HomeMy WebLinkAboutStaff Report 2681
City of Palo Alto (ID # 2681)
Finance Committee Staff Report
Report Type: Meeting Date: 4/18/2012
April 18, 2012 Page 1 of 18
(ID # 2681)
Summary Title: Gas Utility Financial Projections
Title: Gas Utility Five-Year Financial Projections (FY 2013 - FY 2017)
From: City Manager
Lead Department: Utilities
Recommendation
This report is provided to the Finance Committee to support its discussion of the long-term
financial projections and revenue requirements for the Gas Fund. No action is required.
Executive Summary
Since the market price for gas is expected to be significantly below the current supply rate, gas
supply sales revenue is expected to decrease by 35% in FY 2013. Distribution sales revenue in
FY 2013, however, must increase by 25% to cover costs. This distribution sales revenue
increase is a one-time adjustment to properly allocate and align distribution costs.
The financial forecast assumes implementation of market price-based retail commodity rates
starting July 1, 2012. This change prompted a review of the costs and revenues for the supply
and distribution fund centers. Since the market price for gas is expected to be significantly
below the current supply rate, gas supply sales revenue is expected to decrease by 35% in FY
2013. However, distribution sales revenue must increase by 25% to cover costs that have been
increasing since the last rate adjustment in July of 2009 as explained in Gas Distribution
Revenues section of the report. The overall impact is an expected reduction of 10% in the
system average gas rate for FY 2013. These rate projections assume that actual gas spot prices
will be equal to the forward gas prices as of November 15, 2011, the due date for FY 2013
budget submissions. Since gas supply rates will change monthly and will be passed directly on
to customers, the system average rate could be higher or lower than this projection. For
example, forward gas prices as of February 14, 2012 are 15% lower than those on November 15,
2011.
The projected revenue adjustments to distribution rates align revenues with the cost of
providing those services. After a 25% revenue increase in distribution rates for FY 2013,
increases of 3%, 4%, and 3% are projected for FY 2015, FY 2016, and FY 2017, respectively. Staff
will return to the Finance Committee in May with proposed changes to the gas rate schedules
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effective July 1, 2012 and revisions to the Gas Supply and Distribution Rate Stabilization Reserve
Guidelines as a result of Council direction to implement market price -based retail supply rates.
Background
In order to maintain the financial viability of the Gas Fund, staff conducts an annual review of
major cost drivers and expected costs; evaluates risks and adequacy of reserves; and determines
the revenue requirements for the Gas Fund for the next five years. The revenue requirements
and resulting projected rate adjustments depend on a number of factors including sales
revenue projections, gas supply costs, distribution system operating and Capital Improvement
Program (CIP) expenses, debt service payments, and prudent funding of the Gas Supply Rate
Stabilization Reserve (G-SRSR), the Gas Distribution Rate Stabilization Reserve (G-DRSR), and
the Emergency Plant Replacement (EPR) Reserve. Changes in these factors can trigger an
adjustment to the revenue requirement.
The City Council directed the staff to implement gas retail commodity rates based on market
prices (Staff Report 2106). This change, to be implemented in rates effective on July 1, 2012,
required a review of the costs and revenues of the gas supply and gas distribution units to
ensure that revenues will cover costs.
Discussion
Summary of Financial Projections
Table 1 below shows the summary of financial projections for the Gas Fund for FY 2012 to FY
2017. Financial projections for gas supply and gas distribution funds include expected supply
and distribution revenue adjustments as a result of the move to market -based supply retail
rates. In summary, the market price for gas is expected to be significantly below the current
supply rate, and since the market price will be passed through to customers, gas su pply sales
revenue is expected to decrease by 35% in FY 2013. However, distribution sales revenue must
increase by 25% to cover costs that have been increasing since the last rate adjustment in July
of 2009 as explained in Gas Distribution Revenues section of the report. The overall estimated
impact on the combined supply and distribution revenues is a reduction of 10% in the system
average gas rate.
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Table 1: Gas Fund - Summary of Financial Projections
($'000)
Adopted Actual Adopted Projected
2011 2011 2012 2012 2013 2014 2015 2016 2017
1 % CHANGE IN TOTAL SYSTEM RETAIL RATE 2%-3%1%-1%-10%4%5%4%4%
2 TOTAL SYSTEM AVERAGE RATE ($/Therm)1.440$ 1.394$ 1.412$ 1.395$ 1.258$ 1.305$ 1.370$ 1.421$ 1.473$
3 COMMODITY COST ($/Therm)0.772$ 0.686$ 0.614$ 0.588$ 0.517$ 0.529$ 0.567$ 0.589$ 0.617$
4 SALES IN THOUSAND THERMS 30,882 30,914 30,685 30,447 30,477 30,487 30,487 30,495 30,483
5
6 Utilities Retail Sales 43,992 42,531 43,078 42,226 37,877 39,532 41,492 43,071 44,633
7 Service Connection & Capacity Fees 700 700 710 710 720 730 752 790 812
8 Other Revenues & Transfers In 88 111 96 96 96 96 96 96 96
9 Interest plus Gain or Loss on Investment 847 821 948 948 712 612 502 500 505
10 Total Sources of Funds 45,628 44,164 44,832 43,980 39,404 40,970 42,842 44,457 46,046
11
12 Supply Purchases 24,532 21,438 19,397 18,497 16,286 16,672 17,856 18,567 19,419
13 Supply and Distribution Operations 10,967 9,319 14,957 14,957 11,199 12,555 11,861 12,120 12,382
14 Debt Service Payments 947 947 948 803 803 802 802 802 802
15 Rent 215 215 215 215 220 224 228 233 238
16 Transfers to General Fund 5,304 5,304 6,006 6,006 5,995 6,396 6,623 6,861 7,104
17 Other Transfers Out 614 1,075 170 170 170 170 170 170 170
18 Capital Improvement Programs 8,325 8,325 7,821 8,021 7,706 5,377 5,538 5,617 6,113
19 Total Uses of Funds 50,905 46,622 49,513 48,669 42,379 42,196 43,078 44,370 46,228
20
21 Into/ (Out of) Reserves (5,278)(2,459)(4,681)(4,689)(2,975)(1,226)(236)87 (182)
Fiscal Year
City of Palo Alto
Gas Utility FINANCIAL PROJECTIONS SUMMARY
(Jan 2012)
For FY 2011, both budgeted and realized actuals based on the City’s Comprehensive Annual
Financial Report (CAFR) are shown. For FY 2012, both budgeted and projected financial
expectations are shown. The projected values for FY 2012 reflect known variations from the
budget as of January 2012.
Total uses of funds (Line 19 in Table 1) was $46.6 million in FY 2011, which is $4.3 million lower
than budgeted mainly as a result of $3.1 million lower than expected supply purchase costs and
$1.6 million lower than budgeted distribution operations expenses. Total sources of funds (Line
10 in Table 1) was $44.2 million, which is $1.4 million lower than budgeted mainly due to the
lower than expected revenues from the large customers that have market-based supply rates.
As a result, the Gas Fund withdrew $2.5 million, instead of the budgeted $5.3 million, from
reserves in FY 2011.
The projections for FY 2012 follow a somewhat similar pattern. Supply purchase costs are
expected to be $900,000 less than budgeted due to the decrease in market prices, and debt
service payments are expected to be $145,000 less than budgeted due to the refinancing of the
existing gas and water utility bonds in FY 2011. These savings are offset by a mid -year budget
request of $200,000 for increased street cut fees, resulting in a net reduction in total use of
funds of $844,000 for FY 2012. Variations in other costs and revenues will not be available until
the financial books for FY 2012 are closed in November 2012. As a result, the expected reserve
withdrawal of $4.7 million for FY 2012 remains unchanged at this time.
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Looking forward, the Gas Fund is not projected to face significant cost increases as a whole. In
FY 2013, a $2.2 million reduction in supply p urchase costs and another $3.8 million reduction in
supply and distribution operations costs are forecast, reflecting reduced costs for the cross -
bore program. In total, costs are expected to decrease by $6.0 million in FY 2013 from $48.7
million in FY 2012 and then gradually increase to $46.6 million by FY 2017, primarily due to
projected increases in gas commodity costs and in charges paid to Pacific Gas and Electric
Company (PG&E) for gas transportation.
The revenue requirements presented in this report are provided for information purposes only
at this time. Staff will return in May to recommend specific rate adjustments. At that time, staff
may propose revisions to the G-SRSR guidelines, if appropriate, to implement market-price
based gas supply retail rates.
Gas Demand Projections
Gas demand in Palo Alto is generally volatile, varying with both the economic and weather
conditions. After a significant drop from its peak1 of 40.7 million therms in FY 1999 to 31.5
million therms in FY 2004, gas demand stabilized somewhat, but continued with its general
downward trend, decreasing by 3.2% in total during the next five years as a result of continued
investments in energy efficiency and conservation, reaching 30.5 million therms in FY 2009.
The City’s gas demand was stable at that level in FY 2010 and FY 2011, with the exception of a
small upward adjustment due to weather. The long-term projections include a downward
correction for FY 2012 to reflect the effect of weather normalization as well as the loss of a
major customer, whose gas use is expected to be replaced gradually over the next four years.
The demand projections incorporate the expected impact of investments in gas energy
efficiency consistent with the adopted ten -year gas energy efficiency (EE) goals, as well as
known changes in large customer attrition and additions. The cumulative gas EE program
impact by FY 2020 is assumed to be 1.7 million therms or five percent of expected gas
consumption. After incorporating these factors into the projections, a nnual gas consumption in
the City is expected to stabilize at its current level of 30.5 million therms throughout the
forecast horizon.
Figure 1 presents the historical gas consumption levels (with and without gas EE programs) from
FY 2002 through FY 2011 and projections for FY 2012 through FY 2020.
1 The all time peak gas usage for the City was in 1973 when annual usage was 45.6 million therms.
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Figure 1: Historic and Projected Gas Consumption
Palo Alto Gas Consumption
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Fiscal Year
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ForecastActual
w/o EE Programs
Center Fund Supply Gas Financial Projections
In November 2012 Council directed staff to terminate the laddered gas purchasing strategy and
transition to market price-based retail supply rates. Staff prepared a timeline to implement the
new rates by July 1, 2012 (Staff Report 2427). The new supply rate will be adjusted every month
and will be based on the monthly market price. The financial projections presented below and
summarized in Table 2 for the Gas Supply Fund Center illustrate expected costs for the Supply
Fund Center expense categories and the corresponding expected revenue streams required for
the existing supply retail rate components; namely, the commodity charge; the administrative
fee; and the PG&E local transportation charge.
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Table 2: Gas Utility Supply Fund Center - Financial Projections
($'000)
Adopted Actual Adopted Projected
2011 2011 2012 2012 2013 2014 2015 2016 2017
1 SALES IN THERMS 30,882 30,914 30,685 30,447 30,477 30,487 30,487 30,495 30,483
2 SYSTEM AVERAGE RATES
3 COMMODITY RATE 0.6937 0.7687 0.7867 0.7669 0.4501 0.4921 0.5471 0.5825 0.6090
4 TRANSPORTATION RATE 0.0212 0.0212 0.0212 0.0212 0.0742 0.0787 0.0661 0.0522 0.0543
5 ADMINISTRATION RATE 0.0227 0.0227 0.0227 0.0227 0.0039 0.0040 0.0041 0.0042 0.0043
6 PERCENTAGE RATE CHANGES
4 COMMODITY RATE -41.3%9.3%11.2%6.5%4.5%
5 TRANSPORTATION RATE 250.0%6.0%-16.0%-21.0%4.0%
6 ADMINISTRATION RATE -83.0%3.0%3.0%2.0%3.0%
7
8 FINANCIAL RESOURCES
9 MARKET BASED COMMODITY REVENUE 3,916 2,262 3,029 2,036 13,717 15,003 16,680 17,765 18,566
10 FIXED RATE COMMODITY REVENUE 20,718 21,502 21,109 21,313 0 0 0 0 0
11 RATE CHANGE (3,211)0 0 0 0 0 0 0 0
12 PRORATION IMPACT 134 0 0 0 0 0 0 0 0
13 PG&E LOCAL TRANSPORT 655 655 651 645 646 2,262 2,398 2,015 1,591
14 RATE CHANGE 0 0 0 0 1,615 136 (384)(423)64
15 PRORATION IMPACT 0 0 0 0 (67)(6)16 18 (3)
16 ADMINISTRATIVE FEE REVENUE 701 702 697 691 692 118 121 125 127
17 RATE CHANGE 0 0 0 0 (574)4 4 2 4
18 PRORATION IMPACT 0 0 0 0 24 (0)(0)(0)(0)
19 DISCOUNTS / UNCOLLECTABLES (22)(24)0 0 0 0 0 0 0
20 TOTAL ADJUSTED SALES 22,890 25,097 25,485 24,686 16,053 17,516 18,835 19,501 20,348
21 INTEREST 313 421 418 418 175 144 144 147 148
22 OTHER REVENUE AND TRANSFERS (12)12 11 11 11 11 11 11 11
23 RESERVE WITHDRAWALS:
24 SUPPLY RSR 3,101 3,650 0 2,955 1,033 7 0 0 0
25 DISTRIBUTION RSR 0 0 0 0 0 0 0 0 0
26 COMMITMENTS & REAPPROPRIATIONS 0 0 0 0 0 0 0 0 0
27 TOTAL FINANCIAL RESOURCES 26,292 29,179 25,914 28,069 17,272 17,677 18,990 19,659 20,508
28 OPERATING EXPENSES
29 TOTAL COMMODITY PURCHASES 23,816 20,732 18,660 17,360 14,814 15,022 16,588 17,724 18,550
30 PG&E TRANSPORTATION 716 706 737 1,137 1,472 1,650 1,268 844 869
31 ALTERNATIVE ENERGY PROGRAMS 260 87 460 460 200 204 208 212 216
32 GENERAL ADMIN & OVERHEAD 0 0 0 0 518 528 539 550 561
33 COMMODITY ADMIN & OVERHEAD 1,455 1,277 1,072 1,072 227 231 236 241 245
32 RENT, OTHER TRANSFERS 40 377 40 40 41 42 43 44 44
33 TOTAL OPERATING EXPENSES 26,288 23,179 20,969 20,069 17,272 17,677 18,881 19,614 20,486
34 RESERVE FUNDING:
35 SUPPLY RSR 0 0 4,945 0 0 0 108 46 22
36 DISTRIBUTION RSR 0 6,000 0 8,000 0 0 0 0 0
38 TOTAL RESERVE FUNDING 0 6,000 4,945 8,000 0 0 108 46 22
39 TOTAL REVENUE REQUIREMENT 26,288 29,179 25,914 28,069 17,272 17,677 18,990 19,659 20,508
40 RESERVE BALANCES
41 RATE STABILIZATION RESERVE 4,761 8,789 8,160 5,834 4,801 4,794 4,903 4,948 4,970
42
43 LONG TERM MINIMUM GUIDELINE 6,133 6,133 4,849 4,849 4,072 4,168 4,464 4,642 4,855
44 LONG TERM MAXIMUM GUIDELINE 12,266 12,266 9,698 9,698 8,143 8,336 8,928 9,284 9,710
45 SHORT TERM RISK ASSESSMENT 5,700 5,700 3,300 3,300 4,072 4,168
46
2011 2011 2012 2012 2013 2014 2015 2016 2017GAS - SUPPLY
Fiscal Year
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FINANCIAL PROJECTIONS (Jan 2012) City of Palo Alto
Gas Utility - Supply Fund Center
Center Fund Supply Gas Expenses
Total commodity purchase expenses (Line 29 in Table 2) represent the cost of gas procured to
serve the City. No gas has been purchased for delivery beyond October 2013. The cost of gas
through October 2013 includes previously purchased fixed-price gas. For the remaining
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deliveries, the cost of gas is assumed to be equal to the forward market prices as of November
15, 2011. Specifically, commodity purchases in FY 2013 include fixed-price commitments of
$3.8 million in FY 2013 and $0.6 million in FY 2014. This represents 24% of expected pool
customer requirements in FY 2013 and 4.6% of expected pool customer requirements in FY
2014. Based on gas market prices as of November 15, 2011, the co st of these commitments is
above their value by $1.15 million in FY 2013 and $80,000 in FY 2014. The difference between
the actual market price at time of delivery and the cost of the fixed price transactions will be
drawn out of (or credited into) the G-SRSR.
The PG&E transportation cost (Line 30 of Table 2) is based on Gas Accord V Settlement
Agreement and filing submitted to the California Public Utilities Commission (CPUC) on
November 17, 2011 (PG&E advice letter 3257-G) for calendar years 2012 through 2014 ($0.220
per million British Thermal Units (MMBtu), $0.234/MMBtu and $0.256/MMBtu, respectively)
and an escalation rate of 3% per year for the remainder of forecast horizon . Additionally, PG&E
proposed a Pipeline Safety Enhancement Plan in a separate CPUC proceeding under which an
additional gas pipeline safety rate will be applied to the local transport rates in calendar years
2012 through 2014. As this is still in the proposal stage, the projected costs could change
depending on the final outcome of the rate case . For Palo Alto, the proposed additional charges
are $0.2547/MMBtu, $0.2276/MMBtu and $0.318/MMBtu, respectively. The PG&E
transportation costs shown represent the total charges (the sum of the bas e rate and the
pipeline safety rate).
A number of changes were made in the budgeting and reporting of supply operating costs in
preparation for the market-price based supply rates.
First, reporting categories have been changed to clearly separate commodity versus non-
commodity related areas. In previous financial forecasts, supply operating expenses were
presented under three general areas: purchases, operations maintenance and other
administration, and allocated charges. In this year’s financial forecasts, operating expenses are
presented under five categories: 1) commodity purchases, 2) PG&E transportation costs, 3)
alternative energy program costs, 4) administrative and overhead costs associated with
commodity purchases; and, 5) administrative and overhead costs associated with non-
commodity related activities.
Second, in FY 2013, program costs and FTE assignments will be reallocated to align with actual
and planned work activities. In this regard, alternative energy program costs (Line 31 of Table 2)
prior to FY 2013 include supply funding for gas EE and biogas program development. Starting in
FY 2013, the supply funding of $325,000 for EE programs is transferred to the distribution fund
center where an additional $1.0 million for these programs is budgeted (under Demand Side
Management). Similarly, FTE allocations are updated to reflect existing and future staff work
plans. Over time, work load has increased in the gas and electric alternative resource programs
area such as EE, demand response and alternative resource procurement. Due to both the
change in supply procurement strategy and increased workload in alternative resource
management activities, overall FTE allocation to the gas supply fund center has been reduced by
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1.19 FTE from a total of 3.25 FTE in FY 2012 to 2.06 FTE in FY 2013. This has a direct impact on
the allocation of other overhead costs to the gas supply fund center.
A related change is in the supply administration and overhead costs area (Lines 32 and 33 of
Table 2). These costs include not only the direct supply procurement and transportation
management activities but also the allocated administration costs and overhead charges such as
cost plan based allocation of expenses including specific assigned FTE charges from the General
Fund and the IT Fund. Starting in FY 2013, these costs are broken into two areas to more
accurately reflect costs associated with providing commodity procurement services versus other
general services including gas resource planning, transportation regulatory support, and rates.
As a result, total supply administration and overhead costs are reduced by $327,000 in FY 2013.
Other costs for the gas supply fund center include rent and other transfers. Throughout the
forecast horizon, these costs as well as administration and overhead costs are assumed to
escalate at 2% per year.
Center Fund Supply Gas Revenues
Financial resources for the gas supply fund center include sales revenue and interest earnings
on investments. Supply sales revenue is broken into three components based on existing rate
schedule (commodity charge, administration fee, and PG&E local transportation). The last retail
rate adjustment for the Gas Fund was a ten percent decrease effective July 1, 2009. Since that
time, commodity costs have fallen and other cost components have increased while rates
remained unchanged. The Gas Fund as a whole had sufficient resources to cover its operating
expenses and maintain healthy reserve levels overall. However, in order to maintain reserve
levels consistent with the guidelines, a transfer of $6.0 million was made from the G-SRSR to the
G-DRSR in FY 2011 and another transfer of $8.0 million is planned for FY 2012.
Commodity revenues for FY 2011 and FY 2012 are divided into market-based and fixed rate-
based revenue streams based on revenue from G-3 (large commercial customers) (Table 2, Line
9), and all other customers (Table 2, Line 10), respectively. Starting in FY 2013, commodity
revenues from all customers will be market-based. The projections for market-based
commodity revenues are based on expected gas usage and forward market prices at PG&E
Citygate as of November 15, 2011. Figure 2 provides historical and projected wholesale gas
prices at PG&E Citygate for November 2006 through November 2014. Starting in FY 2013, PG&E
local transportation and administrative fee revenues will need to be aligned with expected costs
associated with commodity versus non-commodity related areas. In that regard, administrative
fee revenues (Table 2, Line 16), starting in FY 2013 represent the revenue requirement to cover
only the commodity related administrative and overhead costs. The PG&E local transportation
revenues (Table 2, Line 13) relate primarily to recovery of PG&E transportation costs (Table 2,
Line 30) and costs to monitor and intervene in gas regulatory proceedings at the CPUC.
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Figure 2: Natural Gas Prices – Historical and Projected
Natural Gas Wholesale Prices at PG&E Citygate
as of November 15, 2011
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* High and low prices in the 75th and 25th percentile
projected using Black Scholes model
As a result, the projected adjustments to the three components of the supply retail rate in FY
2013 include: 1) a decrease of 41% to the commodity charges; 2) an increase of 250% to the
PG&E local transportation rate; and 3) a decrease of 83% to the administrative fee. The large
percent increase in the PG&E local transportation rate is due to the alignment of $518 thousand
from Commodity Admin Overhead (Line 33 in Table 2) to General Admin Overhead (Line 32 in
Table 2) as described above. This alignment results in a similar amount of reduction in the
administrative fee. The projected net change for all supply-related charges is a decrease of 35%.
Staff will return to the Finance Committee in May with proposed changes to gas rates after
taking into account a cost of service analysis in order to allocate required revenues based on
costs imposed by each customer group.
Center Fund Distribution Gas Financial Projections
The financial projections summarized in Table 3 for the gas distribution fund center illustrate
expected costs for major expense categories and the corresponding total revenue stream
required for the existing distribution retail rate components (customer and the local distribution
charges).
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Table 3: Center Fund Distribution Utility Gas Financial Projections
($'000)
Adopted Actual Adopted Projected
2011 2011 2012 2012 2013 2014 2015 2016 2017
1 SALES IN THERMS 30,882 30,914 30,685 30,447 30,477 30,487 30,487 30,495 30,483
2 SYSTEM AVERAGE DISTRIBUTION RATE 0.7027 0.5813 0.5815 0.5843 0.7304 0.7304 0.7523 0.7824 0.8058
3 % CHANGE IN RATE 25.0%0.0%3.0%4.0%3.0%
4
5 FINANCIAL RESOURCES
6 BASE SALES REVENUE:17,743 17,970 17,843 17,790 17,807 22,266 22,267 22,941 23,849
7 RATE ADJUSTMENT 3,957 - - - 4,452 - 668 918 715
8 PRORATION IMPACT (165) - - - (185) - (28) (38) (30)
9 DISCOUNTS/UNCOLLECTABLES (428) (535) (250) (250) (250) (250) (250) (250) (250)
10 TOTAL ADJUSTED SALES 21,107 17,435 17,593 17,540 21,824 22,016 22,657 23,570 24,285
11 INTEREST 534 400 530 530 537 468 358 353 357
12 OTHER REVENUE AND TRANSFERS 100 100 85 85 85 85 85 85 85
13 SERVICE CONNECTION FEES 700 700 710 710 720 730 752 790 812
14 RESERVE WITHDRAWALS:
15 DISTRIBUTION RSR 2,177 0 9,626 0 1,942 1,219 344 0 203
16 SUPPLY RSR 0 6,000 0 8,000 0 0 0 0 0
17 COMMITMENTS & REAPPROPRIATIONS 0 0 0 1,848 0 0 0 0 0
18 TOTAL FINANCIAL RESOURCES 24,617 24,634 28,544 28,713 25,107 24,519 24,196 24,797 25,742
19 OPERATING EXPENSES
20 CUSTOMER DESIGN & CONNECTION (CIP)700 700 710 710 720 730 752 790 812
21 SYSTEM IMPROVEMENT (CIP)7,625 7,625 7,111 7,311 6,986 4,647 4,786 4,827 5,301
22 ALLOCATED ADMIN & OVERHEAD 2,985 2,569 2,990 2,990 3,050 3,111 3,173 3,236 3,301
23 ENGINEERING SUPPORT & ADMIN 760 669 841 841 858 875 893 910 929
24 GAS OPERATIONS 3,407 2,923 7,314 7,314 3,649 4,762 3,817 3,894 3,971
25 CUSTOMER SERVICE & ADMIN 644 682 709 709 723 737 752 767 783
26 METER READING 255 232 269 269 275 280 286 292 297
27 BILLING AND COLLECTIONS 349 316 358 358 366 373 380 388 396
28 DEMAND SIDE MANAGEMENT 852 562 942 942 1,334 1,453 1,577 1,630 1,682
29 TOTAL MAJOR ACTIVITIES 17,577 16,279 21,245 21,446 17,960 16,969 16,416 16,734 17,472
30 DEBT SERVICE 947 947 948 803 803 802 802 802 802
31 TRANSFERS:
32 GENERAL FUND TRANSFER 5,304 5,304 6,006 6,006 5,995 6,396 6,623 6,861 7,104
33 RENT 175 175 175 175 178 182 186 189 193
34 OTHER TRANSFER 614 738 170 170 170 170 170 170 170
35 SUB-TOTAL TRANSFER 6,094 6,218 6,351 6,351 6,343 6,748 6,978 7,220 7,467
36 TOTAL OPERATING EXPENSES 24,617 23,443 28,544 28,600 25,107 24,519 24,196 24,756 25,742
37 RESERVE FUNDING:
38 DISTRIBUTION RSR 0 1,191 0 114 0 0 0 41 0
39 SUPPLY RSR 0 0 0 0 0 0 0 0 0
40 TOTAL RESERVE FUNDING 0 1,191 0 114 0 0 0 41 0
41 TOTAL REVENUE REQUIREMENT 24,617 24,634 28,544 28,713 25,107 24,519 24,196 24,797 25,742
42 RESERVES BALANCES
43 PLANT REPLACEMENT 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
44 RATE STABILIZATION 3,874 7,399 417 7,513 5,571 4,352 4,007 4,048 3,845
45 DEBT SERVICE RESERVES 952 952 952 952 952 952 952 952 952
46 TOTAL RESERVES BALANCES 5,826 9,351 2,369 9,465 7,523 6,304 5,959 6,001 5,797
47 COMMITMENTS & REAPPROPRIATIONS 16,656
48
49 RATE STABILIZATION RESERVE
50 LONG TERM MINIMUM GUIDELINE 3,230 3,230 2,676 2,676 3,311 3,340 3,436 3,573 3,680
51 LONG TERM MAXIMUM GUIDELINE 6,460 6,460 5,353 5,353 6,622 6,680 6,872 7,146 7,360
52 SHORT TERM RISK ASSESSMENT 4,070 4,070 4,300 4,300 4,015 3,810
53
2011 2012 2013 2014 2015 2016 2017
S
O
U
R
C
E
S
GAS - DISTRIBUTION
City of Palo Alto
Gas Utility - Distribution Fund Center
Fiscal Year
FINANCIAL PROJECTIONS (Jan 2012)
R
E
S
E
R
V
E
S
U
S
E
S
Center Fund Distribution Gas Expenses
The two main drivers of expenses in the distribution fund center are the changes in CIP plans
and the funding requirement for the continuation of the cross-bore program initiated in FY
2012.
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Table 4 summarizes the five-year plan for CIP expenditures. Annual CIP expenditures are
planned to decrease to around the $5.5 million range starting in FY 2014 as a result of the
completion of the 21-year effort to replace acrylonitrile butadiene styrene (ABS) piping
materials. This is represented by the 50% reduction in costs budgeted for the Gas Main
Replacement (GMR) Project 21 (GS-11000) in FY 2013 and subsequent GMR projects in future
years.
Table 4: Capital Improvement Program Plan (FY 2013 – FY 2017) ($)
ID Description FY 2013 FY 2014 FY 2015 FY 2016 FY 2017
GS-03007 Directional Boring E 64,000 68,000 70,040
GS-02013 Directional Boring M 45,000 250,000 46,350 257,500
GS-80019 Gas Meters and Regul 315,000 325,000 335,000 351,750 362,303
GS-80017 Gas System Extension 720,000 730,000 752,000 789,600 812,000
GS-11002 Gas System Improv.206,000 212,200 218,600 229,530 236,416
GS-13002 General Shop Equipm. 52,335
GS-11000 GMR - Project 21 6,150,000
GS-12001 GMR - Project 22 3,200,000
GS-13001 GMR - Project 23 482,000 3,300,000
GS-14003 GMR-Project 24 492,000 3,465,000
GS-15000 GMR - Project 25 542,000 3,568,950
GS-16000 GMR- Project 26 570,000
GS-03008 Polyethylene Fusion 34,000 36,100 37,183
GS-15001 Security at Stations 100,000
GS-03009 Sys Ext Ops 172,000 178,000 183,500 192,675 198,500
Total 7,706,000 5,377,200 5,537,535 5,616,905 6,112,892
The gas operations budget (Line 24 in Table 3) for FY 2012 included a one-time cost of $3.8
million for Crossbore Inspection Program related expenditures. This work will continue into FY
2013 so any unused budget from FY 2012 will be carried over to continue the work in FY 2013.
In 2013, an additional $500,000 of operational funding is needed to complete the Crossbore
Inspection Program. The increase in cost is due to the conditions being encountered in the field.
The changed conditions are as follows: multiple customer owned laterals are needing
inspection on customers properties, a larger number of customer laterals than anticipated are
requiring some kind of repair to allow the camera to pass through the lateral, and the
contractor is having to do more manual push camera work due to small mains and lined pipes.
The General Fund transfer (Line 32 in Table 3) is expected to continue at the current level of
$6.0 million in FY 2013 and gradually increase over the forecast horizon based primarily on the
expected increases in net book value of gas utility assets resulting from planned CIP
expenditures less anticipated depreciation.2
Funding for Demand Side Programs (Line 28 in Table 3) is increased by about $100,000 per year
consistent with the ten-year gas EE goals approved by Council in April 2011.
2 General Fund Transfers are calculated using the Council-approved Utility Enterprise Methodology (CMR:260:09).
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Staff projects a long-term net cost increase of 2% per year in other operating expenditures (i.e.
operations, maintenance and administration costs, allocated cost plan and utilities
administration charges, rent, and other transfers). Final operating budget proposals will be
presented to the Finance Committee in May 2012.
Center Fund Distribution Gas Revenues
Retail sales constitute the largest source of revenue for the gas distribution fund center. Other
major revenue sources include service connection and capacity fees, which are expected to
increase at a modest level of 2.9% per year, and interest and gains on investments, which are
projected to diminish somewhat in future years based on projected cash reserves and an
assumed 3% per year return on investment throughout the forecast horizon.
As explained under the Gas Supply Fund Center Revenues section, since the last gas rate
adjustment was made on July 1, 2009, revenues in the Gas Fund have covered expenses overall,
but supply revenues were more than needed and distribution revenues were insufficient.
Therefore, a transfer of $6.0 million was made from the G-SRSR to the G-DRSR in FY 2011 and
another transfer of $8.0 million is planned for FY 2012. As market -based gas supply rates are
implemented, a one-time realignment of distribution costs must be made with the effect that
the gas distribution rate must increase by 25% for revenues t o cover costs3 in FY 2013 followed
by increases of 3%, 4%, and 3% in FY 2015, FY 2016 and FY 2017, respectively . The expected
25% increase in gas distribution rate is an adjustment representing cumulative cost increases in
the gas distribution fund since the last rate adjustment in July 2009. Since that time, the
following changes have taken place:
$2.9 million increase in General Fund Transfers from $3.1 million in FY 2009 to 6.0
million in FY 2013,
$1.3 million increase in Energy Efficiency Programs from $54,000 in FY 2009 to $1.3
million in FY 2013,
$838,000 increase in Utility Operations from $5.033 million in FY 2009 to $ 5.870 million
in FY 2013,
$874,000 decrease in Capital Improvement Program expenses from $8.6 million in FY
2009 to $ 7.7 million in FY 2013,
$145,000 decrease in Debt Service expenses from $949,000 in FY 2009 to $843,000 in FY
2013,
$373,000 decrease in Allocated Charges and Other expenses from $3.8 million in FY
2009 to $ 3.4 million in FY 2013.
Figure 3 and Table 4 present the changes in Gas Distribution costs since FY 2009 and projections
for the next five years.
3 While gas distribution rates are projected to increase by 25% in FY 2013, gas supply rates are projected to
decrease by 35%, resulting in a system average rate reduction of 10% for FY 2013.
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Figure 3: Distribution Fund Revenue and Costs (FY 2009 – FY 2017) ($M)
$0
$5
$10
$15
$20
$25
$30
$35
2009 2010 2011 2012 2013 2014 2015 2016 2017
Gas Distribution Revenue and Cost
($million)
CIP
Utility Operations
EE Programs
Allocated
Charges & Other
General Fund
Transfer
Debt Service
Distribution
Revenue after
10% Rate
Decrease
Distribution
Revenue
with Projected
Rate Adjustments
Actual Projected
Table 5: Distribution Fund Costs (FY 2009 – FY 2017) ($1000)
Cost
Description FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017
Capital
Improvement
Programs
8,580 3,364 8,325 8,021 7,706 5,377 5,538 5,617 6,113
Utility
Operations 5,033 5,342 4,822 9,492 5,870 7,028 6,128 6,251 6,376
Energy
Efficiency
Programs
54
428
562
942
1,334
1,453
1,577
1,630
1,682
Allocated
Charge and
Other
3,771 1,990 3,483 3,335 3,398 3,463 3,529 3,596 3,664
General Fund
Transfers 3,135 5,300 5,304 6,006 5,995 6,396 6,623 6,861 7,104
Debt Service
949
1,009
947
803
803
802
802
802
802
Total 21,521 17,433 23,443 28,600 25,107 24,519 24,196 24,756 25,742
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Reserves and Risk Assessment for the Gas Utility
The Gas Fund maintains separate rate stabilization reserves for its gas supply and gas
distribution fund centers. The current reserve guidelines for the G -DRSR are 30% and 15% of
sales revenues for maximum and minimum reserve levels, respectively. The guidelin es for the
G-SRSR are 50% and 25% of supply purchase costs for maximum and minimum reserve levels,
respectively. Additionally, as required by the reserve guidelines, staff performs an annual
assessment of short-term risks facing the Fund for both the supply and the distribution fund
centers.
Gas Supply Rate Stabilization Reserve (G-SRSR)
The Council direction to implement market-price based gas supply rates creates an opportunity
to review existing reserve guidelines for the utility and propose changes as necessary. In the
past, the short-term risk assessment for the G-SRSR focused on market price volatility, load
uncertainty and supplier default. With the change in commodity rate setting based on market
price, this type of risk will now be passed on to customers. There is, however, still a need to
maintain some level of reserves for both the supply and the distribution fund centers for other
reasons in order to continue to ensure prudent financial management of the utility. These
reasons, in general, include debt service obligation, unplanned need for a major capital
expenditure and operational cash management. Since the first two factors do not readily apply
to the supply fund center, the short -term analysis conducted this year for the supply fund
center includes only a review of operational cash management needs.
Table 6 below shows the typical monthly cash flow for commodity purchases during a fiscal
year. Column D shows the cost of purchased gas and Column E shows cash flow out for
payment of the gas, which is due in the following month. Due to the time elapsed from
customer usage of gas to meter reading, bill processing and, finally receipt of payment from
customers, there can be up to a two-month delay between when CPAU pays for the gas
delivered to the City and CPAU collects payments from customers for the gas delivered to their
premises. This cash flow issue is amplified by the seasonal nature of gas consumption. For the
forecasted gas usage, cash reserves of around 15% of annual gas commo dity budget (Column I
of Table ) are required to cover the cash flow needs.
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Table 6
A B C D E F G H I
7 1,459,985 4.008 585,162 715,105 1,135,156 420,051 420,051 3.1%
8 1,512,981 4.035 610,488 585,162 866,722 281,560 701,611 5.1%
9 1,585,020 4.037 639,873 610,488 715,105 104,617 806,228 5.9%
10 2,178,588 4.074 887,557 639,873 585,162 (54,711)751,517 5.5%
11 2,917,416 4.153 1,211,457 887,557 610,488 (277,069)474,448 3.5%
12 4,443,878 4.422 1,964,861 1,211,457 639,873 (571,584)(97,136)-0.7%
1 4,630,919 4.546 2,104,984 1,964,861 887,557 (1,077,304)(1,174,439)-8.6%
2 3,550,296 4.535 1,609,882 2,104,984 1,211,457 (893,527)(2,067,967)-15.1%
3 3,062,186 4.490 1,374,768 1,609,882 1,964,861 354,979 (1,712,988)-12.5%
4 2,576,094 4.407 1,135,156 1,374,768 2,104,984 730,216 (982,772)-7.2%
5 1,960,245 4.422 866,722 1,135,156 1,609,882 474,726 (508,046)-3.7%
6 1,607,157 4.450 715,105 866,722 1,374,768 508,046 0 0.0%
Total 31,484,765 13,706,014 13,706,014 13,706,014
Expected Cash Flow for Gas Commodity Purchases and Collection
Scenario 1 - Base Case -
Monthly
Difference
($)
Cumulative
Difference
($)
Cash
shortfall
(%) over
Total
Budget
Operating
Month
Monthly Gas
Purchases
($)
Payment for
Commodity
($)
Market
Price @
PG&E
Citygate
($/MMBtu)
Monthly Gas
Purchases
(therm)
Commodity
Revenue
from
Customers
($)
Cash flow needs are affected both by gas usage patterns and by the cost of gas. In a scenario
with winter gas consumption 20% higher than normal, the cash reserve requirement is about
21% of the annual gas commodity budget. In another cold winter scenario in which gas prices
are 25% higher than expected the cash reserve requirement is about 30% of the annual gas
commodity budget.
In summary, under the new gas supply rate structure, the gas supply rate will change each
month to reflect the market price. Over the course of a year, revenue will match cost since
market price risk is eliminated. In addition, with no fixed-price gas purchases, there is no credit
risk, the risk from a counterparty defaulting on a pre-arranged deal. However, reserves are
required to cover the cash flow needs associated with the 2 -month lag between when gas is
purchased and when gas sales revenue is collected. In this analysis, a conservative estimate of
25% is used as the short-term risk assessment value for determining reserve adequacy for the
G-SRSR for FY 2013 and FY 2014. Along with the proposed changes to gas rates, staff will return
to the Finance Committee in May 2012 with a review of, and potential recommended changes
to, the gas reserve guidelines.
Gas Distribution Rate Stabilization Reserve (G-DRSR)
For the G-DRSR, the annual short-term reserve adequacy analysis involves an evaluation of the
distribution business risk factors, which include loss of load, unplanned variance in CIP
expenditures, and debt coverage ratio. Since most of the expenses on the distribution side are
fixed and most of the revenue is recovered through volumetric rates, loss of load results in a
shortfall in cost recovery. Table 7 presents short-term risk assessment for the G-DRSR. The risk
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due to loss of load is calculated using the maximum annual budget -to-actual variance in
distribution sales revenue during the past ten years, which was 15% in FY 2002. A 10% variance
for unplanned CIP is included in the risk exposure. The resulting reserve requirement for the G -
DRSR is $4.0 million for FY 2013 and $3.8 million, for FY 2014.
Table 7: Gas Distribution Rate Stabilization Reserves
Annual Reserve Adequacy Analysis ($1000)
FY 2013 FY 2014
Distribution Sales Revenue $ 21,074 $ 22,266
Loss of Load @15% $ 3,317 $ 3,345
System Improvement CIP Budget $ 6,986 $ 4,647
Contingency @10% $ 699 $ 465
Total Reserve Requirement $ 4,015 $ 3,810
Reserve Requirement as % of
Distribution Sales Revenue 18.2% 17.1%
Table 8 presents the results of the short-term risk assessment along with the existing minimum
and maximum reserve guideline levels and estimated FY year-end balances for the G-SRSR and
the G-DRSR.
Table 8
Gas Rate Stabilization Reserve Guideline Levels and Short -Term Risk Assessment ($M)
The Gas Fund ended FY 2011 with adequate funds in its reserves and the projections for FY
2012 indicate that this will continue to be the case. Transfers of $6.0 in FY 2011 and $8.0
million in FY 2012 from the G-SRSR to the G-DRSR align fund level balances with expected costs.
FY 2011
Actual
FY 2012
Projected
FY 2013
Projected
FY 2014
Projected
Gas Supply Rate Stabilization Reserve
Balance prior to Transfer to G-DRSR 14.9 13.8 4.8 4.8
Transfer to G-DRSR 6.0 8.0 0 0
End of Year Balance 8.9 5.8 4.8 4.8
Risk Assessment 5.7 3.3 4.1 4.2
Minimum Guideline Level 6.1 4.9 4.1 4.2
Maximum Guideline Level 12.3 9.7 8.1 8.3
Gas Distribution Rate Stabilization Reserve
Balance prior to Transfer from G-SRSR 1.4 (0.5) 5.6 4.3
Transfer from G-SRSR 6.0 8.0 0 0
End of Year Balance 7.4 7.5 5.6 4.3
Risk Assessment 4.3 4.3 4.0 3.8
Minimum Guideline Level 2.7 2.7 3.3 3.3
Maximum Guideline Level 5.4 5.4 6.6 6.7
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After these alignments and with the planned changes to rates in FY 2013, the Gas Fund is
projected to end the next two fiscal years with both the G-SRSR to the G-DRSR within the
minimum and maximum reserve guideline levels.
Rate Comparison with Neighboring Cities
The City currently has a cost disadvantage with respect to PG&E as shown in Table 9 below.
Comparisons are based on the median residential customer usage of 54 therms per month
during the winter months (November through April) and 18 therms per month during the
summer months (May through October). Monthly bills shown are based on rates effective
January 1, 2012.
Table 9: Gas Utility Residential Benchmark Comparison
Current FY 2012 (as of January 1, 2012)
Palo
Alto
Mountain
View
Redwood
City
Menlo
Park
Santa
Clara
Average
Benchmark
City
Monthly Bill ($) 55.19 37.80 37.80 37.80 37.80 37.80
Difference from CPAU -31.5% -31.5% -31.5% -31.5% -31.5%
The City’s current relative position with respect to neighboring cities may change in the future
depending on future financial decisions by PG&E.
Commission Review and Recommendations
The UAC reviewed the Gas Fund financial forecast at its March 7, 2012 meeting.
Commissioners asked why the gas distribution rates need to go up by 25%. Staff explained that
distribution rates have not been changed since FY 2009 and the rates have resulted in an under-
collection of revenue to support the distribution fund center. Over that time, costs related to
the distribution fund center have increased. The specific costs that are included in the
distribution fund center were discussed. The Commission suggested that staff should explain
more fully the need for a 25% revenue increase in the distribution fund center so that the
public and Council can understand the need for such a significant increase in gas distribution
rates. Staff added more detail in this report regarding the change in distribution costs since FY
2009 in response to the UAC’s input. The excerpted notes from the UAC’s March 7, 2012
meeting are attached.
Attachments:
-: Attachment A: Excerpted Minutes of the March 7 UAC Meeting (PDF)
Prepared By: Ipek Connolly, Sr. Resource Planner
Department Head: Valerie Fong, Director
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City Manager Approval: ____________________________________
James Keene, City Manager
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Excerpted Minutes of the March 7, 2012 UAC Meeting
NEW BUSINESS
ITEM 2: DISCUSSION: Gas Fund Financial Projections (FY 2013 – FY 2017)
Senior Resource Planner Ipek Connolly provided a presentation summarizing the report. She
stated that the Council direction to change the laddered purchasing strategy and implement
monthly‐varying, market‐based gas commodity rates necessitates a structural change to gas
rates for FY 2013. The gas supply and gas distribution rate components will need to be adjusted
as they have not been adjusted for several years and, meanwhile distribution system costs have
increased while supply costs have decreased leading to a situation over the past two years
when significant transfers have been made from the supply reserves to the distribution
reserves. The changes to rate components for FY 2013 include a 25% increase in gas
distribution rates while the gas commodity rates are not known since they will be based on
market rates. Connolly added that, if gas commodity rates are equal to the forward prices for
gas when the budget estimates were prepared, then the gas commodity prices will fall about
41%. However, since that time, gas prices have fallen further and the forward prices indicate
that commodity prices could fall 53%. Overall, the bundled gas rates (supply plus distribution)
are projected to fall by 10% based on the budget projections for gas supply. The UAC is
scheduled to review the gas rates in May, when results from a cost of service study will be
provided. The cost of service study findings may result in cost shifts between customer classes.
Commissioner Eglash asked why distribution rates need to go up by 25%. Connolly said that
distribution rates have not been changed in many years and the rates have resulted in an
under‐collection of revenue to support the distribution fund center. Over that time, costs
related to the distribution fund center have increased. Commissioner Eglash asked if his
understanding that the costs increase is not from FY 2012 to FY 2013, but over a longer period
of time. Connolly confirmed this understanding.
Commissioner Eglash asked Connolly to describe the costs that make up the distribution fund
center. Connolly replied that these costs include all costs not related to the commodity
purchases, staff costs to manage the gas supply portfolio, and gas transportation costs paid to
PG&E. Distribution fund center costs include the transfer to the General Fund, allocated
charges for services provided by General Fund departments to Utilities (HR, payroll, attorney,
etc.), Capital Improvement Projects (CIP), and debt service.
Commissioner Waldfogel stated that the 25% increase is not found on the tables provided in
the report as they don’t go back further than FY 2011. Commissioner Eglash said that, if the
increases are, for example, in CIP costs, a 25% increase is not evident in the information
provided. Connolly stated that Table 3 in the report does show that the distribution fund
center revenues have not covered costs and that a 25% rate increase for distribution will bring
revenues in line with costs. Assistant Director Jane Ratchye added that in FY 2011 and FY 2012,
transfers of $6 million and $8 million, respectively were made from the supply rate stabilization
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reserve to the distribution rate stabilization reserve to balance revenue and cost in the
distribution fund center. Commissioner Waldfogel stated that Table 3 is confusing since line 41,
the total revenue requirement doesn’t show a 25% increase, but a decrease from $28.7 million
in FY 2012 to $25.1 million in FY 2013. Connolly said that line 41 does show the total revenue
requirement and it is declining from FY 2012, but that the financial resources for FY 2012
includes sales revenue of only $17.5 million and other revenue includes the $8 million transfer
from supply. Since the transfer from supply reserves will not occur in FY 2013, the sales
revenue must increase to cover costs. Commissioner Waldfogel recommended showing an
operating profit or loss in the table.
Commissioner Eglash returned to the question of why distribution rates need to increase by
25%. Connolly stated that the costs did not increase by 25% in one year, but increased over
time. One reason is that the methodology for determining the General Fund Transfer changed
in FY 2009 and the transfer from the Gas Fund increased substantially. He asked why this cost
increase is not shown in the tables provided in the report. Ratchye said that the tables only
show costs from FY 2011 and don’t show the costs from FY 2009, when the last change was
made to distribution rates. Commissioner Eglash recommended that staff provide a very clear
explanation of how much costs have increased if it is proposing such a significant increase in gas
distribution rates.
Council Member Shepherd asked if we were separating that the distribution costs related to
bringing the gas to a house from the cost of the commodity itself. Ratchye confirmed that this
understanding was correct. She said that the distribution costs include the costs of employee
salary and benefits, which have been increasing, as well as CIP and the General Fund transfer.
These costs do not vary with amount of gas used.
Commissioner Waldfogel commented that when the rates come back to the UAC, a part of the
discussion needs to be what part of the fixed costs should be recovered from fixed charges
versus volumetric charges.
Commissioner Keller asked about the "other transfers" shown on line 34 in Table 3 of the
report, noting the large increase in FY 2011 compared to the amounts for the five‐year financial
forecast. Connolly indicated that these are for transfers between funds that are shared
between funds. These include costs from the IT fund, which are related to the SAP financial and
billing system.
Commissioner Waldfogel stated that we are half way through the program and asked if staff
still believes that the cross‐bore program is an essential safety program, or should it be
stopped. Ratchye responded that the program is taking slightly longer than originally
anticipated, but that it is determined to be beneficial and some cross‐bores have been
discovered and fixed.
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