0 1,389,925 1,389,925 75,299 77,697 75,299 3,008,145 7,907,297

10 Beg. Inv. - $/Bbl. 93.65$ 93.65 93.65$ 97.11$ 98.30 103.28$ 103.28$ 103.28$ 117.08$ 117.08$ 117.08$ 117.08$

11 Beg. Inventory-Bbls. 14,378 6,453 5,808 8,414 13,048 10,897 2,216 2,216 13,844 1,973 1,330 666

12 Beginning Inv. Cost 1,346,573$ 604,330$ 543,901$ 817,096$ 1,282,596$ 1,125,427$ 228,864$ 228,864$ 1,620,886$ 230,961$ 155,662$ 77,965$

13 Purchases - Bbls. 0 0 16,653 14,745 6,000 0 37,399 0 23,500 0 0 0 0 23,500 60,899

14 Deliv. Price-$/Bbl. 93.65$ 93.65$ 98.32$ 98.98$ 114.10$ 119.48$ 118.90$ 118.38$ 117.86$ 117.35$ 116.81$ 116.29$

15 Cost of Purchases -$ -$ 1,637,397$ 1,459,452$ 684,594$ -$ 3,781,443$ -$ 2,781,947$ -$ -$ -$ -$ 2,781,947 6,563,390

Inventory Adjustment (0.01)


16 Tot. Inventory Cost 1,346,573$ 604,330$ 2,181,299$ 2,276,548$ 1,967,190$ 1,125,427$ 228,864$ 3,010,811$ 1,620,886$ 230,961$ 155,662$ 77,965$

Ending Inv. Cost 604,330$ 543,901$ 817,096$ 1,282,596$ 1,125,427$ 228,864$ 228,864$ 1,620,886$ 230,961$ 155,662$ 77,965$ 2,666$

17 Ending Inv. - Bbls. 6,453 5,808 8,414 13,047.6878 10,897 2,216 2,216 13,844 1,973 1,330 666 23

18 Inventory (wtd avg) 93.65$ 93.65$ 97.11$ 98.30$ 103.28$ 103.28$ 103.28$ 117.08$ 117.08$ 117.08$ 117.08$ 117.08$


No. 6 Fuel Allocated to Water

19 Fuel - $ 86,822$ 16,645$ 197,767$ 113,806$ 37,879$ 40,345$ 493,265$ -$ 62,547$ 62,547$ 3,388$ 3,496$ 3,388$ 135,367$ 628,632$

20 Fuel - Bbls. 927 178 2,036 1,158 367 391 0 0 534 534 29 30 29 1,156 1,156

21. Electic Usage - Bbls 6,998 468 12,011 8,954 7,784 8,290 44,505 0 11,337 11,337 614 634 614 24,537 69,042

22. Cost of No. 6 Oil 655,421$ 43,783$ 1,166,435$ 880,146$ 803,884$ 856,218$ 4,405,887$ -$ 1,327,378$ 1,327,378$ 71,910$ 74,201$ 71,910$ 2,872,778$ 7,278,666$

C:\virgin\wapa\docket289 December2003\S1.2\Schedule 3 - STX


Generating Units St Croix

Schedule 3

Page 2 of 2


Per. Ending Per. Ending TOTAL




23. Generation - Mwh 0 0 0 0 0 0 0 9,795 7,167 8,792 8,125 8,398 5,417 47,694 47,694

24. Heat Rate 0 0 0 0 0 0 0 18,674 18,674 18,674 18,674 18,674 18,674

25. Heat Content / Bbl. 5.89 5.93 5.74 5.83 6 6 0 6 6 6 6 6 6

26. Fuel - Bbls. 0 0 0 0 0 0 0 31,423 23,003 28,243 26,083 26,963 17,394 153,109 153,109


27. Generation - Mwh 2,981 5,223 4,118 1,370 2,708 2,799 0 2,799 264 264 2,708 2,799 1,354 10,188 10,188

28. Heat Rate 22,195 21,075 19,505 22,191 20,290 20,290 0 20,290 20,290 20,290 20,290 20,290 20,290 22,786

29. Heat Content / Bbl. 5.89 5.93 5.74 5.83 5.83 5.80 0.00 5.82 5.82 5.81 5.82 5.82 5.82

30. Fuel - Bbls. 11,223 18,558 13,998 5,215 9,421 9,790 0 9,755 921 921 9,447 9,764 4,725 35,532 35,532


31. Generation - Mwh 5,749 6,309 3,130 9,135 8,125 8,396 0 6,997 4,000 4,000 6,771 6,997 5,417 34,182 34,182

32. Heat Rate 19,759 20,272 19,418 17,870 18,644 18,257 0 18,451 18,354 18,402 18,378 18,390 18,384

33. Heat Content / Bbl. 5.89 5.93 5.74 5.83 5.85 5.85 0.00 5.85 5.85 5.85 5.85 5.85 5.85

34. Fuel - Bbls. 19,272 21,560 10,593 28,002 25,875 26,183 0 22,050 12,540 12,573 21,255 21,978 17,010 107,406 107,406


31. Generation - Mwh 10,260 9,340 10,704 8,589 8,125 8,396 0 0 0 0 0 0 6,771 6,771 6,771

32. Heat Rate 19,100 19,809 17,759 18,929 18,823 18,823 0 0 0 0 0 0 19,548

33. Heat Content / Bbl. 5.89 5.93 5.74 5.83 5.85 5.85 0.00 5.85 5.85 5.85 5.85 5.85 5.85

34. Fuel - Bbls. 33,247 31,190 33,128 27,889 26,123 26,994 0 0 0 0 0 0 22,608 22,608 22,608

Unit 10 & 11 0 6,794 10.05 0 5.05 2.56 - 544.93 516.33 544.90 535.37 544.89 535.37 3,222 3,222

37. Total No. 2 - Bbls. 63,742 78,102 57,730 61,106 61,425 62,970 385,074 63,773 36,980 42,283 57,320 59,250 62,272 321,877 706,951

Total Costs 6,707,433$ 9,052,015$ 4,755,443$ 4,973,134$ 8,430,350$ 8,541,305$ 42,459,679$ 0 4,905,249 5,599,249 7,634,274 7,938,356 8,350,651 34,427,780$ 76,887,459$

38. Beg. Inv. - $/Bbl. 101.36$ 105.23$ 115.90$ 122.27$ 130.98$ 137.25$ 135.64$ 133.22$ 132.65$ 132.42$ 133.19$ 133.98$ $801.10

39. Beg. Inventory-Bbls. 29,953 45,559 30,030 35,406 33,180 31,755 33,785 35,012 58,032 80,749 83,430 89,180

40. Beginning Inv. Cost 3,036,041$ 4,794,072$ 3,480,493$ 4,328,982$ 4,345,930$ 4,358,301$ 4,582,701$ 4,664,450$ 7,697,657$ 10,693,215$ 11,111,805$ 11,948,435$ 50,698,263$ 50,698,263$

41. Purchases - Bbls. 79,348 62,573 63,105 58,880 60,000 65,000 388,907 65,000 60,000 65,000 60,000 65,000 60,000 375,000 763,907

16. Deliv. Price-$/Bbl. 106.69$ 123.67$ 125.30$ 136.22$ 140.71$ 134.86$ 131.97$ 132.31$ 132.23$ 134.21$ 135.00$ 134.28$

43. Cost of Purchases 8,465,463$ 7,738,436$ 7,906,979$ 8,020,665$ 8,442,720$ 8,765,705$ 49,339,968$ 8,577,881$ 7,938,456$ 8,594,807$ 8,052,864$ 8,774,987$ 8,056,644$ 49,995,639$ 99,335,607$

Inventory Adjustment


44. - 11,501,505$ 12,532,508$ 11,387,472$ 12,349,646$ 12,788,650$ 13,124,006$ 13,160,582$ 12,602,906$ 16,292,464$ 18,746,079$ 19,886,792$ 20,005,079$

Ending Inv. Cost 4,794,072$ 3,480,493$ 4,328,982$ 4,345,930$ 4,358,301$ 4,582,701$ 4,664,450$ 7,697,657$ 10,693,214.96 11,111,804.62 11,948,435.19 11,654,428.41

45. Ending Inventory 45,559 30,030 35,406 33,179.85 31,755 33,785 35,012 58,032 80,749 83,430 89,180 86,908

46. Inventory (wtd avg) 105.23$ 115.90$ 122.27$ 130.98$ 137.25$ 135.64$ 133.22$ 132.65$ 132.42$ 133.19$ 133.98$ 134.10$

% No. 2 allocated to Water 3.44% 3.42% 3.51% 4.21% 4% 4% 4% 4% 4% 4% 4% 4% 4%

No. 2 Fuel Allocated to Water

35. Fuel - $ 230,640$ 309,491$ 167,148$ 209,347$ 337,214$ 341,652$ 1,595,492$ 339,845$ 196,210$ 223,970$ 305,371$ 317,534$ 334,026$ 1,716,956$ 3,312,449$

36. Fuel - Bbls. 2,192 2,670 2,029 2,572 2,457 2,518.79 14,439 2,551 1,479 1,691 2,293 2,370 2,491 12,875 27,314

47. Electric Usage - Bbls. 61,550 75,432 55,700 58,534 58,968 60,451 370,635 61,222 35,501 40,591 55,027 56,880 59,781 309,002 679,637

48. Cost of No. 2 Oil 6,476,793$ 8,742,524$ 6,810,392$ 7,666,794$ 8,093,136$ 8,199,652$ 45,989,292$ 8,156,287$ 4,709,039$ 5,375,279$ 7,328,903$ 7,620,822$ 8,016,625$ $41,206,955 $87,196,247

49. Total Electric Fuel Cost 7,132,214$ 8,786,308$ 7,976,828$ 8,546,940$ 8,897,019$ 9,055,870$ 50,395,179$ 8,156,287$ 6,036,418$ 6,702,657$ 7,400,814$ 7,695,023$ 8,088,535$ 44,079,734$ 94,474,913$

Fuel Allocated to Water 317,462$ 326,136$ 364,916$ 323,154$ 375,093$ 381,998$ 2,088,758$ 339,845$ 258,757$ 286,517$ 308,759$ 321,031$ 337,414$ 1,852,323$ 3,941,080$

TOTAL FUEL COST 7,449,676$ 9,112,443$ 8,341,744$ 8,870,094$ 9,272,113$ 9,437,868$ 52,483,937$ 8,496,132$ 6,295,174$ 6,989,174$ 7,709,573$ 8,016,054$ 8,425,949$ 45,932,056$ 98,415,994$

% of Total Fuel Allocated to Water 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4%

C:\virgin\wapa\docket289 December2003\S1.2\Schedule 3 - STX


Sales and Generation Forecst

Schedule 4

Page 1 of 2


Actual Actual Actual

Prelimary

Actual Forecast Forecast Per. Ending Forecast Forecast Forecast Forecast Forecast Forecast Per. Ending TOTAL


31 31 30 31 30 31 184 31 28 31 30 31 30 181 365


St. Thomas

Energy Sales:

1 Percentage of Total 8.49% 8.49% 8.22% 8.49% 8.22% 8.49% 50.41% 8.49% 7.67% 8.49% 8.22% 8.49% 8.22% 49.59% 100.00%

2. Sales (Mwh) - 39,432 36,885 36,856 35,523 37,188 38,428 224,312 38,428 34,709 38,428 37,188 38,428 37,188 224,370 448,683

3. Net Available for Sales 40,523 39,954 37,090 35,526 40,275 41,618 234,985 41,618 37,590 41,618 40,275 41,618 40,275 242,993 477,978

Line Loss & Unaccounted 2.69% 7.68% 0.63% 0.01% 8.30% 8.30% 4.76% 8.30% 8.30% 8.30% 8.30% 8.30% 8.30% 8.30% 6.53%

4. Gross Generation 43,053 41,859 38,997 41,027 43,175 44,614 252,725 44,614 40,297 44,614 43,175 44,614 43,175 260,489 513,214

5. Plant Use and Plant Losses 5.55% 4.12% 4.40% 7.20% 7.20% 7.20% 7.55% 7.20% 7.20% 7.20% 7.20% 7.20% 7.20% 7.20% 7.37%

St Croix

Energy Sales:

Percentage of Total 8.49% 8.49% 8.22% 8.49% 8.22% 8.49% 50.63% 8.49% 7.67% 8.49% 8.22% 8.49% 8.22% 49.59% 100.00%

6. Sales (Mwh) - 24,949 24,917 23,346 24,599 23,221 23,995 145,027 23,995 21,673 23,995 23,221 23,995 23,221 140,100 285,127

7. Net Available for Sales 26,354 26,305 25,886 24,601 24,986 25,819 153,950 25,819 23,320 25,819 24,986 25,819 24,986 150,748 304,697

8. Line Loss & Unaccounted 5.33% 5.28% 9.81% 0.01% 7.60% 7.60% 6.15% 7.60% 7.60% 7.60% 7.60% 7.60% 7.60% 7.60% 6.86%

9. Gross Generation 29,742 28,894 28,588 29,508 27,085 27,987 171,805 27,987 25,279 27,987 27,085 27,987 27,085 163,410 335,215

10. Plant Use and Plant Losses 10.96% 8.57% 9.03% 8.40% 8.40% 8.40% 11.60% 8.40% 8.40% 8.40% 8.40% 8.40% 8.40% 8.40% 10.02%

25554 27379

11. TOTAL SALES (Mwh) 64,382 61,802 60,201 60,122 60,409 62,423 369,340 62,423 56,382 62,423 60,409 62,423 60,409 364,470 733,810

12. TOTAL NET AVAILABLE FOR SALE 66,876 66,259 62,976 60,126 65,261 67,436 388,935 67,436 60,910 67,436 65,261 67,436 65,261 393,741 782,676

13. TOTAL GROSS GENERATION 72,795 70,753 67,585 70,536 70,260 72,601 424,530 72,601 65,576 72,601 70,260 72,601 70,260 423,899 848,429

14. COMPANY USE/LINE LOSS 11.56% 12.65% 10.93% 14.76% 14.02% 14.02% 13.00% 14.02% 14.02% 14.02% 14.02% 14.02% 14.02% 14.02% 15.62%

Projected FY13 sales - STT 452,460

Projected FY13 sales - STX 282,522

TOTAL 734,982

C:\virgin\wapa\dkt289 december2003\S1.2\S4.1 - Elec. Sales Assump.

THE VIRGIN ISLANDS WATER AND POWER AUTHORITY

WATER PRODUCTION, LOSSES AND SALES

Schedule 4

Page 2 of 2




31 31 30 31 30 31 184 31 28 31 30 31 30 181 365


St. Thomas

Water Sales:

1a. Percentage of Total 8.49% 8.49% 8.22% 8.49% 8.22% 8.49% 50.41% 8.49% 7.67% 8.49% 8.22% 8.49% 8.22% 49.59% 100.00%

2. Sales (kGal) - 42,476 66,084 50,200 40,017 50,171 51,844 300,792 51,844 46,827 51,844 50,171 51,844 50,171 302,700 603,493

3.

Net Distribution Available For Sale or

WAPA Use 61,608 60,803 58,361 48,225 60,462 62,477 351,937 61,514 55,561 61,514 59,529 61,514 59,529 359,160 711,097

Line Loss & Unaccounted 31.06% -8.69% 13.98% 17.02% 17.02% 17.02% 15.72% 15.72% 15.72% 15.72% 15.72% 15.72%

4. Available for Sale - Gross 104,487 85,604 69,683 53,215 66,717 68,941 448,647 67,878 61,309 67,878 65,688 67,878 65,688 396,319 844,966

Plant Use and Plant Losses 20.69% 19.02% 34.43% 10.35% 10.35% 10.35% 10.35% 10.35% 10.35% 10.35% 10.35% 10.35%

5. TARGET LINE LOSS % 17.02% 17.02% 17.02% 17.02% 17.02% 17.02% 14.53% 15.72% 15.72% 15.72% 15.72% 15.72% 15.72% 15.72% 15.13% Line 4/Line 1

St. Croix

Water Sales:

1a. Percentage of Total 8.49% 8.49% 8.22% 8.49% 8.22% 8.49% 50.41% 8.49% 7.67% 8.49% 8.22% 8.49% 8.22% 49.59% 100.00%

2. Sales (kGal) - 53,946 57,435 56,585 65,268 55,546 57,398 346,178 57,398 51,843 57,398 55,546 57,398 55,546 335,129 681,307

3.

Net Distribution Available For Sale or

WAPA Use 75,767 80,694 81,631 78,655 66,939 69,171 452,857 68,104 61,513 68,104 65,907 68,104 65,907 397,638 850,495

Line Loss & Unaccounted 28.80% 28.82% 30.68% 17.02% 17.02% 17.02% 15.72% 15.72% 15.72% 15.72% 15.72% 15.72%

4. Available for Sale - Gross 82,537 87,062 94,852 83,719 71,249 73,624 493,043 72,489 65,474 72,489 70,150 72,489 70,150 423,241 916,284

Plant Use and Plant Losses 8.87% 10.24% 9.43% 6.44% 6.44% 6.44% 6.44% 6.44% 6.44% 6.44% 6.44% 6.44%

5. TARGET LINE LOSS % 17.02% 17.02% 17.02% 17.02% 17.02% 17.02% 23.56% 15.72% 15.72% 15.72% 15.72% 15.72% 15.72% 15.72% 19.89%

Water Sales:

St. Croix...kGal 53,946 57,435 56,585 65,268 55,546 57,398 346,178 57,398 51,843 57,398 55,546 57,398 55,546 335,129 681,307

St. Thomas..kgal 42,476 66,084 50,200 40,017 50,171 51,844 300,792 51,844 46,827 51,844 50,171 51,844 50,171 302,700 603,493

Total Sales..kGal 96,421 123,519 106,785 105,285 105,718 109,242 646,970 109,242 98,670 109,242 105,718 109,242 105,718 637,830 1,284,800

Projected FY13 sales - STT 610,418

Projected FY13sales - STX 675,813

TOTAL 1,286,231

VIRGIN ISLANSD WATER AND POWER AUTHORITY

Fuel Price Forecast

$/BBL

Schedule 5.1

Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast

Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13

Brent Blend Futures 96.91$ 119.35$ 116.25$ 114.31$ 113.38$ 112.78$ 112.21$ 111.71$ 111.21$ 110.71$ 110.19$ 109.68$

Shipping Allowance 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00

Base Price 99.91$ 122.35$ 119.25$ 117.31$ 116.38$ 115.78$ 115.21$ 114.71$ 114.21$ 113.71$ 113.19$ 112.68$

Base Price 99.91$ 122.35$ 119.25$ 117.31$ 116.38$ 115.78$ 115.21$ 114.71$ 114.21$ 113.71$ 113.19$ 112.68$

Market Ratio 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0%

NY Harbor Price 92.92$ 113.79$ 110.90$ 109.10$ 108.23$ 107.68$ 107.15$ 106.68$ 106.22$ 105.75$ 105.27$ 104.79$

Hovensa Discount 80% 85% 85% 90% 95% 100% 100% 100% 100% 100% 100% 100%

Delivered Price 74.33$ 96.72$ 94.27$ 98.19$ 102.82$ 107.68$ 107.15$ 106.68$ 106.22$ 105.75$ 105.27$ 104.79$

Base Price 99.91$ 122.35$ 119.25$ 117.31$ 116.38$ 115.78$ 115.21$ 114.71$ 114.21$ 113.71$ 113.19$ 112.68$

Market Ratio 103.2% 103.2% 103.2% 103.2% 103.2% 103.2% 103.2% 103.2% 103.2% 103.2% 103.2% 103.2%

NY Harbor Price 103.11$ 126.27$ 123.07$ 121.06$ 120.10$ 119.48$ 118.90$ 118.38$ 117.86$ 117.35$ 116.81$ 116.29$


Delivered Price 82.49$ 107.33$ 104.61$ 108.96$ 114.10$ 119.48$ 118.90$ 118.38$ 117.86$ 117.35$ 116.81$ 116.29$

Base Price 99.91$ 122.35$ 119.25$ 117.31$ 116.38$ 115.78$ 115.21$ 114.71$ 114.21$ 113.71$ 113.19$ 112.68$

Market Ratio 121.0% 121.0% 121.0% 121.0% 121.0% 121.0% 121.0% 121.0% 121.0% 121.0% 121.0% 121.0%

NY Harbor Price 120.89$ 148.04$ 144.29$ 141.95$ 140.82$ 140.09$ 139.40$ 138.80$ 138.19$ 137.59$ 136.96$ 136.34$


Delivered Price 96.71$ 122.35$ 122.65$ 127.75$ 133.78$ 140.09$ 139.40$ 138.80$ 138.19$ 137.59$ 136.96$ 136.34$

Hovensa NY Castle 137.71$

Shipping 3.00$

CME Group HO/gal. 2.97$ 2.90$ 2.91$ 2.91$ 2.96$ 2.98$ 2.96$

Conversion gal. to barrel 42 42 42 42 42 42 42

Shipping/markup 9.97$ 9.97$ 9.97$ 9.97$ 9.97$ 9.97$ 9.97$

Delivered Price 140.71$ 134.86$ 131.97$ 132.31$ 132.23$ 134.21$ 135.00$ 134.28$

Number Six Oil - STT

Number Six Oil - STX

Number Two Oil - STT/STX

VIRFIN ISLANDS WATER AND POWER AUTHORITY

Docket 289

Schedule 5.2

Delivery # Bbls Unit Price Trans. Deliv. Price Deliv. Price

STX STT

12101 17,153.70 137.71 69,000 141.73

12102 15,739.12 137.71 55,000 141.20

12103 17,266.11 137.71 69,000 141.71

12104 17,393.83 139.67 69,000 143.64

12105 15,737.66 137.71 55,000 141.20

12106 17,421.38 141.54 69,000 145.50

12107 10,161.96 141.54 34,838 144.97

6,026.86 98.21 20,662 101.64 No 6

12108 15,854.62 141.54 55,500 145.04

Simple Avg 134.81 143.14

Oil Deliveries November 2012

VIRGIN ISLANDS WATER AND POWER

GO Note AmortizationSchedule 6.1

Client: VI WAPA Sc hedul e 6 El ec t r i c 0. 892 0. 70 41, 904. 69

PMT Amount: ############# Wat er 0. 108 0. 30 $198, 034. 77

( $239, 939. 46) Term: 4 y ear s Tot al 239, 939

Rate: 5. 50%

Base360/365: 360

Beginning Monthly Principal Interest Ending Interest Pmt Days Elect Balance

Mo Principal Payment Portion Portion Principal Rate Date Accrued Electric Prin. Water Prin. Total Prin. ($000's)

27,711,909.16

5/ 1/ 2012 31,056,164 759,439 623,389 136,050 30, 432, 776 5.2500% 556,062.92 67,326.00 623,388.92 27,155,846.24

5/ 3/ 2012 18,000,000 12, 432, 776 5.2500% 18,000,000.00 18,000,000 9,155,846.24 J une- 12 1 12, 432, 776 759, 439. 35 697,982.86 61,456.49 11, 734, 793 5. 5000% 06/ 01/ 12 622, 601 75, 382 697, 983 8, 533, 246

J ul y - 12 2 11, 734, 793 759, 439. 35 708,099.63 51,339.72 11, 026, 693 5. 5000% 07/ 01/ 12 631, 625 76, 475 708, 100 7, 901, 621

Augus t - 12 3 11, 026, 693 759, 439. 35 709,589.51 49,849.84 10, 317, 104 5. 5000% 08/ 06/ 12 632, 954 76, 636 709, 590 7, 268, 667

Sept ember - 12 4 10, 317, 104 239, 939. 46 198,957.63 40,981.83 10, 118, 146 5. 5000% 09/ 01/ 12 26 34, 747 164, 210 198, 958 7, 233, 919

Oc t ober - 12 5 10, 118, 146 239, 939 193,473.46 46,466.00 9, 924, 672 5. 5000% 10/ 01/ 12 30 33, 790 159, 684 193, 473 7, 200, 130

Nov ember - 12 6 9, 924, 672 239, 939 192, 935 47, 004. 35 9, 731, 737 5. 5000% 11/ 01/ 12 31 33, 696 159, 240 192, 935 7, 166, 434

Dec ember - 12 7 9, 731, 737 239, 939 195, 336 44, 603. 80 9, 536, 402 5. 5000% 12/ 01/ 12 30 34, 115 161, 221 195, 336 7, 132, 320

J anuar y - 13 8 9, 536, 402 239, 939 194, 774 45, 165. 46 9, 341, 628 5. 5000% 01/ 01/ 13 31 34, 017 160, 757 194, 774 7, 098, 303

Febr uar y - 13 9 9, 341, 628 239, 939 195, 696 44, 242. 99 9, 145, 931 5. 5000% 02/ 01/ 13 31 34, 178 161, 519 195, 696 7, 064, 125

Mar c h- 13 10 9, 145, 931 239, 939 200, 815 39, 124. 26 8, 945, 116 5. 5000% 03/ 01/ 13 28 35, 072 165, 743 200, 815 7, 029, 053

Apr i l - 13 11 8, 945, 116 239, 939 197, 574 42, 365. 06 8, 747, 542 5. 5000% 04/ 01/ 13 31 34, 506 163, 069 197, 574 6, 994, 548

May - 13 12 8, 747, 542 239, 939 199, 847 40, 092. 90 8, 547, 695 5. 5000% 05/ 01/ 13 30 34, 903 164, 944 199, 847 6, 959, 645

J une- 13 13 8, 547, 695 239, 939 199, 457 40, 483 8, 348, 238 5. 5000% 06/ 01/ 13 31 34, 834 164, 622 199, 457 6, 924, 811

J ul y - 13 14 8, 348, 238 239, 939 201, 677 38, 263 8, 146, 562 5. 5000% 07/ 01/ 13 30 35, 222 166, 454 201, 677 6, 889, 588

Augus t - 13 15 8, 146, 562 239, 939 201, 356 38, 583 7, 945, 205 5. 5000% 08/ 01/ 13 31 35, 166 166, 190 201, 356 6, 854, 422

Sept ember - 13 16 7, 945, 205 239, 939 202, 310 37, 629 7, 742, 895 5. 5000% 09/ 01/ 13 31 35, 333 166, 977 202, 310 6, 819, 089

Oc t ober - 13 17 7, 742, 895 239, 939 204, 451 35, 488 7, 538, 444 5. 5000% 10/ 01/ 13 30 35, 707 168, 744 204, 451 6, 783, 382

Nov ember - 13 18 7, 538, 444 239, 939 204, 237 35, 703 7, 334, 207 5. 5000% 11/ 01/ 13 31 35, 669 168, 567 204, 237 6, 747, 713

Dec ember - 13 19 7, 334, 207 239, 939 206, 324 33, 615 7, 127, 883 5. 5000% 12/ 01/ 13 30 36, 034 170, 290 206, 324 6, 711, 679

J anuar y - 14 20 7, 127, 883 239, 939 206, 181 33, 758 6, 921, 702 5. 5000% 01/ 01/ 14 31 206, 181 206, 181 6, 505, 498

Febr uar y - 14 21 6, 921, 702 239, 939 207, 158 32, 782 6, 714, 545 5. 5000% 02/ 01/ 14 31 207, 158 207, 158 6, 298, 341

Mar c h- 14 22 6, 714, 545 239, 939 211, 216 28, 723 6, 503, 328 5. 5000% 03/ 01/ 14 28 211, 216 211, 216 6, 087, 125

Apr i l - 14 23 6, 503, 328 239, 939 209, 139 30, 800 6, 294, 189 5. 5000% 04/ 01/ 14 31 209, 139 209, 139 5, 877, 986

May - 14 24 6, 294, 189 239, 939 211, 091 28, 848 6, 083, 098 5. 5000% 05/ 01/ 14 30 211, 091 211, 091 5, 666, 895

J une- 14 25 6, 083, 098 239, 939 211, 129 28, 810 5, 871, 969 5. 5000% 06/ 01/ 14 31 211, 129 211, 129 5, 455, 765

J ul y - 14 26 5, 871, 969 239, 939 213, 026 26, 913 5, 658, 943 5. 5000% 07/ 01/ 14 30 213, 026 213, 026 5, 242, 739

Augus t - 14 27 5, 658, 943 239, 939 213, 138 26, 801 5, 445, 805 5. 5000% 08/ 01/ 14 31 213, 138 213, 138 5, 029, 601

Sept ember - 14 28 5, 445, 805 239, 939 214, 148 25, 792 5, 231, 657 5. 5000% 09/ 01/ 14 31 214, 148 214, 148 4, 815, 453

Oc t ober - 14 29 5, 231, 657 239, 939 215, 961 23, 978 5, 015, 696 5. 5000% 10/ 01/ 14 30 215, 961 215, 961 4, 599, 492

Nov ember - 14 30 5, 015, 696 239, 939 216, 185 23, 755 4, 799, 512 5. 5000% 11/ 01/ 14 31 216, 185 216, 185 4, 383, 308

Dec ember - 14 31 4, 799, 512 239, 939 217, 942 21, 998 4, 581, 570 5. 5000% 12/ 01/ 14 30 217, 942 217, 942 4, 165, 366

J anuar y - 15 32 4, 581, 570 239, 939 218, 241 21, 699 4, 363, 329 5. 5000% 01/ 01/ 15 31 218, 241 218, 241 3, 947, 126

Febr uar y - 15 33 4, 363, 329 239, 939 219, 274 20, 665 4, 144, 055 5. 5000% 02/ 01/ 15 31 219, 274 219, 274 3, 727, 851

Mar c h- 15 34 4, 144, 055 239, 939 222, 212 17, 727 3, 921, 843 5. 5000% 03/ 01/ 15 28 222, 212 222, 212 3, 505, 639

Apr i l - 15 35 3, 921, 843 239, 939 221, 365 18, 574 3, 700, 478 5. 5000% 04/ 01/ 15 31 221, 365 221, 365 3, 284, 274

May - 15 36 3, 700, 478 239, 939 222, 979 16, 961 3, 477, 499 5. 5000% 05/ 01/ 15 30 222, 979 222, 979 3, 061, 295

J une- 15 37 3, 477, 499 239, 939 223, 470 16, 470 3, 254, 029 5. 5000% 06/ 01/ 15 31 223, 470 223, 470 2, 837, 825

J ul y - 15 38 3, 254, 029 239, 939 225, 025 14, 914 3, 029, 004 5. 5000% 07/ 01/ 15 30 225, 025 225, 025 2, 612, 800

Augus t - 15 39 3, 029, 004 239, 939 225, 594 14, 346 2, 803, 410 5. 5000% 08/ 01/ 15 31 225, 594 225, 594 2, 387, 206

Sept ember - 15 40 2, 803, 410 239, 939 226, 662 13, 277 2, 576, 748 5. 5000% 09/ 01/ 15 31 226, 662 226, 662 2, 160, 544

Oc t ober - 15 41 2, 576, 748 239, 939 228, 129 11, 810 2, 348, 619 5. 5000% 10/ 01/ 15 30 228, 129 228, 129 1, 932, 415

Nov ember - 15 42 2, 348, 619 239, 939 228, 816 11, 123 2, 119, 803 5. 5000% 11/ 01/ 15 31 228, 816 228, 816 1, 703, 599

Dec ember - 15 43 2, 119, 803 239, 939 230, 224 9, 716 1, 889, 579 5. 5000% 12/ 01/ 15 30 230, 224 230, 224 1, 473, 375

J anuar y - 16 44 1, 889, 579 239, 939 230, 990 8, 949 1, 658, 589 5. 5000% 01/ 01/ 16 31 230, 990 230, 990 1, 242, 385

Febr uar y - 16 45 1, 658, 589 239, 939 232, 084 7, 855 1, 426, 505 5. 5000% 02/ 01/ 16 31 232, 084 232, 084 1, 010, 301

Mar c h- 16 46 1, 426, 505 239, 939 233, 183 6, 756 1, 193, 321 5. 5000% 03/ 03/ 16 31 233, 183 233, 183 777, 117

Apr i l - 16 47 1, 193, 321 239, 939 234, 288 5, 652 959, 033 5. 5000% 04/ 03/ 16 31 234, 288 234, 288 542, 830

May - 16 48 959, 033 239, 939 235, 397 4, 542 723, 636 5. 5000% 05/ 04/ 16 31 235, 397 235, 397 307, 432

J une- 16 49 723, 636 239, 939 236, 512 3, 427 487, 124 5. 5000% 06/ 04/ 16 31 236, 512 236, 512 70, 920

J ul y - 16 50 487, 124 239, 939 237, 632 2, 307 249, 491 5. 5000% 07/ 05/ 16 31 237, 632 237, 632 ( 166, 712)

Augus t - 16 51 249, 491 239, 939 238, 758 1, 182 10, 734 5. 5000% 08/ 05/ 16 31 238, 758 238, 758 ( 405, 470)

30


GO Note AmortizationSchedule 6.1

0. 17 9, 156$ 704. 53 73. 6%

0. 83 3, 277 26. 4%

1. 00 12, 433$ 100. 0%

Water Bal. Total Balance Total Bal.

($000's) ($000's) Electric Inter. Water Inter. Total Interest Electric P&I Water p & I

Elect & Water

Prin. Elec. & Water Int. Total Pmts. Total PMT

3,344,255.31 31,056,164.47 62, 112, 328. 94

3,276,929.31 30,432,775.55 60, 865, 551. 10

3,276,929.31 12,432,775.55 24, 865, 551. 10

3, 201, 547 11,734,792.69 23, 469, 585. 38 54, 819 6, 637 61, 456 677, 420 82, 019 697, 983 61, 456 759, 439 759, 439

3, 125, 072 11,026,693.06 22, 053, 386. 12 45, 795 5, 545 51, 340 677, 420 82, 019 708, 100 51, 340 759, 439 759, 439

3, 048, 437 10,317,103.55 20, 634, 207. 10 44, 466 5, 384 49, 850 677, 420 82, 019 709, 590 49, 850 759, 439 759, 439

2, 884, 226 10,118,145.92 20, 236, 291. 84 7, 157 33, 824 40, 982 41, 905 198, 035 198, 958 40, 982 239, 939 239, 939

2, 724, 543 9,924,672.46 19, 849, 344. 92 8, 115 38, 351 46, 466 41, 905 198, 035 193, 473 46, 466 239, 939 239, 939

2, 565, 303 9,731,737.35 19, 463, 474. 70 8, 209 38, 795 47, 004 41, 905 198, 035 192, 935 47, 004 239, 939 239, 939

2, 404, 082 9,536,401.69 19, 072, 803. 38 7, 790 36, 814 44, 604 41, 905 198, 035 195, 336 44, 604 239, 939 239, 939

2, 243, 325 9,341,627.69 18, 683, 255. 37 7, 888 37, 277 45, 165 41, 905 198, 035 194, 774 45, 165 239, 939 239, 939

2, 081, 806 9,145,931.21 18, 291, 862. 42 7, 727 36, 516 44, 243 41, 905 198, 035 195, 696 44, 243 239, 939 239, 939

1, 916, 063 8,945,116.01 17, 890, 232. 03 6, 833 32, 291 39, 124 41, 905 198, 035 200, 815 39, 124 239, 939 239, 939

1, 752, 994 8,747,541.62 17, 495, 083. 23 7, 399 34, 966 42, 365 41, 905 198, 035 197, 574 42, 365 239, 939 239, 939

1, 588, 050 8,547,695.06 17, 095, 390. 11 7, 002 33, 091 40, 093 41, 905 198, 035 199, 847 40, 093 239, 939 239, 939

1, 423, 428 8,348,238.43 16, 696, 476. 86 7, 070 33, 413 40, 483 41, 905 198, 035 199, 457 40, 483 239, 939 239, 939

1, 256, 973 8,146,561.73 16, 293, 123. 46 6, 682 31, 580 38, 263 41, 905 198, 035 201, 677 38, 263 239, 939 239, 939

1, 090, 783 7,945,205.29 15, 890, 410. 58 6, 738 31, 845 38, 583 41, 905 198, 035 201, 356 38, 583 239, 939 239, 939

923, 806 7,742,895.21 15, 485, 790. 41 6, 572 31, 058 37, 629 41, 905 198, 035 202, 310 37, 629 239, 939 239, 939

755, 062 7,538,444.02 15, 076, 888. 03 6, 198 29, 290 35, 488 41, 905 198, 035 204, 451 35, 488 239, 939 239, 939

586, 494 7,334,207.46 14, 668, 414. 93 6, 235 29, 468 35, 703 41, 905 198, 035 204, 237 35, 703 239, 939 239, 939

416, 204 7,127,883.12 14, 255, 766. 24 5, 871 27, 744 33, 615 41, 905 198, 035 206, 324 33, 615 239, 939 239, 939

6,505,498.26 13, 010, 996. 51 33, 758 33, 758 239, 939 206, 181 33, 758 239, 939 239, 939

6,298,340.75 12, 596, 681. 49 32, 782 32, 782 239, 939 207, 158 32, 782 239, 939 239, 939

6,087,124.62 12, 174, 249. 23 28, 723 28, 723 239, 939 211, 216 28, 723 239, 939 239, 939

5,877,985.64 11, 755, 971. 29 30, 800 30, 800 239, 939 209, 139 30, 800 239, 939 239, 939

5,666,894.55 11, 333, 789. 10 28, 848 28, 848 239, 939 211, 091 28, 848 239, 939 239, 939

5,455,765.32 10, 911, 530. 64 28, 810 28, 810 239, 939 211, 129 28, 810 239, 939 239, 939

5,242,739.05 10, 485, 478. 11 26, 913 26, 913 239, 939 213, 026 26, 913 239, 939 239, 939

5,029,600.98 10, 059, 201. 95 26, 801 26, 801 239, 939 213, 138 26, 801 239, 939 239, 939

4,815,453.45 9, 630, 906. 91 25, 792 25, 792 239, 939 214, 148 25, 792 239, 939 239, 939

4,599,492.42 9, 198, 984. 84 23, 978 23, 978 239, 939 215, 961 23, 978 239, 939 239, 939

4,383,307.86 8, 766, 615. 71 23, 755 23, 755 239, 939 216, 185 23, 755 239, 939 239, 939

4,165,366.16 8, 330, 732. 32 21, 998 21, 998 239, 939 217, 942 21, 998 239, 939 239, 939

3,947,125.52 7, 894, 251. 05 21, 699 21, 699 239, 939 218, 241 21, 699 239, 939 239, 939

3,727,851.28 7, 455, 702. 55 20, 665 20, 665 239, 939 219, 274 20, 665 239, 939 239, 939

3,505,639.16 7, 011, 278. 33 17, 727 17, 727 239, 939 222, 212 17, 727 239, 939 239, 939

3,284,273.99 6, 568, 547. 97 18, 574 18, 574 239, 939 221, 365 18, 574 239, 939 239, 939

3,061,295.05 6, 122, 590. 10 16, 961 16, 961 239, 939 222, 979 16, 961 239, 939 239, 939

2,837,825.41 5, 675, 650. 82 16, 470 16, 470 239, 939 223, 470 16, 470 239, 939 239, 939

2,612,800.25 5, 225, 600. 51 14, 914 14, 914 239, 939 225, 025 14, 914 239, 939 239, 939

2,387,206.49 4, 774, 412. 99 14, 346 14, 346 239, 939 225, 594 14, 346 239, 939 239, 939

2,160,544.30 4, 321, 088. 59 13, 277 13, 277 239, 939 226, 662 13, 277 239, 939 239, 939

1,932,414.93 3, 864, 829. 86 11, 810 11, 810 239, 939 228, 129 11, 810 239, 939 239, 939

1,703,598.79 3, 407, 197. 58 11, 123 11, 123 239, 939 228, 816 11, 123 239, 939 239, 939

1,473,375.09 2, 946, 750. 19 9, 716 9, 716 239, 939 230, 224 9, 716 239, 939 239, 939

1,242,384.89 2, 484, 769. 78 8, 949 8, 949 239, 939 230, 990 8, 949 239, 939 239, 939

1,010,300.69 2, 020, 601. 38 7, 855 7, 855 239, 939 232, 084 7, 855 239, 939 239, 939

777,117.31 1, 554, 234. 63 6, 756 6, 756 239, 939 233, 183 6, 756 239, 939 239, 939

542,829.55 1, 085, 659. 11 5, 652 5, 652 239, 939 234, 288 5, 652 239, 939 239, 939

307,432.18 614, 864. 37 4, 542 4, 542 239, 939 235, 397 4, 542 239, 939 239, 939

70,919.94 141, 839. 89 3, 427 3, 427 239, 939 236, 512 3, 427 239, 939 239, 939

(166,712.44) ( 333, 424. 89) 2, 307 2, 307 239, 939 237, 632 2, 307 239, 939 239, 939

(405,470.28) ( 810, 940. 57) 1, 182 1, 182 239, 939 238, 758 1, 182 239, 939 239, 939

VI RI GI N I SLANDS WATER AND POWER

PROPOSED AMORTI ZATI ON Sc hedul e 6. 2

FIRST BANK FIRST BANK FIRST BANK

AMOUNT 10,317,103.25$ AMOUNT 7,268,666.82$ AMOUNT 3,048,436.73$

RATE 5.50% RATE 5.50% RATE 5.50%

TERM 48 TERM 48 TERM 16

PAYMENT $239,939.46 PAYMENT $41,904.69 PAYMENT $198,034.77

Beginning Bal. PMT Prin. Interest Ending Balance Beginning Bal. PMT Prin. Interest Ending Balance Beginning Bal. PMT Prin. Interest Ending Balance Beginning Bal. PMT Prin. Interest Ending Balance

10,317,103.22 7,268,666.82$

9/1/2012 10, 317, 103. 22 239, 939. 46 198,957.63 40,981.83 10, 118, 145. 59 7,268,666.82$ 41,904.69 14,894.86 27,009.83$ $7,253,771.96 3,048,436.73$ $198,034.77 $184,062.77 13,972.00$ 2,864,373.96$ $10,317,103.55 $239,939.46 $198,957.63 $40,981.83 $10,118,145.92

10/1/2012 10, 118, 145. 59 239, 939. 46 193,473.46 46,466.00 9, 924, 672. 13 $7,253,771.96 41,904.69 8,567.07 33,337.62$ $7,245,204.89 2,864,373.96$ $198,034.77 $184,906.39 13,128.38$ 2,679,467.57$ $10,118,145.92 $239,939.46 $193,473.46 $46,466.00 $9,924,672.46

11/1/2012 9, 924, 672. 13 239, 939. 46 192, 935. 54 47, 003. 92 9, 731, 736. 59 $7,245,204.89 41,904.69 7,181.66 34,723.03$ $7,238,023.22 2,679,467.57$ $198,034.77 $185,753.88 12,280.89$ 2,493,713.70$ $9,924,672.46 $239,939.46 $192,935.54 $47,003.92 $9,731,736.92

12/1/2012 9, 731, 736. 59 239, 939. 46 195, 336. 09 44, 603. 37 9, 536, 400. 50 $7,238,023.22 41,904.69 8,730.84 33,173.85$ $7,229,292.39 2,493,713.70$ $198,034.77 $186,605.25 11,429.52$ 2,307,108.45$ $9,731,736.92 $239,939.46 $195,336.09 $44,603.37 $9,536,400.83

1/1/2013 9, 536, 400. 50 239, 939. 46 194, 774. 44 45, 165. 02 9, 341, 626. 06 $7,229,292.39 41,904.69 7,313.92 34,590.77$ $7,221,978.47 2,307,108.45$ $198,034.77 $187,460.52 10,574.25$ 2,119,647.92$ $9,536,400.83 $239,939.46 $194,774.44 $45,165.02 $9,341,626.39

2/1/2013 9, 341, 626. 06 239, 939. 46 195, 696. 91 44, 242. 55 9, 145, 929. 15 $7,221,978.47 41,904.69 7,377.20 34,527.49$ $7,214,601.27 2,119,647.92$ $198,034.77 $188,319.72 9,715.05$ 1,931,328.21$ $9,341,626.39 $239,939.46 $195,696.91 $44,242.55 $9,145,929.48

3/1/2013 9, 145, 929. 15 239, 939. 46 200, 815. 60 39, 123. 86 8, 945, 113. 55 $7,214,601.27 41,904.69 11,632.75 30,271.94$ $7,202,968.53 1,931,328.21$ $198,034.77 $189,182.85 8,851.92$ 1,742,145.36$ $9,145,929.48 $239,939.46 $200,815.60 $39,123.86 $8,945,113.88

4/1/2013 8, 945, 113. 55 239, 939. 46 197, 574. 84 42, 364. 62 8, 747, 538. 71 $7,202,968.53 41,904.69 7,524.90 34,379.79$ $7,195,443.62 1,742,145.36$ $198,034.77 $190,049.94 7,984.83$ 1,552,095.42$ $8,945,113.88 $239,939.46 $197,574.84 $42,364.62 $8,747,539.04

5/1/2013 8, 747, 538. 71 239, 939. 46 199, 846. 99 40, 092. 47 8, 547, 691. 72 $7,195,443.62 41,904.69 8,925.99 32,978.70$ $7,186,517.63 1,552,095.42$ $198,034.77 $190,921.00 7,113.77$ 1,361,174.42$ $8,747,539.04 $239,939.46 $199,846.99 $40,092.47 $8,547,692.05

6/1/2013 8, 547, 691. 72 239, 939. 46 199, 457. 07 40, 482. 39 8, 348, 234. 65 $7,186,517.63 41,904.69 7,661.02 34,243.67$ $7,178,856.61 1,361,174.42$ $198,034.77 $191,796.05 6,238.72$ 1,169,378.37$ $8,547,692.05 $239,939.46 $199,457.07 $40,482.39 $8,348,234.98

7/1/2013 8, 348, 234. 65 239, 939. 46 201, 677. 14 38, 262. 32 8, 146, 557. 51 $7,178,856.61 41,904.69 9,002.02 32,902.67$ $7,169,854.59 1,169,378.37$ $198,034.77 $192,675.12 5,359.65$ 976,703.25$ $8,348,234.98 $239,939.46 $201,677.14 $38,262.32 $8,146,557.84

8/1/2013 8, 146, 557. 51 239, 939. 46 201, 356. 89 38, 582. 57 7, 945, 200. 62 $7,169,854.59 41,904.69 7,798.68 34,106.01$ $7,162,055.92 976,703.25$ $198,034.77 $193,558.21 4,476.56$ 783,145.03$ $8,146,557.84 $239,939.46 $201,356.89 $38,582.57 $7,945,200.95

9/1/2013 7, 945, 200. 62 239, 939. 46 202, 310. 54 37, 628. 92 7, 742, 890. 08 $7,162,055.92 41,904.69 7,865.18 34,039.51$ $7,154,190.73 783,145.03$ $198,034.77 $194,445.36 3,589.41$ 588,699.68$ $7,945,200.95 $239,939.46 $202,310.54 $37,628.92 $7,742,890.41

10/1/2013 7, 742, 890. 08 239, 939. 46 204, 451. 63 35, 487. 83 7, 538, 438. 45 $7,154,190.73 41,904.69 9,115.07 32,789.62$ $7,145,075.67 588,699.68$ $198,034.77 $195,336.56 2,698.21$ 393,363.12$ $7,742,890.41 $239,939.46 $204,451.63 $35,487.83 $7,538,438.78

11/1/2013 7, 538, 438. 45 239, 939. 46 204, 237. 01 35, 702. 45 7, 334, 201. 44 $7,145,075.67 41,904.69 8,005.15 33,899.54$ $7,137,070.51 393,363.12$ $198,034.77 $196,231.86 1,802.91$ 197,131.26$ $7,538,438.78 $239,939.46 $204,237.01 $35,702.45 $7,334,201.77

12/1/2013 7, 334, 201. 44 239, 939. 46 206, 324. 79 33, 614. 67 7, 127, 876. 66 $7,137,070.51 41,904.69 9,193.54 32,711.15$ $7,127,876.98 197,131.26$ $198,034.77 $197,131.25 903.52$ 0.01$ $7,334,201.77 $239,939.46 $206,324.79 $33,614.67 $7,127,876.99

1/1/2014 7, 127, 876. 66 239, 939. 46 206, 181. 48 33, 757. 98 6, 921, 695. 18 $7,127,876.98 239,939.46 206,181.48 33,757.98$ $6,921,695.50 $7,127,876.98 $239,939.46 $206,181.48 $33,757.98 $6,921,695.50

2/1/2014 6, 921, 695. 18 239, 939. 46 207, 157. 97 32, 781. 49 6, 714, 537. 21 $6,921,695.50 239,939.46 207,157.97 32,781.49$ $6,714,537.53 $6,921,695.50 $239,939.46 $207,157.97 $32,781.49 $6,714,537.53

3/1/2014 6, 714, 537. 21 239, 939. 46 211, 216. 55 28, 722. 91 6, 503, 320. 65 $6,714,537.53 239,939.46 211,216.55 28,722.91$ $6,503,320.97 $6,714,537.53 $239,939.46 $211,216.55 $28,722.91 $6,503,320.97

4/1/2014 6, 503, 320. 65 239, 939. 46 209, 139. 44 30, 800. 02 6, 294, 181. 21 $6,503,320.97 239,939.46 209,139.44 30,800.02$ $6,294,181.53 $6,503,320.97 $239,939.46 $209,139.44 $30,800.02 $6,294,181.53

5/1/2014 6, 294, 181. 21 239, 939. 46 211, 091. 55 28, 847. 91 6, 083, 089. 66 $6,294,181.53 239,939.46 211,091.55 28,847.91$ $6,083,089.98 $6,294,181.53 $239,939.46 $211,091.55 $28,847.91 $6,083,089.98

6/1/2014 6, 083, 089. 66 239, 939. 46 211, 129. 70 28, 809. 76 5, 871, 959. 96 $6,083,089.98 239,939.46 211,129.70 28,809.76$ $5,871,960.28 $6,083,089.98 $239,939.46 $211,129.70 $28,809.76 $5,871,960.28

7/1/2014 5, 871, 959. 96 239, 939. 46 213, 026. 73 26, 912. 73 5, 658, 933. 23 $5,871,960.28 239,939.46 213,026.73 26,912.73$ $5,658,933.55 $5,871,960.28 $239,939.46 $213,026.73 $26,912.73 $5,658,933.55

8/1/2014 5, 658, 933. 23 239, 939. 46 213, 138. 56 26, 800. 90 5, 445, 794. 68 $5,658,933.55 239,939.46 213,138.56 26,800.90$ $5,445,795.00 $5,658,933.55 $239,939.46 $213,138.56 $26,800.90 $5,445,795.00

9/1/2014 5, 445, 794. 68 239, 939. 46 214, 148. 00 25, 791. 46 5, 231, 646. 67 $5,445,795.00 239,939.46 214,148.00 25,791.46$ $5,231,647.00 $5,445,795.00 $239,939.46 $214,148.00 $25,791.46 $5,231,647.00

10/1/2014 5, 231, 646. 67 239, 939. 46 215, 961. 50 23, 977. 96 5, 015, 685. 18 $5,231,647.00 239,939.46 215,961.50 23,977.96$ $5,015,685.50 $5,231,647.00 $239,939.46 $215,961.50 $23,977.96 $5,015,685.50

11/1/2014 5, 015, 685. 18 239, 939. 46 216, 185. 05 23, 754. 41 4, 799, 500. 13 $5,015,685.50 239,939.46 216,185.05 23,754.41$ $4,799,500.45 $5,015,685.50 $239,939.46 $216,185.05 $23,754.41 $4,799,500.45

12/1/2014 4, 799, 500. 13 239, 939. 46 217, 942. 17 21, 997. 29 4, 581, 557. 96 $4,799,500.45 239,939.46 217,942.17 21,997.29$ $4,581,558.28 $4,799,500.45 $239,939.46 $217,942.17 $21,997.29 $4,581,558.28

1/1/2015 4, 581, 557. 96 239, 939. 46 218, 241. 12 21, 698. 34 4, 363, 316. 84 $4,581,558.28 239,939.46 218,241.12 21,698.34$ $4,363,317.16 $4,581,558.28 $239,939.46 $218,241.12 $21,698.34 $4,363,317.16

2/1/2015 4, 363, 316. 84 239, 939. 46 219, 274. 74 20, 664. 72 4, 144, 042. 10 $4,363,317.16 239,939.46 219,274.74 20,664.72$ $4,144,042.42 $4,363,317.16 $239,939.46 $219,274.74 $20,664.72 $4,144,042.42

3/1/2015 4, 144, 042. 10 239, 939. 46 222, 212. 56 17, 726. 90 3, 921, 829. 54 $4,144,042.42 239,939.46 222,212.56 17,726.90$ $3,921,829.86 $4,144,042.42 $239,939.46 $222,212.56 $17,726.90 $3,921,829.86

4/1/2015 3, 921, 829. 54 239, 939. 46 221, 365. 67 18, 573. 79 3, 700, 463. 87 $3,921,829.86 239,939.46 221,365.67 18,573.79$ $3,700,464.19 $3,921,829.86 $239,939.46 $221,365.67 $18,573.79 $3,700,464.19

5/1/2015 3, 700, 463. 87 239, 939. 46 222, 979. 42 16, 960. 04 3, 477, 484. 45 $3,700,464.19 239,939.46 222,979.42 16,960.04$ $3,477,484.77 $3,700,464.19 $239,939.46 $222,979.42 $16,960.04 $3,477,484.77

6/1/2015 3, 477, 484. 45 239, 939. 46 223, 470. 14 16, 469. 32 3, 254, 014. 31 $3,477,484.77 239,939.46 223,470.14 16,469.32$ $3,254,014.63 $3,477,484.77 $239,939.46 $223,470.14 $16,469.32 $3,254,014.63

7/1/2015 3, 254, 014. 31 239, 939. 46 225, 025. 65 14, 913. 81 3, 028, 988. 66 $3,254,014.63 239,939.46 225,025.65 14,913.81$ $3,028,988.99 $3,254,014.63 $239,939.46 $225,025.65 $14,913.81 $3,028,988.99

8/1/2015 3, 028, 988. 66 239, 939. 46 225, 594. 26 14, 345. 20 2, 803, 394. 40 $3,028,988.99 239,939.46 225,594.26 14,345.20$ $2,803,394.72 $3,028,988.99 $239,939.46 $225,594.26 $14,345.20 $2,803,394.72

9/1/2015 2, 803, 394. 40 239, 939. 46 226, 662. 70 13, 276. 76 2, 576, 731. 70 $2,803,394.72 239,939.46 226,662.70 13,276.76$ $2,576,732.02 $2,803,394.72 $239,939.46 $226,662.70 $13,276.76 $2,576,732.02

10/1/2015 2, 576, 731. 70 239, 939. 46 228, 129. 86 11, 809. 60 2, 348, 601. 84 $2,576,732.02 239,939.46 228,129.86 11,809.60$ $2,348,602.16 $2,576,732.02 $239,939.46 $228,129.86 $11,809.60 $2,348,602.16

11/1/2015 2, 348, 601. 84 239, 939. 46 228, 816. 65 11, 122. 81 2, 119, 785. 19 $2,348,602.16 239,939.46 228,816.65 11,122.81$ $2,119,785.51 $2,348,602.16 $239,939.46 $228,816.65 $11,122.81 $2,119,785.51

12/1/2015 2, 119, 785. 19 239, 939. 46 230, 224. 20 9, 715. 26 1, 889, 560. 99 $2,119,785.51 239,939.46 230,224.20 9,715.26$ $1,889,561.31 $2,119,785.51 $239,939.46 $230,224.20 $9,715.26 $1,889,561.31

1/1/2016 1, 889, 560. 99 239, 939. 46 230, 990. 72 8, 948. 74 1, 658, 570. 27 $1,889,561.31 239,939.46 230,990.72 8,948.74$ $1,658,570.59 $1,889,561.31 $239,939.46 $230,990.72 $8,948.74 $1,658,570.59

2/1/2016 1, 658, 570. 27 239, 939. 46 232, 084. 72 7, 854. 74 1, 426, 485. 55 $1,658,570.59 239,939.46 232,084.72 7,854.74$ $1,426,485.87 $1,658,570.59 $239,939.46 $232,084.72 $7,854.74 $1,426,485.87

3/1/2016 1, 426, 485. 55 239, 939. 46 233, 619. 74 6, 319. 72 1, 192, 865. 81 $1,426,485.87 239,939.46 233,619.74 6,319.72$ $1,192,866.13 $1,426,485.87 $239,939.46 $233,619.74 $6,319.72 $1,192,866.13

4/1/2016 1, 192, 865. 81 239, 939. 46 234, 290. 35 5, 649. 11 958, 575. 46 $1,192,866.13 239,939.46 234,290.35 5,649.11$ $958,575.78 $1,192,866.13 $239,939.46 $234,290.35 $5,649.11 $958,575.78

5/1/2016 958, 575. 46 239, 939. 46 235, 546. 41 4, 393. 05 723, 029. 06 $958,575.78 239,939.46 235,546.41 4,393.05$ $723,029.38 $958,575.78 $239,939.46 $235,546.41 $4,393.05 $723,029.38

6/1/2016 723, 029. 06 239, 939. 46 236, 515. 55 3, 423. 91 486, 513. 51 $723,029.38 239,939.46 236,515.55 3,423.91$ $486,513.83 $723,029.38 $239,939.46 $236,515.55 $3,423.91 $486,513.83

7/1/2016 486, 513. 51 239, 939. 46 237, 710. 02 2, 229. 44 248, 803. 49 $486,513.83 239,939.46 237,710.02 2,229.44$ $248,803.81 $486,513.83 $239,939.46 $237,710.02 $2,229.44 $248,803.81

8/1/2016 248, 803. 49 249, 981. 42 248, 803. 49 1, 177. 93 ( 0. 00) $248,803.81 239,938.46 248,803.49 1,177.93$ $0.32 $248,803.81 $239,938.46 $248,803.49 $1,177.93 $0.32

11,527,136.04 10,317,103.22 1,210,032.82 8,348,536.76$ 1,089,913.22$ 3,168,556.32$ 3,048,436.72$ 120,119.60$ $11,517,093.08 $10,317,103.22 $1,210,032.82

ELECTRIC WATER ELECTRIC AND WATER


Docket 289 - Water Production Costs

($000s)

Schedule 7

Actual Actual Actual Forecast Forecast Forecast YTD Forecast Forecast Forecast Forecast Forecast Forecast YTD Total

Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 July - Dec. Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jan.-June FY 2013

St. Croix

Production/kGal/d 1,000 917 967 966 1,170 1,170 1,170 1,170 1,170 1,170 1,170 1,170 7,023 7,023

Days 30 30 30 30 30 30 30 30 30 30 30 30

Electricity Usage 1st Pass 367,566 342,076 362,125 361,706 438,930 438,930 2,311,334 438,930 438,930 438,930 438,930 438,930 438,930 2,633,583 4,944,917

Electricity Usage Ultra Pure

Monthly Production 1st Pass 30,015 27,514 29,010 28,989 35,114 35,114 185,756 35,114 35,114 35,114 35,114 35,114 35,114 210,687 396,443

Monthly Production Ultra Pure

Rate/kGal (1st Pass) 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$ 3.43$

Rate/kGal (Ultra Pure)

Production Costs ($000s) 103 94 100 99 120 120 636 121 121 121 121 121 121 726 1,362

Electricity Charge @.32 118 109 116 116 140 140 740 140 140 140 140 140 140 843 1,582

Total Water Purchase Cost Billed to Water Customers 221$ 203$ 216$ 215$ 260$ 260$ 1,376$ 261$ 261$ 261$ 261$ 261$ 261$ 1,569$ 2,944$

St. Thomas

Production/kGal/d 1,994 1,999 1,657 1,926 2,073 2,073 2,073 2,073 2,073 2,073 2,073 2,073

Days 30 30 30 30 30 30 30 30 30 30 30 30

Electricity Usage 1st Pass 628,800 220,400 516,000 614,800 777,192 777,192 3,534,384 777,192 777,192 777,192 777,192 777,192 777,192 4,663,153 8,197,538

Electricity Usage Ultra Pure 59,173 44,649 39,198 30,460 35,000 37,500 245,980 44,353 44,353 44,353 44,353 44,353 44,353 266,118 512,098

Monthly Production 1st Pass 59,812 59,984 49,721 57,783 62,175 62,175 351,651 62,175 62,175 62,175 62,175 62,175 62,175 373,052 724,703

Monthly Production Ultra Pure 14,626 11,077 10,500 10,850 14,000 15,000 76,053 17,741 17,741 17,741 17,741 17,741 17,741 106,447 182,500

Rate/kGal (1st Pass) 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$ 4.77$

Rate/kGal (Ultra Pure) 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$ 2.28$

Production Costs ($000s) 319 311 261 300 328 331 1,851 337 337 337 337 337 337 2,022 3,873

Electricity Charge @.32 220 85 178 206 260 261 1,210 263 263 263 263 263 263 1,577 2,787

Less: Amt. billed for Electricity Used for Ultra Pure Water (70) (53) (50) (52) (67) (72) (365) (85) (85) (85) (85) (85) (85) (511) (876)

Less: Amt. billed Electric for Internal Plant Use (98) (75) (71) (73) (94) (101) (512) (119) (119) (119) (119) (119) (119) (716) (1,228)


Total Water Purchase Cost Billed to Water Customers 351$ 249$ 302$ 363$ 407$ 399$ 2,071$ 375$ 375$ 375$ 375$ 375$ 375$ 2,253$ 4,324$

Combined Islands

Production/kGal/d

Days

Electricity Usage 1st Pass 996,366 562,476 878,125 976,506 1,216,123 1,216,123 5,845,718 1,216,123 1,216,123 1,216,123 1,216,123 1,216,123 1,216,123 7,296,736 13,142,454

Electricity Usage Ultra Pure 59,173 44,649 39,198 30,460 35,000 37,500 245,980 44,353 44,353 44,353 44,353 44,353 44,353 266,118 512,098

Monthly Production 1st Pass 89,827 87,498 78,731 86,772 97,290 97,290 537,407 97,290 97,290 97,290 97,290 97,290 97,290 583,739 1,121,146

Monthly Production Ultra Pure 14,626 11,077 10,500 10,850 14,000 15,000 76,053 17,741 17,741 17,741 17,741 17,741 17,741 106,447 182,500

Rate/kGal (1st Pass) STT 4.77 4.77 4.77 4.77 4.77 4.77 4.77 4.77 4.77 4.77 4.77 4.77

Rate/kGal (1st Pass) STX 3.43 3.43 3.43 3.43 3.43 3.43 3.43 3.43 3.43 3.43 3.43 3.43

Rate/kGal (Ultra Pure) 2.28 2.28 2.28 2.28 2.28 2.28 2.28 2.28 2.28 2.28 2.28 2.28

Production Costs ($000s) 422 405 361 399 448 451 2,487 458 458 458 458 458 458 2,748 5,235

Electricity Charge @.32 338 194 294 322 400 401 1,949 403 403 403 403 403 403 2,420 4,369

Electricity Charge @.32

Less: Amt. billed Electric for Electricity Used for Ultra Pure Water (70) (53) (50) (52) (67) (72) (365) (85) (85) (85) (85) (85) (85) (511) (876)

Less: Amt. billed Electric for Internal Plant Use (Ultra Pure Water) (98) (75) (71) (73) (94) (101) (512) (119) (119) (119) (119) (119) (119) (716) (1,228)


Total Water Purchase Cost Billed to Water Customers 572 453 518 578 668 659 3,447 637 637 637 637 637 637 3,822 7,268

1 April 4, 2012 Agreement Section 17.2

The Virgin Islands Water and Power Authority

LEAC Projection for Fiscal 2012_WAPA



Schedule 1

Page 1 of 2


Actual Actual Actual Actual Actual Actual Per. Ending Forecast Actual Actual Forecast Forecast Forecast Per. Ending TOTAL



Energy Sales:



3 Total Sales....Mwh 63,936 63,538 60,913 64,777 61,577 57,932 372,673 60,859 59,993 56,572 55,501 56,596 61,724 351,244 723,918 Line 1 + Line 2 550,097

Cost of Fuel:

4 St. Croix.......$ 9,670$ 9,800$ 9,837$ 10,295$ 8,448$ 8,413$ 56,463$ 7,780$ 7,284$ 7,904$ 8,007$ 8,080$ 6,626$ 45,681$ 102,144$ Schedule 3, page 1


6 Total Fuel Cost 23,886$ 22,856$ 22,161$ 25,524$ 19,339$ 19,696$ 133,462$ 18,819$ 17,426$ 18,850$ 18,173$ 19,038$ 16,889$ 109,195$ 242,657$ Line 4 + Line 5 68,903 242655

7 Hedging Costs/(Credits) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Schedule 5.1

8 Regulatory Expenses (Note 2) 0 0 0 0 0 0 0 0 0 73 0 0 176 249 249 Input


10 New $40MM Loan Principal (note 3) 532 530 532 539 537 544 3,215 542 544 556 550 556 622.60 3,370 6,585 Schedule 6

11 New $40MM Loan Interest & Fees 145 148 145 138 140 133 849 135 133 122 128 121 55 694 1,544 Schedule 6

12 Interest on $6MM LOC 23 24 47 25 0 25 71 WAPA Input


14 Less PILOT refund @ 124k per month (124) (124) (124) (124) (124) (124) (744) (124) (124) (124) (124) (124) (124) (744) (1,488) PSC Order #31/2010

Rate Financing Mechanism - 1,277 1,302 1,420 3,998 3,998

15 Over/Under recovery{Note 1} Footnote 2

16 Total Cost to be Recovered 24,511$ 23,481$ 22,809$ 26,149$ 19,964$ 20,344$ 137,258$ 19,444$ 18,051$ 19,573$ 20,074$ 20,965$ 19,110$ 117,216$ 254,474$ Sum(L9 - L15)

17 Quarterly LEAC Factor..($/Kwh) 0.317389 0.360676 0.352209 0.347618 0.335096 LEAC FACTORS

18 LEAC Recovery 20,293$ 22,917$ 21,970$ 22,815$ 21,688$ 20,404$ 130,086$ 21,156$ 20,854$ 19,666$ 18,598$ 18,965$ 20,683$ 119,922$ 250,009$ Line 3 x Line 20

19 Less Debt Service Recovery & LOC (677) (677) (700) (677) (677) (701) (4,111) (677) (677) (702) (677) (677) (677) (4,089) (8,200)$ Sum(L10+L11+L12)

20 Less Regulatory Asset/Pilot/Dkt 289 52 52 52 52 52 52 315 52 52 (21) 52 52 (124) 66 380$

Rate Financing Mechanism - - - - - - - - - - (1,277) (1,302) (1,420) (3,998) (3,998)$

21 Adjustments 1 9 9 (1) (2) (9) 6 (61) (20) (22) 549 173 (188) 431 437$ Input 250,445$

22 Net LEAC Recovery excluding P&I 19,668$ 22,300$ 21,331$ 22,189$ 21,061$ 19,747$ 126,296$ 20,469$ 20,209$ 18,920$ 17,246$ 17,212$ 18,275$ 112,332$ 238,628$ Sum(L12+L13)

23 (Over)/Under Recovery - Fuel only 4,218$ 556$ 830$ 3,335$ (1,722)$ (51)$ 7,166$ (1,650)$ (2,783)$ (70)$ 927$ 1,826$ (1,386)$ (3,137)$ 4,029$ Line 15 - Line 11

24 Beginning Balance (Note 1) 47,103 18,202$ 18,758$ 19,589$ 22,924$ 21,202$ 21,151$ 19,501$ 16,718$ 16,647$ 17,574$ 19,400$ Line 19 (prior Col.)

25 Monthly (Over)/Under 4,218 556 830 3,335 (1,722) (51) (1,650) (2,783) (70) 927 1,826 (1,386)26 Loan on Deferred Fuel-Open (33,119) Schedule 6

27 Additional due WAPA (Customer) 18,202$ 18,758$ 19,589$ 22,924$ 21,202$ 21,151$ 19,501$ 16,718$ 16,647$ 17,574$ 19,400$ 18,014$ 30,330$ 12,317$ L17+L18

28 Unamortized Loan Balance 32,586 32,056 31,524 30,985 30,448 29,903 29,362 28,817 28,262 27,712 27,156 8,533

29 Total Due WAPA (Deferred Fuel) 50,789$ 50,815$ 51,113$ 53,909$ 51,650$ 51,054$ 48,862$ 45,535$ 44,909$ 45,286$ 46,556$ 26,547$

18000

NOTE: 1 44,547

Ending Total Deferred Fuel Bal. at June 2011 47,103

Less: Loan on Under-recovery (33,119)

Additional Under-recovery 13,985

Loan Balance at June 2012 33,119

Loan Refinance during FY 2012 (18,000)

Principal Payment in FY 2012 (6,585)

Loan Balance ending June 2012 8,533

BeginningAdditional Under-recovery 13,985refinance of add'l under recovery 0

add'l fuel only underrecovery FY 2012 4,029$

June 2012 Add'l fuel ending balance 18,014

Ending Deferred balance & Loan (Mill) 26,547$

Ties to ending FY2011

balance.

89.2

%

C:\Users\Larry Gawlik\Documents\1Larry's Business Files\Georgetown\4Virgin Islands\2012 Activities\Jan - Mar 13 LEAC\GCG Analysis\final\Final Report\12 12 15 Fiscal 2012_GCG



Schedule 1

Page 1 of 2


Actual Actual Actual Actual Actual Actual Per. Ending Forecast Actual Actual Forecast Forecast Forecast Per. Ending TOTAL



Energy Sales:



3 Total Sales....Mwh 63,936 63,538 60,913 64,777 61,577 57,932 372,673 60,859 59,993 56,572 55,501 56,596 61,724 351,244 723,918 Line 1 + Line 2 550,097

Cost of Fuel:

4 St. Croix.......$ 9,670$ 9,800$ 9,837$ 10,295$ 8,448$ 8,413$ 56,463$ 7,780$ 7,284$ 7,904$ 8,007$ 8,080$ 6,626$ 45,681$ 102,144$ Schedule 3, page 1


6 Total Fuel Cost 23,886$ 22,856$ 22,161$ 25,524$ 19,339$ 19,696$ 133,462$ 18,819$ 17,426$ 18,850$ 18,173$ 19,038$ 16,889$ 109,195$ 242,657$ Line 4 + Line 5 68,903 242655

7 Hedging Costs/(Credits) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Schedule 5.1

8 Regulatory Expenses (Note 2) 0 0 0 0 0 0 0 0 0 73 0 0 176 249 249 Input


10 New $40MM Loan Principal (note 3) 532 530 532 539 537 544 3,215 542 544 556 550 556 622.60 3,370 6,585 Schedule 6

11 New $40MM Loan Interest & Fees 145 148 145 138 140 133 849 135 133 122 128 121 55 694 1,544 Schedule 6

12 Interest on $6MM LOC 23 24 47 25 0 25 71 WAPA Input


14 Less PILOT refund @ 124k per month (124) (124) (124) (124) (124) (124) (744) (124) (124) (124) (124) (124) (124) (744) (1,488) PSC Order #31/2010

Rate Financing Mechanism - 1,277 1,302 1,420 3,998 3,998

15 Over/Under recovery{Note 1} Footnote 2

16 Total Cost to be Recovered 24,511$ 23,481$ 22,809$ 26,149$ 19,964$ 20,344$ 137,258$ 19,444$ 18,051$ 19,573$ 20,074$ 20,965$ 19,110$ 117,216$ 254,474$ Sum(L9 - L15)

17 Quarterly LEAC Factor..($/Kwh) 0.317389 0.360676 0.352209 0.347618 0.335096 LEAC FACTORS

18 LEAC Recovery 20,293$ 22,917$ 21,970$ 22,815$ 21,688$ 20,404$ 130,086$ 21,156$ 20,854$ 19,666$ 18,598$ 18,965$ 20,683$ 119,922$ 250,009$ Line 3 x Line 20

19 Less Debt Service Recovery & LOC (677) (677) (700) (677) (677) (701) (4,111) (677) (677) (702) (677) (677) (677) (4,089) (8,200)$ Sum(L10+L11+L12)

20 Less Regulatory Asset/Pilot/Dkt 289 52 52 52 52 52 52 315 52 52 (21) 52 52 (124) 66 380$

Rate Financing Mechanism - - - - - - - - - - (1,277) (1,302) (1,420) (3,998) (3,998)$

21 Adjustments 1 9 9 (1) (2) (9) 6 (61) (20) (22) 549 173 (188) 431 437$ Input 250,445$

22 Net LEAC Recovery excluding P&I 19,668$ 22,300$ 21,331$ 22,189$ 21,061$ 19,747$ 126,296$ 20,469$ 20,209$ 18,920$ 17,246$ 17,212$ 18,275$ 112,332$ 238,628$ Sum(L12+L13)

23 (Over)/Under Recovery - Fuel only 4,218$ 556$ 830$ 3,335$ (1,722)$ (51)$ 7,166$ (1,650)$ (2,783)$ (70)$ 927$ 1,826$ (1,386)$ (3,137)$ 4,029$ Line 15 - Line 11

24 Beginning Balance (Note 1) 47,103 18,202$ 18,758$ 19,589$ 22,924$ 21,202$ 21,151$ 19,501$ 16,718$ 16,647$ 17,574$ 19,400$ Line 19 (prior Col.)

25 Monthly (Over)/Under 4,218 556 830 3,335 (1,722) (51) (1,650) (2,783) (70) 927 1,826 (1,386)26 Loan on Deferred Fuel-Open (33,119) Schedule 6

27 Additional due WAPA (Customer) 18,202$ 18,758$ 19,589$ 22,924$ 21,202$ 21,151$ 19,501$ 16,718$ 16,647$ 17,574$ 19,400$ 18,014$ 30,330$ 12,317$ L17+L18

28 Unamortized Loan Balance 32,586 32,056 31,524 30,985 30,448 29,903 29,362 28,817 28,262 27,712 27,156 8,533

29 Total Due WAPA (Deferred Fuel) 50,789$ 50,815$ 51,113$ 53,909$ 51,650$ 51,054$ 48,862$ 45,535$ 44,909$ 45,286$ 46,556$ 26,547$

18000

NOTE: 1 44,547

Ending Total Deferred Fuel Bal. at June 2011 47,103

Less: Loan on Under-recovery (33,119)

Additional Under-recovery 13,985

Loan Balance at June 2012 33,119

Loan Refinance during FY 2012 (18,000)

Principal Payment in FY 2012 (6,585)

Loan Balance ending June 2012 8,533

BeginningAdditional Under-recovery 13,985refinance of add'l under recovery 0

add'l fuel only underrecovery FY 2012 4,029$

June 2012 Add'l fuel ending balance 18,014

Ending Deferred balance & Loan (Mill) 26,547$

Ties to ending FY2011

balance.

89.2

%

C:\Users\Larry Gawlik\Documents\1Larry's Business Files\Georgetown\4Virgin Islands\2012 Activities\Jan - Mar 13 LEAC\GCG Analysis\final\Final Report\12 12 15 Fiscal 2012_GCG