Attachment C – Quarterly Electric and Fiber Issues Update
QUARTERLY ELECTRIC AND FIBER ISSUES UPDATE
April 2005
I.
Update on FERC, CAISO, CPUC, Transmission, and Other Related Activities
Electric Industry Market Design in California
The California Independent System Operator (CAISO) continues development of the Market
Redesign & Technology Update (MRTU)1 project toward a February 2007 implementation date.
This February 2007 implementation date is now referred to as Release 1, with Release 2 planned for
an undetermined future date. Policy and tariff issues deferred to Release 2 are those that the CAISO
has determined would delay the February 2007 implementation but that the market can function
without for a while. However, the CAISO has not shared any economic or risk analyses to show the
costs and benefits of market delay vs. implementation of an incomplete or flawed design.
The CAISO will be submitting a FERC filing in May that will ask for conceptual approval of three
market design proposals: 1) the mechanism for clearing demand bids; 2) the hour ahead scheduling
process; and 3) the market power mitigation provisions. At this point, the CAISO is no longer
considering the Transitional Alternative Pricing and Settlement (TAPAS)2 as it is confident that the
market power mitigation and seller’s choice issues have been satisfactorily addressed, but no details
have been provided. Following the FERC filing, and starting in May, the CAISO will be holding
monthly stakeholder meetings on remaining policy and tariff issues for Release 1. Staff from Palo
Alto and other Bay Area cities in addition to consultants is participating in the CAISO stakeholder
groups with the goal of preserving the value of the City’s current contracts and Metered Subsystem
(MSS) status. Current issues of interest to the City include:
1. A key element of the Locational Marginal Pricing (LMP) market design is the use of Congestion
Revenue Rights (CRRs) as a hedge against the risk of congestion costs. The CAISO is
conducting its CRR Study 2, which the City is participating in via the Northern California Power
Agency (NCPA). The goal of the study is to determine the effectiveness of CRRs as a hedge
against annual congestion costs. Results from the study are now expected by end of July 2005.
These results should provide more insight on congestion cost risk for the electric portfolio.
2. Depending on the results of the CRR study the CAISO may revisit the design of the Load
Aggregation Prices (LAP). Currently there are three LAPs proposed, covering the service
territories for each of the three large investor-owned utilities (IOUs) in California. The LAPs
were successfully argued for to address equity issues for municipal utilities embedded in load
pockets in an IOU’s service territory. The current proposal for LAP design would mean that Palo
Alto load would pay a load-weighted average of all the nodal prices in PG&E’s service territory
1 Formerly known as Market Design 2002 (MD02)
2 TAPAS was being developed as a contingency market settlement design in the event that concerns the CAISO has
about the economic impact of the Sellers’ Choice contracts (refers to a set of contracts negotiated by the state during
the energy crisis, which provided for the sellers option to pick delivery points and under some contracts both
delivery and receipt points) and market power issues under a Locational Marginal Pricing (LMP) settlement regime
were not resolved by February 2007.
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rather than an (expected higher) nodal price in the congested Bay Area. The LAP construct is
now under attack on the grounds that constraints internal to the LAP will reduce the volume of
feasible CRRs, and the value of the CRR hedge, when the CRR sink is at a highly aggregated
LAP. At this time, there is no indication of the financial impact to the City if the CAISO were to
move to a more granular LAP design. The CAISO and market participants are waiting on the
results of the CRR Study to better understand the impact that highly aggregated LAPs have on
the availability of CRRs.
3. In March, California Municipal Utilities Association (CMUA) members met with CAISO staff to
discuss the treatment of municipal utilities and particularly MSS agreements under MRTU. The
CAISO staff affirmed that a load following MSS is exempt from certain CAISO market
mechanisms, such as residual unit commitment and must offer obligations, and would continue
to have flexibility to schedule MSS load and resources. However, NCPA highlighted a loophole
concerning the use of MSS resources: MSS resources can only be called on by the CAISO in a
contingency, but the contingency definition is broader than NCPA anticipated and includes
planned outages for maintenance. This use for planned outages could drain NCPA’s energy or
use-limited resources. NCPA has requested that the CAISO communicate and coordinate with
NCPA in the future when the CAISO has requests for planned outages that could result in
contingency use of NCPA resources.
Resource Adequacy
Another major component of California’s market redesign is the resource adequacy requirement (RAR)
whereby utilities are expected to demonstrate ahead of time that they have adequate generation capacity
to meet their load requirements. The lead agency for this issue has been the California Public Utilities
Commission (CPUC). The CPUC is establishing RAR for the IOUs to be in place for summer 2006.
Under the CPUC requirements, IOUs will have to show that they have capacity available for 115% of
their forecasted peak demand in each month. It has been recognized by the CAISO that insufficiency in
resource adequacy is an IOU problem, and that for municipal utilities, operating under a different
regulatory structure, resource adequacy is already a standard component of their resource planning. In
recognition of this, the CAISO has stated that it does not intend to impose the same CPUC obligations
on the municipal utilities for now.
Given the uncertainty in how long municipal utilities will retain this exemption (or its acceptance by
FERC), staff has assessed the electric portfolio’s ability to meet new capacity requirements under
various hydro, load and regulatory scenarios. Under an expected case scenario, staff has concluded
that the electric portfolio has sufficient capacity to meet general RAR through existing resources and
forward purchases. Staff will continue to monitor regulatory progress and advocate full credit for
existing resources.
Resource adequacy will probably include a local capacity requirement. Initial estimates are that one
third of load in the Greater Bay Area will have to be met by in-area generation. One proposal is for
the IOUs and/or the CAISO to procure local capacity and pass the costs through to entities serving
load in the congested area. How the local capacity charges would be allocated to municipal utilities
located in a participating transmission owner’s (PTO’s) service territory is anticipated to be a
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contentious issue. At this time, there is not a liquid capacity market, but staff is considering local
capacity requirements in the analysis of long-term resource investments.
Transmission and Other Related Activities
At the City’s request PG&E has prepared a Study Plan for the City to convert the RavenswoodColorado lines to 230 kilovolt (kV) service. This consists of a system impact study and cost estimate
for conversion of two of the existing three 115 kV lines to 230 kV operation. Staff is also evaluating
the feasibility of a 230 kV connection to the west of the City. A comprehensive analysis of ways to
reduce the City’s escalating transmission and related costs is being undertaken and is expected to be
presented to the UAC and Council in Fall.
Plans are on track to move the California-Oregon Transmission Project (COTP) to the Sacramento
Municipal Utility District (SMUD) control area by the last quarter of 2005.
II.
Western Area Power Administration (Western) Issues & LEAP Update
Western Issues
Western is slowly adjusting to operation under its new marketing plan and new sub control area in
the SMUD control area. A number of resource communication glitches, and sub-optimal control
strategies have appeared between the Bureau, Western and the customers. Efforts are underway to
improve the situations in the coming months. For example, the transfer of information between the
two federal agencies (Reclamation and Western) needs to be smoothed out and better resource
utilization strategies need to be developed and implemented. The agencies have started meetings
with the active customer group to work on identifying and pursuing the improvements.
Western Post-2004 Base Resource Contract
With the reduction of pumping loads after completing the filling of San Luis reservoir in mid March,
Western has begun to provide noticeable amounts of energy to Base Resource. NCPA is managing
the resource on a daily basis. For the first quarter of 2005, Palo Alto received a total of 7.5 GWh
from Western, representing 11% of the Greenbook Long-term Average generation for the same
period.
Western Base Resource Forecasting Process
During months of February through May, the Bureau relies on California Department of Water
Resources forecasts of April-July snowmelt runoff into reservoirs for their monthly water modeling.
Small changes in these runoff forecasts can have significant impacts on water management models,
water release decisions and on the monthly and annual amounts of net generation available. Staff has
been monitoring and reacting to the changes in the resulting power forecasts. Staff is developing an
extended version of the Bureau model to estimate power production for 15 months into the future.
Western started providing a rolling 12-month forecast in April 2004. Prior to April 2004, staff used
Western’s Greenbook Long-term Average generation figures for planning and procurement purposes,
which estimates Palo Alto’s share of Western Base Resource to be 388 GWh for 12 months.
Western’s April 1, 2005 12-month forecast estimates Palo Alto’s share of Base Resource to be 243
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GWh, representing a 37% drop from the Greenbook Long-term Average generation. Based on
current market prices, this drop in supply represents an increase in supply cost for Palo Alto, in
FY05-06, of approximately $7 million. Figure 1 shows Palo Alto’s share of Western’s 12-month
rolling forecast as projected over the last 12 months. Figure 2, shows Palo Alto’s projected monthly
share of Base Resource versus the Greenbook Long-term Average.
Figure 1
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Figure 2
Western Post-2004 Rates
Palo Alto has been paying about $300,000 each month for Base Resource in the winter season and
will pay about $450,000 each month in the April-October period.
Hydro Hedge
Staff has been exploring a complementary Energy Exchange product to manage the monthly hydro
uncertainty associated with Palo Alto’s Western Base Resource. Staff is analyzing the desired
structure and value of an exchange of uncertain monthly energy volumes equal in size to the energy
provided by Western to one of the Electric Master Agreement counterparties in exchange for a
certain prescribed volume of monthly energy from the counterparty. Palo Alto would continue to
pay for and receive the Western Base Resource. The complementary exchange would provide an
energy flow to or from Palo Alto that would make the sum of the Base Resource and the
complementary flow equal to the average year Western Base resource amount. Staff may seek UAC
recommendation this summer to pursue such an exchange this fall for flows over the coming 3-6
years.
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Long Term Electric Acquisition Plan (LEAP) Implementation Update
Staff is working on a number of aspects related to the LEAP implementation plan approved by the
Council on August 7, 2003. A detailed informational LEAP update report was provided to the UAC
in March and to Council in April 2005 [CMR:198:05].
The completion date for the first phase of the local generation feasibility study has been extended by
approximately three months. During the current phase of the feasibility study, staff is evaluating the
potential for smaller-scale distributed generation and cogeneration alternatives. These alternatives
will then be contrasted with more conventional centralized generation options. Initial interactions
with several large customers indicate a strong interest in smaller-scale distributed cogeneration
opportunities, driven by both cost savings and customer environmental objectives. Staff is
evaluating the technical and economic feasibility of these alternatives to include in information to be
shared with the public to solicit input in the long-term electric plan.
Staff has developed a public participation plan for the local generation feasibility study, which aims
to engage the public in understanding and discussing the overall long-term electric plan, not just the
local generation aspects. Staff is working to post the LEAP information on CPAU’s website. Staff
expects to roll out some of this information over the next few months.
Market Prices
Wholesale power prices remain relatively high and volatile, as the prices tend to follow natural gas
prices. The Northern California on-peak strip price for the post 2004 period is currently trading at
$71 per megawatt hour (MWh). The current price is significantly higher than the all-time low price
of $33 per MWh in January 2002. Summer 2005 on-peak prices are expected to reach $90 per
MWh. Figure 3 shows 2005 to 2009 calendar year strip forward prices for Northern California.
Figure 4 shows historical and projected monthly forward prices for Northern California.
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Figure 3
Figure 4
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Load and Resource Balance
Figure 5 below shows the monthly load-resource balance for the next three years. Projections for
hydro resources from Calaveras and Western for the next 12 months are based on Western’s and
NCPA’s current projection of generation which takes into account existing reservoir levels and
average precipitation and inflow conditions. Beyond 12 months, the Greenbook Long-term Average
forecast of generation is used for Western Base Resource and historical long-term average generation
is used for Calaveras. As mentioned above, Western Base Resource for the next 12 months is
expected to be below average, however hydro supply from Calaveras for the same period is projected
to be 123% of average. For the prompt 36 months the electric portfolio is expected to be deficit 580
GWh or 20% deficit as a percent of load. For the prompt 12 months the portfolio is 9% deficit as a
percent of load. A fiscal year summary of the City’s load-resource balance is shown in Figure 6.
Staff continues to purchase diversified “laddered” blocks of electric power to fill short to mid-term
supply needs. For the prompt 36 months, fixed price forward purchases from suppliers under the
Electric Master Agreements (EMA) will make up ~800 GWh representing 26% of expected load for
the same period. The Quarterly Energy Risk Manager’s report to Council provides for the details of
all forward transactions made. As reported in the Risk Manager’s report, the mark-to-market
(market value of contracts minus contract cost) of the forward contracts through December 2009 is
$18.7 million due to the dramatic increase in forward market prices. The energy quantity associated
with all EMA forward transactions (January 05 to Dec 2009) is 980 GWh with an average purchase
cost of $46/MWh.
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Figure 5
Figure 6
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III. Miscellaneous Legislative/Regulatory Issues Update
PG&E-Western Transmission Related Cost Pass-Through
Western, through a series of invoices and verbal representations from PG&E, has been presented
with alleged cost liabilities of approximately $51 million associated with retroactive Grid
Management Charges (GMC), Scheduling Coordinator Services (SCS) charges, transmission and
Reliability Services (RS) charges for the period 2001 to 2004. Western is litigating the legitimacy of
these costs in a proceeding currently pending before FERC and is now in the process of attempting to
figure out how this cost would be apportioned among its customers. A FERC hearing on this issue is
not expected until September 2005, with no resolution expected for a couple of years. However, the
City may have to pay these bills, subject to refund.
If PG&E succeeds in passing on this cost to Western customers, the potential Palo Alto liability
could be as high as $12 million. Staff has kept the UAC informed of the uncertainty in transmission
costs through the UAC quarterly reports (August 2003 and 2004). Actual transmission costs
incurred by CPAU have been consistently lower than budgeted costs during the period 2001-2004.
State Legislative Bills
The 2005/2006 Legislative session started with a plethora of utility related bills. Electricity related
bills cover resource adequacy provisions, core/noncore electricity markets and retail access,
renewable portfolio standards, local control, exit fees, climate change, and solar home funding. Staff
is currently drafting comments on SB 1 (the Governor’s million solar roofs initiative) and AB 1585,
which would require municipal utilities to adopt a statewide renewable portfolio standard to be
established by the CEC.
Federal Bills
The House Energy and Commerce Committee opened mark-up on a national energy policy bill in
April. Committee Chair Joe Barton (R-TX) hopes to complete committee action and take the bill to
the House floor the week of April 18.
NCPA is particularly engaged in support of a native load, service obligation amendment to be
introduced during markup by Congressman Roy Blunt (R-MO). Section 1236 of the electricity title
in the bill being marked-up protects the rights of incumbent utilities with legal obligations to serve
consumer load to use long-term, firm transmission to meet their service obligation.
Another issue before the committee is a vote on an amendment offered by ranking Member John
Dingell (D-MI) that would strike hydropower relicensing language in the bill that is supported by
NCPA, and by the American Public Power Association. The bill allows applicants for relicensing to
propose alternative environmental strategies that are less expensive than those being imposed upon
them if those strategies will accomplish the same results. The issue was strenuously debated during
markup, and Chairman Barton held the vote over so that an effort might be made to reach agreement
on a compromise acceptable to both sides. Expectations are that the Dingell amendment will be
defeated.
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Upcoming Contracts for Council Approval
On May 2, 2005 staff is seeking Council approval to subscribe the Central Valley Project
Corporation Seasonal Energy Exchange agreement as recommended by the Finance Committee on
April 5, 2005. The energy exchange is expected to be a low risk way to produce benefits of $30,000
to $60,000 per year and have a strategic benefit of more involvement in meeting Western needs.
IV.
Telecommunications Update
Dark Fiber*
Staff completed a Draft Phase 1 – Business Plan, and is working on Phase 2 that includes the
proposed Strategic Scenarios of product offerings and a business model. In order to come up with
these strategies, staff is planning to conduct customer and market research efforts in the next 2-3
months.
The table below summarizes the comparative changes occurring in the 1st quarter of 2005 and 2004,
and the first 3-quarters of Fiscal Year 04-05 and Fiscal Year 03-04. For the current Fiscal Year,
changes in sales indicate an economic recovery and focused marketing efforts. For the 3-Quarter
comparison, the annual revenue impact of new projects has been significantly higher in current Fiscal
Year ($177,776) than last Fiscal Year ($70,691). Current annual licensing fee projections for the
Fiscal Year are $1.35 million (26% increase from last fiscal year, target was 10%).
INCREMENTAL IMPACT FROM CURRENT FISCAL YEAR ACTIVITY
Sales
Terminations
Period
# of
Annual
# of
Annual
Projects Revenue Projects
Losses
Net Annual
Impact
Quarterly Comparison
Jan 2004 – March 2004
Jan 2005 – March 2005
2
8
$11,262
$81,013
8
2
$122,259
$3,791
($110,997)
$77,222
3-Quarter Comparison
July 2003 – Mar 2004
July 2004 – Mar 2005
10
15
$70,691
$177,776
13
2
$195,070
$3,791
($124,379)
$173,985
In addition to the increased revenues mentioned, there are four new fiber optic projects currently
under construction, which will increase revenue an additional $52,891 annually.
Fiber To The Home (FTTH)
Staff continues to maintain the FTTH Trial, and monitors the developments related to other FTTH
projects. Staff submitted a report on the new emerging technology, called Broadband-overPowerline (BPL), and recommended that no BPL activity be initiated until the technology, which is
in its infancy, stabilizes into a commercial product.
*
See end of Attachment C for Dark Fiber Operations Statement of Income prepared by Administrative Services
Department (there is no update from last Quarterly Report.)
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V.
Electric Public Benefits Program Update
Residential Measures Report (for the period 01/01/05 to 03/31/05)
Measure
Boiler
Ceiling Insulation
Central Air Conditioner
Clothes Washer
Dishwasher
Equipment Tune-up
Gas Furnace
Programmable Thermostat
Refrigerator
Count
3
10
5
129
126
104
14
31
99
Rebate
Amount
$900
$900
$1,200
$29,750
$9,225
$2,825
$4,200
$1,593
$11,750
521
$62,343
Totals
Energy
Svgs./Yr.
0
7,875
86,688
9,450
37,742
0
0
50,787
Therms
Svgs./Yr.
138
4,088
0
0
0
0
1,666
1,680
0
Customer
Svgs/Yr.
$151
$4,462
$709
$7,802
$851
$3,397
$1,818
$1,834
$4,571
192,542
7,572
$25,594
PV Partners
Period
FY 04-05 To Date
Pending Applications
Installed to date (since 10/1/99)
Number of Systems
10
11
95
Peak kW
24
40
293
Rebates
$83,000
$124,000
$1,020,000
Palo Alto Green
As of April 1, 2005, Palo Alto Green (PAG) has approximately 3243 active participants or 11.76%
of all electric accounts. PAG continues to be the second highest participated program in the nation
based on the percentage of utility customer enrollment. PaloAltoGreen customers consumed
3,878,231 kWh during the Q2 November 2004 through February 2005 or approximately 3% of total
citywide sales. PAG has also set a new goal of 15% community participation rate.
Consultant Assistance for Resource Efficiency (CARE)
To date, two studies were completed in FY 04-05 at a cost of $20,875
Commercial Advantage Program
Period
No. Applications MWh/yr. Peak kW Therms/yr.
Rebates
FY 04-05 Completed To Date 13
1,112
229
253,300
$130,000
Installed to date (since 10/99) 209
11,914
1,483
2.73 Million $3.7 million
Low-Income Program
The City of Palo Alto Utilities (CPAU) is committed in assisting low-income customers. To
provide financial relief to qualifying low-income customers, CPAU offers several key programs
to help customers in need. CPAU also works closely with other city, state and non-profit
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agencies such as the Urban Ministry and Saint Vincent DePaul to direct and refer qualifying low
income customers to other support services.
Rate Assistance Program
Since 1993, CPAU has offered the Rate Assistance Program (RAP) to provide rate relief to lowincome and medically disabled customers (CMR: 262:93). For qualified applicants, the lowincome option offers a 20 percent discount on the three basic utilities: electric, water and gas.
Under the medical option, a 20 percent discount is offered on a specific utility the customer’s
disability directly affects usage on that utility. Applicants can qualify under both the low-income
and medical plans.
At the end of calendar year 2004, CPAU through the Rate Assistance Program discounted a total
of $278,198.
ProjectPLEDGE
In 1995-96 at the direction of Council, staff designed and implemented ProjectPLEDGE a
voluntary ratepayer donation program to help residents who are unable to pay their utility bills
due to financial hardship. With this program, ratepayers would voluntarily pledge a given
amount that would be added to their utility bill charges each month.
ProjectPLEDGE is designed to operate at minimal cost to CPAU by using utility bills to collect
contributions. The contributions assist the elderly, disabled, and individuals or families
experiencing an unusual hardship such as; loss of job, medical problems, and recent desertion or
abandonment.
Since ProjectPLEDGE’s inception in 1997 CPAU has disbursed over $84,000 qualifying
customers.
Residential Energy Assistance Program
Beginning July 1, 2005 and Council approval, CPAU will implement the Residential Energy
Assistance Program (REAP). This is a turnkey program wherein CPAU will contract with a third
party vendor to provide qualifying applicants with an energy and water audit to identify potential
utility cost savings and installation of energy efficient items including a home weatherization,
diagnostic energy efficiency testing, minor plumbing, electrical repairs, weather stripping,
caulking, insulation, and other energy efficiency improvements. Including installation of
ENERGY STAR programmable thermostats, furnaces, refrigerators and water heaters, compact
fluorescent lighting, and low flow plumbing devices to qualified customers.
Low Income Home Energy Assistance Program (LIHEAP)
This is a federally funded program that helps low-income households pay their energy bill.
Eligibility is determined by the State of California. The federal mandate for this program is to
target households with low-incomes and high energy costs taking in consideration households
with elderly and disabled persons and children under age six.
The assistance is in the form of a one-time payment made directly to the utility company on
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behalf of the eligible applicant. Last year, CPUA received $17,080 in direct payments. Because
this is a federally funded program, the amount of money available to the states varies from year
to year.
Housing and Energy Services Program
In 2003, the Planning and Community Environment department implemented the Housing and
Energy Services Program funded through a Community Development Block Grant (CDBG). The
focus for this program is improvements to home access, safety measures, general home maintenance
repairs and some weatherization.
VI.
Key and Major Accounts
On Tuesday March 29, 2005 the Utilities Department hosted a Facilities Managers Meeting held at
Hewlett Packard. There were 32 guests representing 19 of Palo Alto’s Key and Major Customers.
Guest speakers were Council Member Bern Beecham and Utilities Director John Ulrich. Council
Member Beecham talked about the status of the Hetch Hetchy water system. Mr. Ulrich spoke on
local emergency water supply options and existing system operations followed by a discussion on
proposed utility rate increases.
As part of a local generation feasibility study being conducted by the Resource Management group,
staff met with four of the City’s largest commercial customers to determine their level of interest in
the installation of a combined heat and power cogeneration system at their respective sites. The
initial meeting generated significant interest from all customers interviewed. Further discussions
with these customers will be held as the feasibility study progress in the future.
VII. Operations Update
See the three attached graphs showing operational performance measures for FY 04-05 through
March 2005:
1.
Electric Service Interruptions – FY 04-05 (number and types of outages)
2.
Electric Service Interruptions – FY 04-05 (average minutes per customer affected)
3.
Electric Service Interruptions – FY 04-05 (minutes per customer per year)
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Electric Service Interruptions FY 04/05
Overhead
Underground
Other
Storm
6
5
Outages
4
3
2
1
0
July
Aug
Sep
Oct
Nov
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Dec
Jan
Feb
Mar
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Apr
May
Jun
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Averae Minutes per Customer Affected
Electric Service Interruptions FY 04/05
180
165
160
149 150
Goal - 120 minutes
per customer
140
125
120
104
100
91
Does not include storms
103
89
80
All outage data
60
40
20
0
0
July Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
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Electric Service Interruptions FY 04/05
70
Goal- 60 minutes per
customer per year
Minutes per Customer
60
62
53
50
55
57
All outage data
40
30
22
20
23
25
Does not include storms
10 9
0
0
July Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
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City of Palo Alto
Utilities Department
Dark Fiber Operations
Statement of Income
Cost Center: 20020501, 20020502, 20020503, 20020601
Budget for Twelve
Months Ended 6/30/2005
Actuals for Six Months
Ended 12/31/2004
% of Budget Remaining
Revenues:
Fiber Optic Adv Engineering Fee
Fiber Optic Interconnection Fee
Fiber Optic License Fee
Drop Cable Mgmt Fee
Fiber Optic Misc Rev
Fiber Optical Rev
Fiber Optic Fee to City Depts
Drop Cable Fee to City Depts
Sales Adjustments
Total
30,000
370,000
1,120,000
120,000
1,640,000
5,380
38,699
534,585
1,116
9,418
39,036
78,467
39,779
746,480
82.1%
89.5%
52.3%
100.0%
Expenses
Salaries and Benefits
Contract Services
Supplies & Materials
General Expense1
Rent and Leases
Allocated Charges
Total
662,304
130,318
23,859
420,443
56,000
241,000
1,533,924
262,155
17,145
23,328
370
11,851
116,621
431,470
60.4%
86.8%
2.2%
99.9%
78.8%
51.6%
71.9%
106,076
315,010
Excess of Revenues over Expenses
1Budget
amount includes $401,443 for CIP
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54.5%