HomeMy WebLinkAbout2004-09-13 City Council (6)City of Palo Alto
C ty Manager’s-R or:t
4
TO:HONORABLE CITY COUNCIL
FROM:CITY MANAGER DEPARTMENT: UTILITIES
DATE:SEPTEMBER 13, 2004 CMR:368:04
SUBJECT:FINANCE COMMITTEE RECOMMENDATION TO ACCEPT THE
GAS UTILITY LONG-TERM PLAN RECOMMENDATIONS
COMMITTEE REVIEW AND RECOMMENDATIONS
The Finance Committee voted unanimously on August 3, 2004 to accept staff’s
recommendation to approve the six Gas Long-Term Plan (GULP) recommendations and
requested that staff provide a biannual update on the status of the recommendations.
ATTACHMENT
CMR:335:04 - Gas Utility Long Term Plan Recommendations
PREPARED BY:
DEPARTMENT APPROVAL:
Karla Dailey
Resource Planner
JOHN/gjL]~ICI_It" [/%
D!~re’~t¢ of Utilities
CITY MANAGER APPROVAL:
City Manager
CMR:368:04 Page 1 of 1
TO:HONORABLE CITY COUNCIL
ATTENTION: FINANCE COMMITTEE
FROM:CITY MANAGER DEPARTMENT: UTILITIES
DATE:
SUBJECT:
AUGUST 3, 2004 CMR:335:04
GAS UTILITY LONG-TERM PLAN RECOMMENDATIONS
RECOMMENDATION
Staff requests that Council
recommendations.
approve the six Gas Long-Term Plan (GULP)
BACKGROUND
The City of Palo Alto meets a total annual gas demand of approximately 3,250,000
MMBtu comprised of approxilnately 20,000 residential customers, 2,300 commercial
customers, and 10 large customers. The load has declined slightly over the’ past few
years due to the economic downturn.
The pie chart below, FigUre 1, shows the make-up of Palo Alto’s load by major customer
class. Palo Alto also offers direct access to the’10 largest customers. This rate has been
in effect since 1999 (CMR:148:99). However, to-date no customers have elected to
receive gas commodity from any alternative supplier. Currently all 10 large customers
are on either the monthly variable market rate or a 12- or 24-month fixed-term rate.
CMR:335:04 Page 1 of 5
Palo Alto Gas. Utility Customer Mix
Large commercial customers with
market-based rates (G3)
10 customers
Residential customers (G1)
20,000 customers
Large Commercial customers with fixed
term rates (Gll)
2 customers
Small commercial
customers and municipal
customers (G2 & G6)
2300 customers
Figure I
Three main factors drove the need for GULP: (1) a need to review and update the current.
comlnodity purchasing strategy with public input, (2) the possible need to commit to
PG&E assets as part of a PG&E bankruptcy negotiation (not applicable at this time), and
(3) the need to be prepared for possible new regulations imposing minimum asset
holdings for core customers. In addition, development of a GULP addresses
recommendation #20 in the Assessment of Utility Risk Management Procedures by the
City Auditor, "CPAU: should continue to regularly and actively (a) review the
performance of the energy procurement strategy, (b) quantify the risk and cost
consequences of alternatives, and (c) communicate the risks and costs of recommended
revisions to the City Council."
DISCUSSION
The GULP analysis evaluated potential City of Palo Alto acquisition and participation in
five main areas: gas storage capacity, gas pipeline capacity, gas wellhead rese~wes,
prepayment for gas, and gas efficiency programs. In parallel, the City gas commodity
procurement strategy was revisited and revised (CMR: 167:04). Currently the City holds
no long-term gas-related assets.
Storage was analyzed for two potential purposes: (1) swing gas for load-supply balancing
and (2) taking advantage of season price differences. The results of the analysis led to
CMR:335:04 Page 2 of 5
staff’s recommendation not to purchase storage assets at this time. The current
arrangement the City has with suppliers whereby: gas is sold to or bought from the City at
a pre-arranged daily market index in order to balance load and supplies is more cost
effective than storage. Storage cost is much greater than the expected benefit of seasonal
price differences.
Pipeline capacity acquisition is not recommended given the City’s current gas commodity
portfolio. Staff’s analysis showed that the tariff rates are much above the expected future
value of all relevant pipeline routes and that the uncertainty of pipeline capacity value is
such that the necessary long-term nature of such acquisitions does not result in an
expected positive value.
Staff reconamends pursuing joining a consortium to investigate potential natural gas
reserve acquisition and, if successful, proceeding with the next step, namely hiring an
investment bank and consultants to scout for gas reserve properties. This phase will
utilize the proposed FY 04/05 budget for this project of $65,000.
The City could take advantage of its low cost of capital and prepay for natural gas in
exchange for a discounted price under new regulations implemented by the IRS as of
October 2003. Staff investigated the activities of other municipalities and heard that it is
possible to structure a prepay deal with little credit risk to the City. While this appears to
be a low-risk alternative for Palo Alto, the estimated benefit of $50,000 per year is too
small to justify the staff time and cost of formal, expert advice required to structure a deal.
and then explain it to the City’s decision makers. As a result, staff recommends not
participating in prepay arrangements at this time. Staff does recommend the pursuit of
low-cost, high-reward supply-related opportunities as they arise.
Staff recommends developing comprehensive demand-side management goals and an
implementation plan by Fall 2004 in time for incorporation into FY 05-06 and future
ratemaking and budget decisions. This will include evaluation of opportunities to increase
effici.ency of commerci:al, industrial and institutional gas customers by deploying
advanced metering technologies and on-line usage analysis.
In the interim, staff recommends continued implementation of current and planned FY
04-05 demand-side management programs (DSM). This includes evaluating
opportunities to leverage portions of the annual Gas DSM budget of $225,000 to reduce
Utilities costs. An example would be targeting supplemental furnace rebates to Rate
Assistance Program (RAP) participants having older pilot light units in order to reduce
the number of Field Service seasonal pilot turn-on and turn-off workload. This could
result in savings to both the participating customer (operating costs) and the Utilities
Department (labor and financial subsidies).
Details of all the analyses can be found in the attachments to the June 2004 Utilities
Advisory Commission (UAC) report.
CMR:335:04 Page 3 of 5
COMMISSION REVIEW AND RECOMMENDATIONS ......
At its February 4, 2004 meeting, the UAC was given a lengthy presentation of the GULP
analysis and preliminary recommendations. The UAC had no substantive comments at
that time. On June 2, 2004 the UAC unanimously voted to recommend Council approval
¯ of the six GULP recommendations. There were no comments by the public.
POLICY IMPLICATIONS .
The GULP recommendations support the Utilities Strategic Implementation Plan
(CMR:223:01), in particular, Strategy 2 - Preserve a supply cost advantage compared to
the market price and Strategy 6 - maintain stable General Fund transfers, and maintain
financial strength.
In summary, the six recommendations are:
1. Do not contract for natural gas storage capacity at this time.
2. Do not acquire additional natural gas pipeline capacity at this time.
3. Approve staffundertaldng initial steps related to gas reserve acquisition including:
a) Identifying and evaluating potential consortiums including joint action
opportunities;
b) Entering into consortium agreement to scout properties;
c) Through the consortium, employing an investment bank and consultants to
scout properties and spend up to $65,000 in FY 04-05 related to this effort;
and
d) Through the consortium, identifying attractive, feasible opportunities.
4. Do not participate in a gas prepay deal at this time.
5. Pursue any low-cost, high-value prospects to acquire supply-related resources that
may arise from time to time.
6. Develop comprehensive demand-side management goals and implementation plan
by Fall 2004 in time for incorporation into FY05-06 and future ratemaking and
budget decisions. In the interina, continue implementation of current and planned
FY 04-05 demand-side management programs.
ATTACHMENTS
A:June 2, 2004 UAC Report
B:June 2, 2004 Presentation
B:Minutes from UAC Meeting June 2, 2004
PREPARED BY:
KARLA DAILEY~
Resource Planner
CMR:335:04 Page 4 of 5
DEPARTMENT HEAD:
CITY MANAGER APPROVAL:
~ON
Assistant City Manager
CMR:335:04 Page 5 of 5
MEMORANDUM 3
TO:
FROM:
SUBJECT:
Utilities Advisory Commission
Utilities Department
GULP Recolnmendations
AGENDA DATE: May 5, 2004
REQUEST:
Staff requests that the Utilities Advisory Commission (UAC) recornmend that the City
Council approve the six Gas Long-Term Plan (GULP) recommendations.
RECOMMENDATIONS
"l. Do not contract for natural gas storage capacity at this time.
2. Do not acquire additional natural gas pipeline capacity at this time.
3. Approve staff undertaking initial steps related to gas reserve acquisition including:
a) Identifying and evaluating potential consortiums including joint action
opportunities;
b) Entering into consortium agreement to scout properties;
¯c) Through the consortium, employing an investment bank and consultants
to scout properties and spend up to $65,000 in FY 04-05 related to this
effort; and
d) Through. the consortium, identifying attractive, feasible opportunities.
4. Do not participate in a gas prepay deal at this time.
5. Pursue any low-cost, high-value prospects to acquire supply-related resources that
may arise from time to time.
6. Develop comprehensive demand-side management goals and irnplementation plan
by Fall 2004 in time for incorporation into FY05-06 and future ratemaking and
budget decisions. In the interim, continue implementation of current and planned
FY 04-05 demand-side management programs.
UAC 050504 Item 3 Page 1 Of 19
EXECUTIVE SUMMARY
At it February 11, 2004 meeting, preliminary GULP recommendations were presented to
the UAC. The following shows those preliminary recommendations edited to reflect the
final recommendations.
1. Do not contract for.natural gas storage capacity at this time’.
2. Do not acquire additional natural gas pipeline capacity at this time.
3.Approve staff undertaking initial steps related to gas reserve acquisition
including:
a) Identifying and evaluating potential consortiums including joint
action opportunities;
b) Entering iuto consortium agreement to scout properties;
C) Through the consortium, employing an investmeut bank and
consultants to scout properties and spend ~p to $65,000 in FY
related to this effort; aud
d) Through the consortium, identifying attractive, feasible
opportunities.
4. Do not participate in a gas prepay deal at this time.
5. Pursue any low-cost, high-value prospects to acquire supply-related resources
that may arise from time to time.
6.Develop compreheusive demand-side management goals and implementation
plan by Fall 2004 in time for incorporation into FY05-06 and future
ratemaking and budget decisions. In the interim, continue implementation of
current aud planned FY 04,05 demand-side management programs.
The storage and pipeline recommendations have not been changed at all. The reserves
and demand-side management recommendations have been reworded. The prepay
recommendation has been changed from "investigate further" to "do not participate", and
an addition recommendation has been added to include supply-related resource
acquisitions that may arise in the future.
Three main factors drove the need for GULP: (1) a need to review and update the.current
commodity purchasing strategy with public input, (2) the possible need to commit to
PG&E assets as part of a PG&E bankruptcy negotiation (not applicable at this time), and
UAC 050504 Item 3 Page 2 Of 19
(3) the need .to be pr.epared for possible new regulations imposing minimum asset
holdings for core customers. In addition, development of a GULP addresses
recommendation #20 in the Assessment of Utility Risk Management Procedures by the
City Auditor which reads, "CPAU should continue to regularly and actively (a) review
the performance of the. energy procurement strategy, (b) quantify the risk and cost
consequences of alternatives, and (c) communicate the risks and costs of recommended
revisions to the City Council."
To that end, the GULP analysis evaluated potential City of Palo Alto acquisition and
participation in 5 main areas: (1) gas storage capacity, (2) gas pipeline.capacity, (3) gas
wellhead reserves, (4) prepayment for gas, and (5) gas efficiency programs.
Storage was analyzed for two potential purposes: (1) swing gas for load-supply balancing
and (2) taking advantage of season price differences. Based on the storage analysis in
Attachment C, staff does not recommend purchasing storage assets at this time. The
cunent an’angement the City has with suppliers whereby gas is sold to or bought from the
City at a pre-an’anged daily market index in order to balance .load and supplies is more .
cost effective than storage. Storage cost is much greater than the expected benefit of
seasonal price differences.
Pipeline capacity acquisition is not recommended given the City’s current gas commodity
portfolio. The analysis in Attachment D shows that the tariff rates are much above the
expected future value of all relevant pipeline routes and that the uncertainty of pipeline
capacity value is such that the necessary long-term nature of such acquisitions does not
result in an expected positive value.
Staff reconamends joining a consortium to pursue potential natural gas reserve acquisition
and, if successful, proceeding with the next step, namely hiring an investment bank and
consultants to scout for gas reserve properties. This phase will Utilize the proposed FY
04/05 budget for this project of $65,000. Staff is requesting Council approval of the
following project criteria:
1.Project must be a partnership with one or more other entities; .....
2.Producing field must be proven, developed, producing (PDP); .........
3.Gas must exist inan onshore U.S. producing region;
4.Adequate production history exhibiting well-established decline curve;
5.Large number of producing wells;
6.Low variability in monthly production levels;
7.Production life in excess of 10 years;
8.Production field must be operated by large, experienced, financially stable
company; and
9.Palo Alto’s estimated share of the gas will not be for more than 50% of the City’s
estimated annual load requirement.
UAC 050504 Item 3 Page 3 Of 19
Details of staff’s research and analysis of gas reserve acquisition are in Attachment E.
The City could take advantage of its low cost of capital and prepay f(~ natural gas in
exchange for a discounted price under new regulations implemented by the IRS as of
October 2003. Staff investigated the activities of other municipalities and found that it is
possible to structure a prepay deal with virtually no credit risk to the City. While this
appears to be a low-risk alternative for Palo Alto, the estimated benefit of $50k per year
is too small to justify the staff time and cost of formal, expert advice required to structure
a deal and then explain it to the City’s decision makers. As a result staff recommends not
participating in a prepay at this time but the pursuit of low-cost, high-reward supply-
related opportunities as they arise.
Staff recommends developing comprehensive demand-side management goals and an
implementation plan by Fall 2004 in time for incorporation intoFY 05-06 and future
ratemaldng and budget decisions. This will include evaluation of opportunities to increase
efficiency of commercial, industrial and institutional gas customers by deploying
advanced metering technologies and on-line usage analysis.
In the interim, staff recommends continued implementation of current and planned FY
04-05 demand-side management programs including evaluating opportunities to leverage
portions of the annual Gas DSM budget of $225,000 to reduce Utilities costs, such as
targeting supplemental furnace rebates to Rate Assistance Program (RAP) participants
having older pilot light units in order to reduce the number of Field Service seasonal pilot
turn-on and turn-off workload. This could result in savings to both the participating
customer (operating costs) and the Utilities Department (labor and financial subsidies).
BACKGROUND
General Palo Alto Gas Utility Background
A glossary of Gas terms is included in Attachment F.
Palo Alto’s total annual gas usage is approximately 3,250,000 MMBtu comprised of
approximately 20,000 residential customers, 2,300 commercial customers, and 10 large
customers. The load has declined over the past few years due to the economic downturn.
Figure 1 below is a historical representation of Palo Alto’s load.
UAC 050504 Item 3 Page 4 Of 19
Historical & Projected Retail Sales R~venue by Rate Class
~G3, G6, GT, Gl1: Large Commercial, Municipal
Figure 1
The pie chart below, Figure 2, shows the make-up ofPalo Alto’s load by major customer
class. Palo Alto also offers direct access to the 10 largest customers. This rate has been
in effect since 1999 (CMR148.99). However, to date no customers have elected to
receive gas commodity from any alternative supplier. Currently all 10 large customers
are on either the monthly variable market rate or a 12- or 24-month fixed-term rate.
Palo Alto Gas Utility Customer Mix
Large commemlal customers wilh
market-based rates (G3)
10 customers
Large Commercial customers with fixed
term rates (G11 )
2 customers
Residential customers (G1)
20,000 customers
Small commemial
customers and municiple
customers (G2 & G6)
2300 customers
Figure 2
History of GULP
In 2001 staff began the process of developing a Long-Term Electric Acquisition Plan
(LEAP) as a response to the electric energy deficit that will occur when the Western
contract expires in December 2004. Council approved LEAP objectives in November
2001 (CMR:425:01), LEAP guidelines in October 2002 (CMR:398:02), and the LEAP
Implementation Plan on August 4, 2003 (CMR:354:03).
UAC 050504 Item 3 Page 5 Of 19
Staffhas now completed the process of developing a plan similar to the LEAP for the gas
Utility. Like the LEAP, the Gas Utility Long-Term Plan (GULP) will be the vehicle by
which the gas commodity portfolio will be managed consistently, transparently, and with
input from the public and the Council.
In June of 2003 the Utilities Advisory Commission approved three objectives and four
guidelines for GULP. These objectives and guidelines were subsequently approved by
the Finance Committee and by City Council (CMR:355:03)~ The Council-approved
GULP objectives are .included in Attachment A. The UAC reviewed staff’s preliminary
GULP recommendations at its February 11, 2004 meeting. There were no concerns about
the recommendations expressed by the UAC at that time.
The graphic below traces the timeline for GULP development and implementation.
Approval of energy Risk Management Policies
Adoption oi~ gas commodily lacldering slrategy
Approval of DSM & Public Benefits Plan
Approval of planninglobjectives and guidleines
Revise Gas Laddering Strategy
16. Preliminary GULP Recommen(/alions
17. Final GULP
la. implementation
[-. Compleled . ¯ . -’ " " . ...."I
ICouncil approval of risk management policies 2120/2001 (CMR:130.01
Revised I0/0"I/02 (CMR:398.02)
Jlnformation report to Finance Commifiee April’ 2001 {CMR:196:01
Council approval - 12/3/01, (CMR:421:01 )
IUAC approved June 2003
Council approved August 4, 2003 (CMR:355:03)
lPresented to UAC January 14, 2004
Information Report to Council March 15, 2004 (CMR:167:04
IPresen[e6 to UAC - February 2004
ITo UAC June 2004
To Council - July 2004
IStarting Summer 2004
DISCUSSION
Cun-ently, the City does not hold any long-term assets, Acquisition of or participation in
(1) gas storage, (2) gas pipeline capacity, and (3) gas reserves, (4) prepayment for gas,
and (5) gas efficiency programs Was evaluated. In parallel, the City gas commodity
procurement strategy was revisited and revised. The results of that exercise are
documented in Attachment B.
To be in compliance with the Council-approved GULP guidelines, any adopted gas
commodity and asset portfolio must meet the following requirements:
1.Adequate supply rate stabilization reserve;
2.Market price exposure for a portion expected pool load;
3.Maximum term of 10 years for fixed-price energy purchase contracts; and
UAC 050504 Item 3 Page 6 Of 19
4. Reliability of supply at fair and reasonable transmission cost.
Storage Analysis
Gas suppliers~ local distribution companies (LDCs), and end-users use storage for a
variety of reasons. Gas suppliers use it to balance supply with demand for groups of
customers. Many LDCs, including PG&E, .are mandated to hold storage for their core
customers. Large industrial curtailable end-users use storage for reliability. Staff
identified two potential Palo Alto uses for storage: (1) swing gas for load-supply
balancing and (2) season price difference. The cost of storage includes three elements:
inventory, injection, and withdrawal.
In this analysis three storage contracts were evaluated for each potential use. The
development of these parameters for these contracts was based on cold day conditions for
three scenarios: 1 in 50 years, 1 in 20 years, and 1 in 10 years abnormal weather
conditions. A storage contract that would mitigate against a 1 in 10 years weather
scenario would cost approximately $200K per year while contracts for 1 in 20 and 1 in 50
years mitigation would cost $250K and $650K respectively. Details of the storage
analysis are contained in Attachment C.
Daily Balancing
The first potential value of storage is daily balancing, particularly during operational flow
order and emergency flow order’events (OFOs and EFOs). During an OFO or EFO
customers are required to balance supply with demand on a daily basis or face penalties.
The range allowed for imbalance is determined by PG&E for each event and may be as
low as 0%; the penalty is also determined by PG&E for each event and may be as high as
$50 per MMBtu.
Staff evaluated the value of OFO/EFO mitigation by examining historical City usage and
actual OFO/EFO events including PG&E-declared ranges for balancing penalty
magnitude and actual daily spot prices. When the City complies with a daily balancing
event, gas is purchased or sold at the prevailing daily a price to balance supply with
demand for that day. Table 1 shows the historical value of penalty avoidance. Given the
$200k to $650K cost for the three storage contracts evaluated, it is apparent that,
historically, storage would not have been a valuable asset to own.
UAC 050504 Item3 Page 70f19
Total OFOfEFO Mitigation Benefit
99-00 00-01 01-02
Volumetric Value
(Difference between storage
gas price and daily price
multiplied by gas needed on
EFO/OFO day)
Penalty Avoidance
(PG&E penalty that would
have been paid had no storage
contract or swing gas been
available)
Total OFO/EFO Benefit
02-03
$1,792 $ 4,533 $ 2,405 $ 7,076
$4,281 $22,541 $24,830 $12,645
$6,073 $27,074 $27,235 $19,721
Table 1
Average
$3,952
$16,074
$20,026
However, since history is not always an adequate measure of an asset’s worth, stress
testing was undertaken. Given that PG&E can raise OFO penalties to $50 per MMBtu
and given the extremely high usage the City can experience on a cold winter day, a
maximum exposure can be calculated. A less drastic scenario whereby usage is up 30%
for a 4-day cold-snap and an imbalance penalty of $25 per MMBtu is imposed by PG&E
was also tested. Table 2 shows the City’s penalty exposure of the City for two OFO
scenarios.
One-Day Possible City Exposure to Very High OFO/EFO Penalties
Penalty # of Days Tolei’ance Load Nominated Penalty to
$/MMBtu MMBtu (Expected) Load The City
MMBtu
50 1 0%32,000 17,000 750,000
(Maximum
penalty)
25 4 0%22,000 17,000 $500,000
Table 2
The first scenario shows that on one extremely cold day at a $50 per MMBtu penalty, the
City could pay $750,000. The second scenario is based on an event with a historic
probability of 2% whereby 4 days of 22,000 MMBtu per day usage occurs. If a penalty
of only $25 per MMB[u, a penalty which PG&E has imposed in the past, were imposed.
during such weather and the City were not able to purchase gas supply from other
sources, the City would pay $500,000 in penalties. From this stress test it is clear that the
City must have some safe guard in place to mitigate OFOs and EFOs.
Currently, the City does not hold storage but does contract with gas suppliers to
guarantee the sale or purchase of gas at daily market prices. The City’s balancing agent
UAC 050504 Item 3 Page 8 Of 19
and scheduler; IGS, is able to use these swing contracts to balance the City’s supply and
demand. Traditionally, the cost of these arrangements has been significantly less than the
cost .of storage~ If the City is able to continue to negotiate swing gas deals for less than
the cost of storage and if no asset acquisition is mandated, no storage should be acquired
at this time.
Season Price Difference
The value of storage when used to capture season price differences is the ability to buy
gas in less expensive time periods and withdraw it during periods when theprice of gas is
higher. Given the City’s laddering strategy, this essentially means that at a given point in
time, the City can buy gas and inject it into storage with a plan for withdrawing during a
month with a higher forward price, thus locking in the seasonal price differential.
Staff found that the cost of storage is greater than the expected seasonal price benefit
making this an uneconomical use for this asset by itself. The distribution of storage value
shows that when the seasonal price differential reaches the 90th percentile high value,
talcing advantage of seasonal price differences could offset the cost of storage thereby
creating value for the holder of a storage contract. Based on historical data, the holder of
a gas storage contract such as the one specified above, could have realized a profit for
some of contract years if all gas was purchased at the precise time when the forward price
curve was such that an optimal seasonal price differential could be captured. Given the
City’s laddering strategy whereby gas is purchased systematically over a period of time
and staff does not attempt to predict the future market, this kind of activity would be
contradictory to the City’s risk management objectives. Staff concludes that storage has
no value for seasonal price difference and should not be acquired on this basis..
Recommendation:
1. Do not contract for natural gas storage capacity at this time.
Pipeline Analysis
Staff’s objective was to deterrnine the value, if any, to Palo Alto of acquiring additional
pipeline capacity. Details of the pipeline capacity analysis are in Attachment D. The
value of any pipeline segment may be calculated by comparing the market cost for gas at
one end of the pipeline to the market cost of gas at the other end of the pipeline. The
difference between two pricing points is generally referred to a "basis." Staff examined
the historical and projected basis for several pricing points to determine the market value
of several pipeline routes that may be of interest to the City. The estimated future market
value of each of these paths was compared against the pipeline’s tariff rates.
UAC 050504 Item 3 Page 9 Of 19
Pipeline Rates Com )ared to Pipeline Value
2004
Pipeline
Pipeline Path Toll 11
AECO-Malin 50.38
Malin-PG&E City Gate $0.30
OpaI-SCG Topock $0.51
San Juan Basin-SCG Topock $0,39
PG&E Topock-PG&E CG $0,19
Fuel
@
$4.00/D th
$0.13
$0.05
$0,12
$0.13
$0.05
Total
Transport Historical
Cost 1998;2003 2/
$0.51 $0.33
$0.35 $0,25
$0.64 $0.58
$0.51 $0.35
$0.24 $0.17
Basis Differential
Forecast (20035)
2004-2008 I 2009-2013 I 2004-2013
$0.18 $0.26 $0.22
$0.18 $0.20 $0.19
$0.48 $0.43 $0.45
$0.34 $0.34 $0.34
$0.13 $0.17 $0,15
1/ Toll at 100% load factor, excluding fuel.
2/Average excluding energy cdsis (June 2000-J uly 2001)
3/15-year term on 2003 Expansion. Comparable toll on pre-exoansion syslem is $0.46 per Dlh, incl fuel,
Table 3
The analysis concluded that the expected value of transportation on the major paths is
less than the full pipeline toll. This is consistent with historical trends and the outlook
that California as a whole will have a surplus of interstate pipeline capacity for the
forecast period as stated in the California Energy Commission’s October 2003 "Electric
and Natural Gas Assessment Report." In addition, it is likely that additional pipeline
capacity will be built to transport Rocky Mountain or Canadian gas to northern California
during the next 10 years.
Pipeline capacity is also available on the secondary market, often at less than the full
tariff pipeline rates. However, this value, like the future market price fbr gas, is uncertain
and can be hedged in the same way that gas commodity is hedged by locking in basis
differential without making a long-term physical commitment. In addition, it was
verified that gas prices at Southern California border are highly correlated with prices at
Northern California border yielding no advantage to diversifying purchase points.
Recommendation:
2. DO not acquire additional natural gas pipeline capacity atthis time.
Gas Reserves Analysis
Staff’s analysis of gas reserve focused on understanding the economics, risk and benefits
of reserve ownership by 1) learning from Sacramento Municipal Utility’District (SMUD)
and Nebraska Public Gas Association (NPGA)reserve acquisition experiences, 2)
analyzing the relative merits of reserve investment versus continued reliance on markets
purchases to meet load, and 3) exploring potential market opportunities. Details of the
reserves analysis are in Attachment E
The Nebraska Public Gas Agency (NPGA) is a joint action agency delivering natural gas
and gas related services to member municipal gas utilities in the central United States.
NPGA purchased 100% ownership in five deep wells in Texas in 1995. The wells did
not produce as projected. Problems also developed due to absentee ownership, high-than-
expected maintenance costs, and NPGA’s general lack of experience in the operation of
UAC 050504 Item 3 Page 10 Of 19
producing properties. Unacceptable losses necessitated that NPGA sell the property.in
2O00.
SMUD, on the other hand, procured a 25% share of a large cold-bed methane field in the
San Juan basin to meet growing electric generation demand. The field is .55,000 acres
with 265 producing wells. The acquisition amounted to 150 BCF in a 40-70 year life field
for -$135 million from E1 Paso Corp in March 2003. At -20,000 MMBtu/day, the
production satisfies 25% of SMUDs electric generation needs now and is projected to
meet 15% of SMUD’s needs after 2005. The main owner/operator is Willliams. SMUD
holds pipeline capacity to move the gas to Sacramento. Physical pipeline capacity may
be required to qualify to issue tax-exempt bonds for an acquisition.
The SMUD acquisition consisted of upfront costs of approximately $800k for consultants
plus a "finder’s fee" to the investment bankers (estimated $2M total cost), a purchase cost
of $20 million, and ongoing operating and drilling costs. In addition, SMUD estimates
that 1-2 full-time in-house employees are required to manage accounting and other details
of ownership. Given the large upfront costs and ongoing administrative requirements, a
minimum project size of 5,000 MMBtu per day is the rule-of-thumb volume considered
to be economic. This volume is approximately equal to the City’s entire baseload and is
probably a larger percentage of the City’s load than the City would be interested in
securing by this means. A joint partnership whereby the upfront costs and post-
acquisition administrative costs could be shared may result in a more attractive project
for the City. SMUD’s acquisition was the first major gas reserve purchase by any
California utility; and SMUD continues to be in the market to acquire more reserves,
targeting to meet -50% of their needs from long-term resources.
The largest risk associated with gas production ownership is the production rate. Even
with engineering estimates, it is impossible to lcnow what a given well or even a field will
produce over time, If the reserves do not meet expectations, the debt incurred does not
go away, causing a potentially very high unit cost for the gas. If such an outcome is
combined with low market prices, the mark-to-market risk of wellhead ownership
becomes quite high. Additional risks include daily production swings, uncertain
operation and maintenance costs, and unexpected environmental clean-up requirements.
Staff’s analysis was modeled based on SMUD’s project assuming an initial production of
3,000 MMBtu/day (30% of City’s average annual load; 60% of the City’s base load),
declining @1.74% per year over the 30-year life of the field. It was assumed that the
expected long-tetnn price of gas stabilizes at $4.50/MMBtu and then increases 0.4% per
year in real terms during the 30-year life of the field. Annualized market price volatility
over the 30 years assumed to be 15% per annum, producing an 10%-50%-90% price in
year 30 of 2.45-5.17-8.80 $/MMBtu in 2004 dollar terms.
UAC 050504 Item 3 Page 11 Of 19
After gathering, processing, and transportation costs have been added to the cost of
production the total gas cost at the PG&E Citygate was determined to range between
$3.20 and $4.70 per MMBtu.
Staff found that, while no conclusion could be drawn regarding the relative expected
price, market price variability is greater than production cost variability. This concept is
illustrated in Figure 3 belowl
Illustration of Variability of Ownership Cost
Vs. Market Price Variability
30% ofPalo Alto’s Annual Demand is Met by Well Production
Q~erlay Chart
Frequency Q:rr~rison
.071
I~ .018 Cost dV~l
Since any gas reserve acquisition will be a long-term endeavor (more than 10 years), and
since the market price of gas becomes more uncertain with time, Palo Alto may not
choose to have fixed-price gas for the life of the project. It is possible to convert fixed-
price reserves to an index-based product using financial instruments. It is estimated that,
using Palo Alto’s low cost of capital, such a conversion could result in a discount to
index of as much as $0.40-$0.50 per MMBtu. Of course, whether or not Palo Alto is
eligible to use such instruments will need to be explored.
Staff concluded from this research and analysis that, although SMUD’s cmTent project
could easily be modeled, each gas reserve field has unique characteristics, therefore, only
a specific project can be thoroughly evaluated. It is fair to estimate that purchasing
production to serve approximately 30% of the City’s average annual load over 30 years
will require an investment of about $30-$40 million ($0.90-$1.20/MMBtu for gas in the
ground) and to achieve economies of scale, and the interest of investment banks and
suppliers, Palo Alto will need to partner with other municipalities. Lastly, the capability
to physically transport gas from producing field to Palo Alto may be required for tax-
exempt financing to apply.
UAC 050504 Item 3 Page t20f19
Staff proposes the following project criteria:
1.
4.
5.
6.
7.
8.
Must be a partnershipwith one or more other entities
Producing field must be proven, developed, producing (PDP)
Gas must exist in an onshore U.S. producing region
Adequate production history exhibiting well-established decline curve
Large number of producing wells
Low variability in monthly production levels
Production life in excess of 10 years
Production field must be operated by large, experienced, financially stable
company
Palo Alto’s estimated share of the gas will not be for more than 50% of the City’s
estimated annual load requirement
Should Palo Alto proceed with this project, the following are the potential project phases:
1. Phase t (estimated $200K; Palo Alto share $65K)
a. Identify and evaluate potential consortiums including joint action
opportunities
b. Enter into consortium agreement to scout properties
c. Consortium employs investment bank to scout properties
d. Consortium identifies attractive; feasible opportunities
2. Phase 2 (estimated $800K; Palo Alto share $260K)
Stx~dy the property including reservoir engineering, land experts, environmental
assessment, lawyers ($800K total)
3. Phase 3 (estimated $125M; Palo Alto share $41M)
Consortium purchases property
4. Phase 4
Asset maintenance (accounting, royalty payments, new drilling, maintaining
existing equipment)
Staff recommends proceeding with Phase 1 using the proposed FY 04/05 budget for
this project of $65,000. With other members of a consortium, this will be sufficient to
hire investment bank to scout properties.
Recommendation:
3.Approve staff undertaking initial steps related to gas reserve acquisition
including:
1. Identifying and evaluating potential consortiums including joint
action opportunities;
2. Entering into consortium agreement to scout properties;
3. Through the consortium,, employing an investment bank and
consultants to scout properties and spend up to $65,000 in FY 04-
05 related to this effort; and
UAC 050504 Item 3 .Page 13 Of 19
4. Through the consortium, identifying attractive, feasible
opportunities.
Thisrecommendation is for only the first of four phases that would be required for a
consortium to own gas reserves. At the end of each phase, Council will approve further
Palo Alto efforts, if any..It should also be noted that should Palo Alto and the consortium
proceed to Phase 2, spending $800 performing due diligence will not guarantee a
successful purchase as producing properties are sold in an auction-type process, It is,
therefore, possible that more that that amount will be needed to, ultimately, acquire a
property.
Opportunities to Prepay for Natural Gas Purchases in Return for Concessionary
Pricing Terms
Effective October 2003, a set of new IRS regulations explicitly permit tax exempt
financing of public utility electricity and natural gas pre-purchases. This rule provides the
City the oppol~nity to seek cost savings by prepaying for the purchase of natural gas or
power in return for a discount.
The primary benefits of prepay transactions is the ability of the City to leverage the
favorable capital costs of the City in return for a discount on natural gas supplies
delivered by a taxable entity. The advantage is typically harnessed by obtaining supply at
a discount to index at a delivery point of choice. The amount of discount is dependent on
the cost of capital differential between the supplier and the Cityl and the marginal federal
and state corporate tax rates.
¯ Pre-pay contracts are typically structured with the tax-exempt debt issuer issuing bonds
for the purchase of energy. The supplier receives the funds and provides a credit on the
purchaser’s monthly bill that will cover both the debt service obligation and a guaranteed
discount.
In addition, a surety provides performance guarantees to the bond-holder: If required a
swap agreement with an independent third party provides for channeling payments from
the supplier (and at times a limited amounts of funds from the purchaser too) to the bond-
holde):s. At the end of the contract term, the bond holders will be fully paid and the gas
flow from the supplier will cease. Depending on how a transaction is structured, the
recourse for the bond payment default could circle back to the surety, the supplier, or the
bond-issuer. Staff has considered only deals structured whereby the supplier holds the
credit risk. The American Public Energy Agency (APEA) has entered into prepay deals
for a group of Nebraska-based municipalities, The eXperiences of APEA suggest that the
buyer’s credit risk can be managed through ~rbulent market events and even supplier
banlcruptcy.. ’
UAC 050504 Item 3 Page 14 Of 19
Staff’s estimates that, given current interest rates, the discount for entering into a prepay
deal is in the range of 1-10 cents/MMBtu for a 10-year transaction with an AA rated
(Standard and Poor’s Rating) supplier. At present due to the relatively low cost of capital
for all parties concerned, the discount tends to be at the lower end (in the range of 2-3
cents per MMBtu.) A $0.03 per MMBtu discount translates to $50K per year for Palo
Alto’s baseload of approximately 5,000 MMBtu per day.
Staff has identified only one supplier, British Petroleum, who is currently interested in
prepay deals. This supplier has a total deal threshold of $100 million, making a
consortium of some type essential for Palo Alto to participate, and a desired term of 10
years. Bank of America is the primary financial institution structuring these deals.
While staff believes that credit risk can be minimized by guarantees present in the Bank
of America structure, this structure is quite complex and includes the use of financial
instruments to convert fixed-price gas to index-priced gas and to swap fixed to floating
interest rates. Whether or not the City is able to participate in such an arrangement is
questionable. Furthermore, constructing a prepay deal and explaining the deal to
management, the Utilities Advisory Commission, and City Council will require large
amounts of staff time. Therefore, staff has concluded that the benefits of the City
participating directly in a prepay contract are currently outweighed by the cost of
implementing such a contract.
If interest rates rise or if other market conditions change, prepay deals may become more
attractive in the future. In addition, there may be an opportunity for Palo Alto to
purchase gas from another municipal entity that has excess prepay gas to sell. For
example, APEA is planning to execute a prepay deal and excess gas, by law, must be sold
to another tax-exempt entity. Staff will monitor the prepay.activities of other municipal
entities and explore opportunities to acquire gas at a discount.
The Preliminary recommendation regarding prepays was:
Investigate gas prepay activities by other municipal utilities and explore deal
structure, credit issues, and use of financial instruments by the City.
Staff recommends changing that recommendation and adding another.
Recommendations:
4. Do not partic.ipate in a gas prepay deal at this time.
5.Pursue any low-cost, high-value prospects to acquire supply-related
resources that may arise from time to time.
UAC 050504 Item 3 Page 15 Of 19
Joint Action Opportunities for Natural Gas Portfolio - Exploration of options
There are a number of opportunities present for entities to collectively procure, transport,
store and schedule natural gas to meet loads. A clear example Palo Alto had identified
previously was to be part of a natural gas pool for scheduling supplies to meet load and
minimize penalty exposure during OFO/EFO events. The City was unable to take
advantage of this pooling opportunity due to the poor credit standing of the private sector
pool operator who made the proposal. As a result, the City had to contract with swing gas
suppliers and had to incur an additional cost of $180,000/year to obtain EFO/OFO
penalty protection.
In addition to this opportunity to pool scheduling operations, a number of additional
opportunities were identified by the GULP analysis. NCPA with membership urging will
be exploring these opportunities further.
1.Operation of a natural gas scheduling pool .............
2.Procurement of natural gas-reserves
3.Joint operation of natural gas storage contracts
4.Contracting or purchase of backbone pipeline capacity
1. Operation of Natural Gas Scheduling Pool
The City contracts for natural gas supply with suppliers who have Master Agreements
with the City. These suppliers deliver the gas daily to City of Palo Alto’s Scheduler, IGS,
Inc., a City contractor.
The gas supply purchased month ahead has two components. The first component of the ’
purchase is designed to deliver a fixed quantity each day of the month to meet the
average load of the City for that month. The second component, swing gas, is purchased
to provide the City the option to call on additional gas on high usage days or sell’ surplus
gas during 10w usage days. This type of swing contract is also needed to provide the
City’s 24x7 scheduling contractor the flexibility to order gas from approved City
suppliers. This swing gas purchase option has a considerable premium associated with it,
but is a necessity to maintain daily supply-demand balance within tolerance bands
specified by PG&E to maintain transportation system reliability. Pooling of scheduling
operations, by multiple load serving entities such as other municipalities with natural gas
fired generators, could potentially reduce this cost by aggregating loads and supply
resource within the PG&E system.
A recent RFP for such services from private sector parties did not result in any suppliers
meeting City’s expectations. Efforts in exploring such joint action opportunities with
other municipal utilities through NCPA will be explored further. The gross value of such
opportunities is estimated at approximately $100 dollars per year.
UAC 050504 Item 3 Page 16 Of 19
2. Procurement of Natural Gas Reserves
The analysis discusses the merits and economics ~f acquiring natural gas reserves. As
outlined in the analysis, the costs of undertaking site-specific analysis and due diligence
worl~ before any purchase commitments could be made are relatively large. In addition,
for the optimal size of reserve procurement for Palo Alto (assuming acceptable pricing
terms), is in the 20-30 BCF range over 20-30 years. These facts suggest there are
synergies to be part of a larger consortium in managing and maximizing the value of such
a long-term asset. Staff will explore this opportunity in conjunction with other California
municipal agencies. ..
3. Natural Gas Storage Opportunities
Storage asset’ value and cost are driven by three primary factors: the amount of storage
capacity, the injection rate, and the withdrawal rate. Even if a number of members
individually contracted for storage services, there could be synergies operating in a
coordinated manner. For example, two members with complementary loads may be able
to trade storage capacity during seasonal peaks .thus minimizing the cost for both
members. If the City is ever mandated to hold storage, such joint opportunities will be
explored further.
4. Contracting or purchase of backbone and interstate pipeline
If a large consortium can be formed, opportunities are available to obtain discounts from
PG&E when contracting for backbone capacity or when negotiating a purchase of a part
of an existing pipeline. It has also the potential to induce additional pipeline investments
by third parties:
The joint action value associated with this opportunity tends to be ~one-of-a-kind’ and
tend to be longer te~zn in nature. Opportunities are similar to subscribing to the Mojave
pipeline company expansion the City explored in the mid-1990s. No immediate
investigation of a joint pipeline procurement opportunity is recommended at this time,
unless it is part of a larger reserve acquisition proposal.
Natural Gas Efficiency Programs
From a wholesale gas purchasing perspective, there is no Utilities-driven imperative to
reduce natural gas supply purchases since supplies are adequate and available in the
marketplace and commodity costs are recovered through rates. Energy efficiency efforts
in recent years have primarily targeted the residential end user in the form of education
and rebates. Programs have included rebates for dual-paned windows, replacement of
home space and water heating systems, and furnace tune-ups. This strategy had helped
levelize the City’s gas consumption as is shown in Figure 4 below.
UAC 050504 Item 3 Page 17 Of 19
40-
35-
Figure 4
In the event of resource shortages, physical restrictions, or economic conditions requiring
significant curtailments or spot gas purchases, the Gas Supply Reserve may provide
financial support to the Gas Public Benefits Program in order to aggressively capture
those cost-effective conservation opportunities which will result in lower costs to all
ratepayers. Staff recommends developing comprehensive demand-side management
goals and an implementation plan by Fall 2004 in time for incorporation into FY 05-06
and future ratemaking and budget decisions. This includes evaluation of opportunities to
increase efficiency of commercial, industrial and institutional gas customers by deploying
advanced metering technologies and on-line usage analysis.
One example of possible demand-side management may be to avoid penalties and gas
costs associated with occasional PG&E-required daily balancing. During these events,
the City must balance demand with supply or be subjected to penalties as high as $50 per
MMBtu. For large customers with discretionary load, it may be mutually beneficial to
share the savings achieved by reducing gas usage .instead of increasing supply on those
days.
In the interim, staff recommends continued implementation of current and planned FY
04-05 residential demand-side management programs. This includes evaluating
opportunities to leverage portions of the annual Gas DSM budget of $225,000 to reduce
Utilities costs, such as targeting supplementa! furnace rebates to Rate Assistance Program
(RAP) participants having older, pilot light units, in order to reduce the number of Field
Service seasonal pilot turn-on and turn-off workload. This could result in savings to both
the participating customer (operating costs) and the Utilities Department (labor and
financial subsidies).
UAC 050504 Item 3 Page 18 Of 19
Recommendation: -
6. Develop comprehensive demand-side management goals and implementation
plan by Fall 2004 in time for incorporation into FY05-06 and future ratemaking
and budget decisions. In the interim, continue implementation of current and
planned FY 04-05 residential demand-side management programs.
NEXT STEPS
Upon council approval, the GULP recommendations will be implemented beginning
summer 2004.
ATTACHMENTS:
A. Natural Gas Supply Portfolio Planning and Management Objectives and
Guidelines for the Gas Utility Long-Term Plan (GULP) Approved by City Council
on August 4, 2003 (CMR:355:03).
B.Gas Laddering Strategy
C.Storage Acquisition Assumptions, Analysis, and Results
D.Pipeline Capacity Acquisition Assumptions, Analysis, and Results
E.Gas Reserves Acquisition Assumptions, Analysis, and Results
F.Glossary of Gas Terms
PREPARED BY:
Karla Dailey, Resource Planner
Resource Management
Bernard Erlich, Senior Market Analyst
Resource Management
REVIEWED BY:
APPROVED BY:
~~ Balachandran
Assistant Director, Resource Management
/
of Utilities
UAC 050504 Item 3 Page 19 Of 19
ATTACHMENT A: Natural Gas Supply Portfolio Planning and
Management Objectives and Guidelines for the Gas Utility
Long-Term Plan (GULP) Approved by City Council on
August 4, 2003 (CMR:355:03).
The three following GULP Objectives govern gas supply resource asset acquisition and
energy efficiency strategies for the gas utility:
Objective 1: Ensure low and stable gas supply rates for pool customers.
Objective 2: Provide superior financial performance to customers and the City by
managing the supply portfolio cost in a competitive manner compared
to market cost and a retail supply rate advantage compared to PG&E.
Objective 3: Balance environmental, rate, and cost impacts when considering energy
efficiency investments.
,I
To facilitate the development of specific recommendations, staff has developed four GULP
Guidelines based on the three Objectives. Key themes found in these GULP Guidelines
address diversification to minimize risk and stabilize rates, operational flexibility, and
opportunities for energy efficiency.
Guideline 1: Market Risk Management- Manage market risk by adopting a portfolio
strategy for gas supply procurement by."
A. Diversifying energy purchases for the pool ac~vss commitment date, delivery date,
duration, suppliers, pricing terms & delivery points;
B. Maintaining a prudent exposure to changing market prices by leaving some fraction
of the forecasted gas pool needs exposed to near-term market prices,"
C. Avoiding long term (> 10 years) fixed-price commodity contracts.
Guideline 2: Asset Aeq uisition and Management - Explore supply, pipeline, and storage
acquisition options available to the City which may be assembled to yield reliable supply at
fair and reasonable cost, talcing into consideration."
A. Long-term supply cost for gas deliveries at PG&E Citygate;
B. Operational needs including the need for daily balancing during Operational and
Emergency Flow Orders;
C. Existing and potential regulatory mandates;
D. Potential operational streamlining opportunities with other agencies; and
E. City’s low cost of capital for asset acquisition.
Guideline 3: Management of Regulatory and Legislative Matters - Serve as an effective
voice to protect and enhance the City’s position in regulatory and legislative arenas by:
A.Intervening in the regulatory and legislative arenas to ensure that the City’s gas utility
interests are protected and enhanced; and
Item 3: GULP Attachment A Page I of 2
B. Exploring potent(al joint action with other public agencies..
Guideline 4: Gas Energy Efficiency Investments -Pursue cost-effective energy efficiency
investments by:
A. Providing expertise, education and incentives to support cost-effective customer
efficiency improvements;
B. Demonstrating new efficiency and load management alternatives; and
C. Ptvviding rate assistance and efficiency p~vgrams to low-income customers.
Guidelines 1,2 and 3 apply to Objectives 1 and 2 while Guideline 4 applies to Objective 3.
For example, successful management of market price risk will result in stable rates for
customers. Asset management will result in good financial performance for the City.
Item 3: GULP Attachment A Page 2 of 2
ATTACHMENT B: GAS LADDERING STRATEGY
The Director of Utilities has revised the gas commodity purchasing strategy whereby
60% to 100% of the load will be purchased for the nearest 18 month time period, 40% to
75% of the load will be purchased for months 19 to 27 months from now, and 20%to
50% of the load will be purchased for the months 28 to 36 months starting in January
2004. These purchases will apply to the residential and small commercial customers’
loads only. Staff presented the revised strategy to the UAC at its January meeting and as
an information report to Council on March 15, 2004 (CMR: 167:04). The revised strategy
is shown below along with the old strategy in Table A, and the revised strategy is shown
in Figure 1. Implementation of the revised strategy began in January 2004.
GAS COMMODITY PURCHASING STRATEGY
Current vs. Revised
Monlhs from Present I1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36
Revised Strategy 60% - 100%40% - 75%20% - 50%
Old Strateg)/60% - 100%40% - 60%20% - 30%
Table A
Figure 1 below represents the status of the purchasing’ strategy as of April 2004. The
shaded area represents the ranges that staff operates within.
500,000
45O,OQO
400,000
350,000
~300,000
~250,000
~200,000
150,000
100,000
50,000
Gas Supply Procurement Program for Pool Customers
Monthly Fixed-price Purchase Volumes Compared to Target
¯ as of April 14, 2004
Expected Poo; Customer Load
Fixed-price Actual fixed-Price Pur
Purchase Target /
///
/* Shaqed area represents
minimpm and maximum
purchSses under laddering
stra lY
** ,,cast revised
Decer ]ber 2003
75% Target70% Actual
60% min - 100% max"40% min - 75% max-
Actual --
ATTACHMENT C: STORAGE ACQUISITION ASSUMPTIONS, ANALYSIS, and
RESULTS
INTRODUCTION
This document summarizes the major assumptions underling the storage contract evaluation
model and the results of the analysis. The gas storage model was developed as part of the Gas
Utility Long Tema Plan (GULP).
BACKGROUND
Staff is evaluating the value of gas storage based on two potential uses for the asset:
l.Operational FIow Order (OFO)/Emergency Flow Order (EFO) and balancing needs
2.Taking Advantage of Seasonal Price Differences
MODEL DESCRIPTION
The cost of storage includes three elements:
Injection Demand Charge
For each month the maximum daily injection quantity is multiplied by the injection demand rate
to arrive at the injection demand charge. For exmnple, if, during the month of April, Palo Alto
requires a maximum daily injection quantity of 5,000 MMBtu/day and the negotiated injection
demand rate is 3.00 per MMBTU per day for that month, then the injection demand charge for
the month of April is $15,000.
Inventory Demand Charge
For each lnonth the inventory capacity, which does not vary over the terrn of the contract, is
multiplied by the inventory demand rate to arrive at the inventory demand charge. For example,
if in April 2004, Palo Alto required an inventory capacity of 1,000,000 MMBtu and the
negotiated inventory demand rate for the month of April was 0.03 per MMBtu, then Palo Alto
will pay an inventory demand charge for the month of April of $30,000..
Withdrawal Demand Charge
For each month the maximum daily withdrawal quantity is multiplied by the withdrawal demand
rate to arrive at the withdrawal demand charge. For example, if the month of November 2004
requires a maximum daily withdrawal qnantity of 7,000 MMBtu per day and the negotiated
withdrawal demand i’ai~ i~ Z00 per MMBtu per day fo~: tilat month; tlien the withdrawal demand
charge for the month of November is $14,000.
Tl~’ee contracts were evaluated using daily injection and withdrawal quantities the City would need
in order to hedge against the daily balancing requirements of:
1.One-in-ten year daily gas demand;
2.One-in-twenty year daily gas demand; and
3.One-in fifty year daily gas demand.
Table 1 shows the cost components and the total cost of each of the three contracts evaluated.
Item 3 GULP Attachment C Page 1 of 8
Table 1: Cost Components of Storage Contracts
1-in 50 Year Daily Demand 1-in 20 Year Daily 1-in-10 Year Daily
Event Demand Event Demand Event
Inventory 150,000 150,000 150,000
MMBtu MMBtu MMBtu
Maxinaum Daily 4,600 - 13,000 MMBtu t ,000 - 5,200 MMBtu 800- 4,100
Injection MMBtu
Withdrawal 4,0000- 14,000 MMBtu 1,000 - 6,000 800- 4,200
MMBtu MMBtu
Inventory Demand $54,000 $54,000 $54,000
Charge
Injection Demand $288,336 $103,818 $ 81,300
Charge
Withdrawal Demand $294,390 $78,970 $64,066
Charge
Storage Demand $636,726 $236,788 $I99,366
Charge
Commodity Charge $7,000 $7,000 $7,000
Total Cost of Storage $643,726 $243,788 $206,366
OFO/EFO Mitigation and Balancin~ Needs
1. Methodology and Assumptions
The second potential value of storage is for daily balancing, particularly during operational flow
order and emergency flow order events (OFOs and EFOs). During an OFO or EFO, customers
are required to balance supply with demand on a daily basis or face penalties. The range
allowed for imbalance is determined by PG&E for each event and may be as low as 0%; the
penalty is also determined by PG&E for each event and maybe as high as 50 per MMBtu.
Table 2 presents the distribution of penalties for non-compliance since 1998 for balancing
events on the PG&E system.
Table 2: PG&E Penalty and City Exposure (no swing gas)
0.10 97 40%
0.25 4 2%
0.50 6 2%
1.00 85 35%
5.00 47 19%
25.00 5 2% ....
Total 244 100%
The penalties less than $1 per MMBtu were imposed during the initial time period that PG&E
implemented the OFO/EFO system. Penalties in the range $1 - $25 have become the norm.
Item 3 GULP Attachment C Page 2 of 8
Staff evaluated the three contracts based on the ability to use storage for various daily balancing
requirements (during OFOs and EFOs). The storage parameters were constrained by the City’s
actual load and the assumption that 100% of the City’s expected monthly load was purchased
prior to the beginning of the month (no more than daily usage less expected usage may be
withdrawn and no more than expected usage less actual usage may be injected.)
Tables 3 through 5 show the daily injection and withdrawal quantities that the City would need
in order to hedge against the daily balancing requirements of a one-in-ten, one-in-twenty, and
one-in-fifty year gas day demand respectively.
Table 3:On-in-50 Years Day Hedging
January 15,764 30,000 3,006 14,236 12,758
February 13,747 27,334 2,504 13,586 11,242
March 1 "1,106 23,249 1,991 12,142 9,114
April 9,213 19,160 1,741 9,947 7,472
May 7,474 15,536 1,435 8,061 6,039
June 6,112 11,334 1,245 5,222 4,867
July 5,722 9,892 1,239 4,170 4,483
August 5,718 9,764 1,272 4,045 4,446
September 5,973 10,426 ‘1,315 4,453 4,658
October 7,224 14,934 1,456 7,710 5,767
November 11,599 23,917 2 05"1 12,318 9,547
December 15,874 29,643 2,934 13,768 12,940
Table 4: One-in-Twenty Day Hedging
January 15,764 ,’20,784 10,812 5,020 4,952
February 13,747 19,431 9,099 5,684 4,648
March 11,106 15,234 7,042 4,128 4,064
April 9,213 13,597 6,328 4,384 2,885
May 7,474 10,180 5,555 2,706 1,919
June 6,112 7,938 4,406 1,826 1,706
July 5,722 6,709 4,790 987 932
August 6,409 6,724 4,838 315 1,571
September 5,973 7,142 5,022 1,169 951
October 7,224 10,440 5,561 3,216 1,663
November 11,599 16,939 7~521 5,340 4,078
December 15,874 20,584 10,637 4,710 5,237
Item 3 GULP Attachment C Page 3 of 8
Table 5: One-in-Ten Day Hedging
January 15,764
February 13,747
March 11,106
April 9,213
May 7,474:
June
July 5 72~
August 5,7i8
September 5,973
October 7,224
November 11,599
December 15,874
19,658 11,979 .......3,894 3,785
17,911 9,980 4,164 3,767
15,234 ........7,935 4,128 3,171
12,555 6,938 3,342 2,275
10,180 5,717 2,706 1,757 ...............
7;427 4’961 1315 115i
6482 4:93i 760 ~85
6,398 :680 649
6,832 5,239 859 734
9,786 5,804 2,562 1,420
15,672 8,174 4,073 3,425
19,424 11,693 3,550 4,181
The values in Tables 3 through 5 were used to determine the parameters of the three contracts
evaluated in this analysis. Contract 3 protects against one-in-ten year daily weather scenario while
Contract 2 protects against a one-in-twenty year daily weather scenario and Contract 1 protects
against a one-in-fifty year daily weather scenario. The one-in-fifty year daily case corresponds to
what PG&E refers to as "Abnormal Peak Day" and may become a future standard if regulatory
mandates require the City to prove gas supply self-reliance. Storage capacity was set to 150,000
MMBtu resulting enough inventory for approximately 10 extremely cold, 30 cold, or 50 slightly
cold consecutive days.
Figure 1 presents the OFOs and EFOs that c0uld be mitigated by a storage contract designed to
accommodate a one:in’twenty gas demand event; as well as the City’s exposure to penalties for
OFOs that could not be mitigated by the storage contract.
Item 3 GULP Attachment C Page 4 of 8
30000
25000
Figure 1: OFOs EFOs and One-in-Twenty Gas Demand Event
¯Load during High OFO ¯Load During Low OFO Expected ~Low High
20000 -
15000
10000
5O0O
Figure 1 shows that the majority of OFO/EFO events would be covered using a storage contract
designed to accommodate 1-in-20 years weather events.
2. Value of Storage Derived From OFO and EFO Mitigation
Staff evaluated the value of OFO/EFO mitigation by examining historical City usage and actual
OFO/EFO occurrence including actual PG&E-declared ranges and penalty magnitude and actual
daily spot prices. When the City complies with an OFO event, gas is purchased or sold at the
prevailing daily market price to balance supply and demand for that day. If storage is used to
mitigate against these daily balancing events, the City would be able to use gas already in storage
instead of being subjected to the daily price on the day of the event.
If the City does not comply with a daily balancing event, the portion of gas out of the PG&E-
defined range will be subjected to penalties. Adding the gas cost avoidance and the penalty
avoidance values results in the total value of storage for OFO/EFO mitigation. Table 6 shows the
total historical value of storage. Given that cost of a storage contract is $200K-$650K, it is
apparent that, historically, storage would not have been a valuable asset to own.
Item 3 GULP Attachment C Page 5 of 8
. Table 6: Historical Value of Storage
Volumetric Value $1,792 $4,533 $2,405 $7,076 $3,952
(Difference between storage gas price
and daily price multiplied by gas
needed on EFO/OFO day)
Penalty Avoidance
(PG&E penalty that would have been
paid had no storage or swing gas been
available
Total OFO/EFO Benefit
$4,281 $22,541 $24,830 $12,645 $16,074
$6,073 $27,074 $27,235 $19,721 $20,026
3. Sensitivity/Stress Testing
However, since history is not always an adequate measure of an asset’s worth, stress testing
was undertaken. Given that PG&E can raise OFO penalties to $50 per MMBtu and given the
extremely high usage the City can experience on a cold winter day, a maximum exposure can
be calculated. Table t0 shows the City’s penalty exposure for two OFO scenarios.
Table 7: One’Day Possible City Exposure to Very High OFO/EFO Penalties
can impose)
25
(Maximum
Penalty that PG&E
has imposed)
4 0%22,000 17,000 $500,000
The first scenario shows that on one extremely cold day at a $50 per MMBtu penalty, the City
could pay $750,000. The second scenario is based on an event with a historical probability of 2%
whereby 4 days of 22,000 MMBtu per day usage occurs. If a penalty of only $25 per MMBtu were
imposed during such weather, the City would pay $500,000 in penalties. From this stress test it is
clear that the City nmst have some safe guard in place to mitigate against OFOs and EFOs.
Taking Advantage of Seasonal Price Differences
1. Methodology and Assumptions
The value of storage when used for taking advantage of seasonal price differences is the ability
to buy gas in less expensive time periods and withdraw it during periods when the price of gas
is higher. Given the City’s laddering strategy, this essentially means that at a given point in
time, the City can buy gas with a plan for withdrawing during a month with a higher forward
price, thus locking in the seasonal benefit.
Item 3 GULP Attachment C Page 6 of 8
The evaluation methodology calculated the value of a one-year gas storage contract using
forward prices. The objective function of the optimization problem is the value of storage as
defined by the revenues from taking advantage of seasonal differences minus the cost of the
contract. Staff used historic data and simulated the injection and withdrawal decisions staff
would have made based on forward contracts to determine the value of each storage contract.
2. Value of Storage Derived from Taking Advantage of Seasonal Price Differences
Table 8 presents the value of the second contract (i.e., 1-in-20 year scenario). The net-value of
storage is calculated for the period April through March, based on forward contracts for 6 and
12-month periods leading up to the 12 month period of the contract. Results are presented at the
99% high, 95% high, 90% high, 50%, and 10% low percentile.
Table 8: Net Value of Storage Contract 1 (1 in 20 year event) Based on Forward Contracts
Period
Analyzed
April 03 to
March 04
April 02 to
March 03
April.01 to
March 02
Percentile 6 Months 12 Months
(Value Distribution)Leading up to Leading up to
Storage Cycle Storage Cycle
Year Year
99%(54,767)(61,041)
95%(77,041)(87,091)
90%(100,098)(114,268)
50%(129,765)(155,216)
10%(182,412)(183,987)
99%158,912 184,361
95%(4,710)(8,300)
90%(21,000)(30,341)
50%(44,426)(52,300)
10%(118,926)(120,318)
99%146,802 196,900
95%23,343 32,981
90%900 I0,050
50%(159,127)(170,090)
10%(217,012)(219,211)
Staff found that the cost of storage is greater than the expected benefit of taking advantage of
seasonal price differences making this an uneconomical use for this asset by itself. The distribution
of storage value shows that in some rare instances (90th percentile or above), taking advantage of
seasonal price differences could offset the cost of storage thereby creating value for the. holder of a
storage contract. Based on historical data, the holder of a gas storage contract such as the one
Item 3 GULP Attachment C Page 7 of 8
specified above, could have realized a profit for some of contract years if all gas was purchased at
the precise time when the forward price curve was such that an op~:imal seasonal price differential
could be captured. A summer/winter price differential of approximately $1.5 per MMBtu makes
storage a valuable asset. Currently that difference is about $0.30 per MMBtu. Since the City uses
a !addering strategy whereby gas is purchased systematically over a period of time and staff does
not attempt to predict the future market, staff concludes that storage has no value for taking
advantage of seasonal price differences and should not be acquired on this basis.
CONCLUSION
Currently, the City does not hold storage but does contract with gas suppliers to guarantee the
supply of gas on a high usage day at a daily price higher than normal and the purchase of surplus
gas on a low usage day at a price lower than nomaal. The City’s current balancing agent and
scheduler, IGS, is able to use these swing contracts to balance the City’s supply and demand. The
cost of these supplier agreements has been significantly less than the cost of a storage contract. If
the City is able to continue to negotiate swing gas deals for less than the cost of storage, and if no
asset acquisition is mandated by the regulators to maintain system reliability, contracting for
storage is not recommended at this time.
Item 3 GULP Attachment C Page 8 of 8
ATTACHMENT D: PIPELINE CAPACITY ACQUISITION
ASSUMPTIONS, ANALYSIS, AND RESULTS
Objective
The objective of this analysis was to determine if the acquisition of additional
pipeline capacity has value to the City.
Background
The City currently has an allocation of Redwood Pipeline Capacity approximately
equal to the City’s base load needs. The Redwood path is PG&E’s large
transmission line that moves Canadian gas to PG&E’s local distribution system. It
originates at the California/Oregon border and terminates at a fictitious point
known as the PG&E Citygate. Palo Alto obtained this capacity at a "vintage" rate
(lower than the tariff rate) as a result of a settlement process called the Gas
Accord. PG&E core customers are also allocated a proportional share of the
Redwood path at vintage rates. The terms of the Gas Accord extend through the
end of 2004. The City captures the value of this capacity when the difference
between fixed-price gas purchased at Malin and the market price at the PG&E
Citygate is greater than the vintage rate. Positive value is provided to the City in
this way nearly all the time.The City does not hold any additional pipeline
capacity
Analysis
Value of Transportation
The value of gas transportation between two points is equal to the difference in the
gas price at those two points. For this analysis, published pipeline tariffs were
compared to estimations of future basis differential. To forecast prices at the
various Western basins and delivery points, historical prices were regressed
against Henry Hub prices.
The first step was to develop a forecast of market gas prices at the NYMEX
trading point, Henry Hub. From January 2004 through December 2005, Henry
Hub prices are equal to the forward prices as of December 8, 2003. From January
2006 through December 2013, the Henry Hub prices are based on the Energy
Institute of America (EIA) forecast of national wellhead prices published in the
2003 Annual Energy Outlook plus $0.32 per MMBtu converted to 2003 dollars. In
a 1980 report, EIA estimated the difference between wellhead prices and the
NYMEX trading price to be approximately $0.32 per MMBtu. Monthly price
factors were developed for NYMEX data.
Prices at the various Western basins and delivery points were calculated by
regressing the historical basin or delivery (border) prices against Henry Hub
prices. The mathematical formula is as follows:
Item 3 GULP Attachment D Page 1 ot"4
Price (at basin or delivery point) =A*NYMEX Price + B
Where:
A is the regression coefficient and
B is the constant or intercept value.
The basin price forecast is shown in Figure 1 below.
Basin Price Forecast (2003 $)
6.00
5.00
.= 4.00
~’- 3.00
~ 2.00
1.00
0.00
Figure 1
The basin price was subtracted from the delivered price to calculate the basis
differential or transportation value, and this value was compared to pipeline tariff
rates. The 2004 pipeline rates include the cost of compressor fuel based on an
input gas price of $4.00 per MMBtu. The historical averages exclude the "crisis
period" from June 2000 through July 2001.
Table 1 provides the results of the analysis. Under normal weather and market
conditions, it is expected that the value of transportation on the major paths will be
less than the full pipeline toll for the path. This is consistent with historical trends
and the outlook that California as a whole will have a surplus of interstate pipeline
capacity for the entire forecast period. We further assume that additional pipeline
capacity will be built to transport either Rocky Mountain or Canadian gas to
northern California during the next 10 years.
Item 3 GULP Attachment D Page 2 of 4
2004 Fuel Total
Pipeline @ Transport Historical
Pipeline Path Toll 1/$4.00/Dth;Cost 1998-2003 2J
AECO-Malin $0.38 $0.13 $0,51 $0.33
Malin-PG&E City Gate $0.30 $0.05 $0.35 $0.25
OpaI-SCG Topock $0.51 $0.12 $0.64 $0.58
San Juan Basin-SCG Topock $0.39 $0.13 $0.51 $0.35PG&E Topock-PG&E CG $0.19 $0.05 $0.24 $0.17
Basis Differential
Forecast (20035)
2004-2008 I 2009-2013 I 2004-2013
$0.18 $0.26.$0,22
$0,18 $0.20 $0.19
$0.48 $0.43 $0.45
$0.34 $0.34 $0.34
$0.13 $0.17 $0.15
11 Toll at 100% toad factor, excluding fuel.
2/Average ex cluding energy crisis (June 2000-J uly 2001 )
3/15-year term on 2003 Expanmon, Comparable toll on pre-expansion syslem is $0.46 per Dth. incl fuel.
Table 1
Uncertainty of Transportation Value
Most pipeline contracts require a long-term commitment, at least 10 years.
However, the value of pipeline capacity can-be extremely uncertain. Figure 2
below shows the historical NYMEX-Malin basis.
Henry Hub-Malin Basis
(marketer quotes)
~1.oo [i! ...........................................................................................................................................April - Oct 04
.i !-’- Nov 03 - Mar:~/-+-April - Oct 03
’1-’-NOV 02- Mar 03
|-.-April - Oct 02
$040
8/1L. 1 111112001 x ~= ,5~112002 ,, 8/1/200~= =, 11/112002 *2/1/200~ ¯5/ ~003 [
date of quote
Figure 2
Figure 2 illustrates that this basis has varied dramatically over the past 3 years and
has even fluctuated between positive and negative values. Should the City want to
lock-in a basis differential, basis is an approved product that may be purchased by
Item 3 GULP Attachment D Page 3 of 4
the City. This type of purchase may be seasonal and for short, medium, or long
terms.
Value of Delivery Point Diversification
The final part of the analysis entailed evaluating the value of diversifying the
City’s delivery points for gas commodity purchases. Staff compared monthly
bidweek gas prices at the Northern California boarder, Malin and the Southern
California border. Figure 3 below illustrates how highly con’elated these prices
are. In fact, the prices are nearly perfectly correlated; therefore, there is no value
to diversifying delivery points.
Malin, SoCal & NYMEX Gas Prices
Bidweek and Colosing NYMEX Price
16
14
12
~o~ ~ ~ o~ c~ c~ ~ o~ ~ ~ o o ~ ~ o o oo~o~ c~ o~ c~ o~ c~ o~ o~ ~ ~ o o o o o o o
Month
Figure 3
Item 3 GULP Attachment D Page 4 of 4
ATTACHMENT E: GAS RESERVES ACQUISITION ASSUMTIONS,
ANALYSIS, AND RESULTS
INTRODUCTION
This document summarizes the major assumptions underlying the wellhead
evaluation model and the results of the analysis, The gas reserves equity model
was developed as part of the Gas Utility Long-Term Plan (GULP).
BACKGROUND
Market research indicates that utilities usually seek equity ownership in gas fields
under a combination of one or several of the following circumstances:
1. Market liquidity relative to market requirement for hedging: markets
may not be adequately liquid or deep to meet risk management requirements.
For example The North American gas market is highly liquid in the period up
to one year but drops off significantly thereafter to a point that the five-year
transactions represent less than 1% of the volume traded compared to a one-
year prompt period. Table 1 presents the open b~terest (the total number of
contracts outstanding) for natural gas futures traded on the New York
Mercantile Exchange (NYMEX) on May 7, 2004.
NYMEX Open Interest ou natural gas futures
Natural Gas Futures Natural Gas Futures
Open Interest Open Interest
Jun-04 69,356 Jun-09 37
Jul-04 45,092 Jul-09 46
Aug-04 26,769 Aug-09 45Sep-04 24,513 Sep-09 36
Oct-04 23,242 Oct-09 2 I
Nov-04 16,812 Nov-09 23
Dec-04 19,494 Dec-09 34
Jan-05 17,927 Jan-l 0 10
Feb-05 12,1’36 Feb- 10 3
Mar-05 14,217 Mar- 10 0
Apr-05 10,837 Apt- 10
May-05 8,633 May- 10
Average Open Interest 24,086 2515
Trading unit = 10,000 MMBTU
Table 1
Table 1 shows that the average open interest for the first year is 24, 086 while
this number drops to 25.5 or less than 1% five years later
o Counterparty risk: Owning gas supply reserves in the portfolio could
reduce the exposure that results fi’om contracting with third parties for long-
term supply.
Item 3 GULP Attachment E Page 1 of 5
MODEL DESCRIPTION
The acquisition of gas reserves requires an initial cash outlay and will produce an
uncertain benefit stream .of avoiding market-priced gas. The gas wellhead equity
model was developed in order to evaluate the net present value of a gas well under
two sources of uncertainty:
1. Market price risk is the risk that value of the asset declines due to a
decline in gas market prices.
2.Asset ownership risk is the risk that the well production volume does not
meet expectations
Cost items included in the model comprise:
Capital costs: Includes initial procurement of land, mineral rights, and
wellhead equipment.
Variable Costs: Includes gathering and processing, production, royalty,
transportation, and administrative.
Transaction costs: Includes inforrnation collection and processing and
legal costs.
Methodology
Using Monte Carlo simulation, staff estimated the cost uncertainty of procuring
30% of Palo Alto’ expected average daily gas demand (3,000 Dth per day) from a
Palo Alto owned gas welt and compared this cost uncertainty to purchasing the
same amount of gas from forward markets in accordance with Palo Alto’s three-
year laddering strategy.
Model Hypothesis:
The gas wellhead model was developed using information provided by the
Sacramento Municipal Utility District (SMUD) which recently acquired equity in
a 55,000-acre coal bed methane gas field comprising 265 producing wells.
SMUD’s field is expected to produce a total of 150 billion cubic feet (BCF) of
natural gas over a 40 to 70 year period. The purchase price for this field located in
the San Juan basin was $135 million.
A range of possible costs was built around the cost figures provided by SMUD to
reflect the uncertainty of those costs. Table 1 summarizes the cost and operational
figures used in the model. The real discount rate was set to 2.5% per annum.
Item 3 GULP Attachment E Page 2 of 5
Depletion Rate
Price Growth (in real terms)
Expected Well Output
Debt Service Cost (initial cost -$1/MMBtu, 30 years,
2.5% real discount rate)
Production Costs
Gathering & Processing
Royalty (market value of 12.5% of production at
production basin; @$2.50 to $3.50 market price)
Production Taxes
Transportation (San Juan basin to Citygate)
Admin & General
Total Cost of Owned Reserves at the PG&E Citygate
0.5% - 3.4% per annum
0.4% per annum
15 Bcf
$ 1.08 $1.66
$0.30 $0.50
$ 0.40 $O.6O
. $ O.3O $O.5O
$ O.35 $O.45
$0.70 $0.80
$ 0.05 $0.1~
Total $ 3.18 $ 4.66
Table 2
Market Prices
The following assumptions were made about market prices:
¯Expected price is $4.50, real term growth of 0.4% per annum. " . .
°Vary between $2.45 (10th percentile) to $8.80 (90th percentile) in year 30.
¯Volatility was estimated to be 15% per annum following a mean reversion
process. Price uncertainty was set to increase as a function of time.
The market price forecasts used are shown in Figure 1.
Market Price Forecasts
+ Low Forecast ~ Base Forecast ForecastHigh
10.00 ......................................................................................................
9,00 4
7.00 4 ......................................................................................................
6.00
5.00
4.00
3.00
2.00
1.00
0.00
Figure 1
Item 3 GULP Attachment E Page 3 of 5
Results of Analysis
,Qualitative
Diversification of risk for the City’s gas
portfolio - replaces market price risk with
production risk resulting in a hedge against
price volatility
!.Potential to utilizg City’s low cost of capital
3,Has the ability to met City’s low and stable
retail rate objective by satisfying a portion of
City’s Iong~ term needs
4.Can use financial instruments to realize a
significant discount to index
5. No credit risk exposure
1.Actual production over the life of the well may
be greater or less than estimatesl Risk may be
reduced by procuring proven producing
reserves.
2.Poor performance of operator of wells or lack of
owner expertise in managing the operator.
3. Daily production/flow from the well can fluctuate,
4. Risk of market price collapse can be hedged in
a fixed-to-floating price swap with a third party.
5. Potential environmental issues mayarise
6. Administrative burden
’7. Large upfront transaction costs
Table 3
Quantitative
Figure 2 compares the market cost variability to the production cost variability.
Even though staff draws no conclusion drawn regarding relative expected price, it
is apparent that market cost uncertainty is greater than production cost uncertainty.
Market Cost Variability_vs. Production Cost Uncertainty
O,/erlay Chart
Frequency Corr~arison
|
Figure 2
Item 3 GULP Attachment E Page 4 of 5
Discount Rate Sensitivity:
The City’s real discount rate (i.e,, corrected for inflation) is assumed to be 2.5%.
While changing this variable would change the overall value of a gas reserves
ifivestment project, it would not change the conclusion that production cost
uncertainty is less than market cost uncertainty.
Item 3 GULP Attachment E Page 5 of 5
ATTACHMENT F: GLOSSARY OF. GAS TERMS
.Associated Gas: A layer of free natural gas, commonly known as "gas cap gas" which
overlies and is in contact with crude oil in a reservoir.
.Available heat: The amount of heat that can be generated from a particular type of fuel
using a particular type of processing
¯ Base gas: The minimum volume of gas required in a storage reservoir in order to
provide enough pressure to cycle the normal working storage volume.
¯ Balancing Agreement: A contractual agreement between two or more legal entities that
accounts for differences between delivered and received volumes.
¯ Bcf : One billion cubic feet of natural gas.
¯ British Thermal Unit (Btu): The energy required to raise the temperature of one pound
of water by one degree Fahrenheit, under standard pressure.
-Capacity: Generally, the total volume that can be contained within a given space.
"City Gate: a location at which gas usually changes ownership, from one party to
another, neither of which is the ultimate consumer.
.Coalbed Methane: A methane-rich, sulfur-free natural gas contained within
underground coal beds.
¯ Completed Well: A well that is producing or that has been drilled to sufficient depth to
conclude that it is a dry hole.
¯ Dekatherm (Dth): A thermal unit of energy equal to 1 MMBtu.
¯ Delivery Point: A point at Which gas leaves a transporter’s system completing a sale or
transportation service transaction between the transporter company and a sale of
transportation service customer.
¯ Demand Charge: An amount paid by a customer based upon that customer’s right to
"demand" a contracted level of service.
-Firm: Continuous except during force majeure situations.
"Gas Field: A district or area from which natural gas is produced.
¯ Gas Plant: Any plant which performs one of the following functions: removing
liquefiable hydrocarbons from wet gas (gas processing); removing undesirable gaseous
and particulate elements from natural gas (gas treatment); removing water or moisture
from the gas stream (dehydration).
Item 3 GULP Attachement F Page 1 of 2
¯ Gas Reserves: The volume of natural gas that has been estimated by geologists to exist
is known underground formations.
¯ Gathering System: A series of pies connecting one or more natural gas wells which is
used to deliver gas into a mainline transmission system.
¯ Hydrocarbon’ A chemical compound composed solely of carbon and hydrogen.
"Liquefied Natural Gas (LNG): Natural gas which has been liquefied by reducing its
temperature to -260 degrees F at atmospheric pressure.
¯ Load profile: Pattern of a customer’s gas usage, hour to hour, day to day, or lnonth to
month.
¯Market Price: The price at which natura! gas is purchased and sold on the open market.
¯Mef: 1,000 cubic feet.
¯ Methane (CH4): The chief constituent of natural gas. Pure methane has a heating value
of 1012 Btu per cubic foot.
¯ Natural Gas: a naturally occun-ing mixtur~ of hydrocarbon and nonhydrocarbon gases,
including methane, ethane, butane and propane.
¯ Producing Well: A well that produces oil and/or natural gas in profitable quantities.
¯ Reserves, Energy:
1. Estimated potential Natural Gas Reserves - The quantity for a specified area
which is not presently proved or recoverable.
2. Estimated Probable Natural Gas Reserves - An estimated quantity.
3. Estimated Proved Recoverable Natural Gas Reserves - An estimated quantity
for a reservoir that has demonstrated the ability to produce by wither actual
production or a conclusive formation test.
¯ Reservoir: A subsurface, porous, .pemaeable rock formation containing an accumulation
of natural gas, crude oil to a producing reservoir, or both...
¯ Shut-in: Refers to a well, plant, or pump, in which valves are closed at both inlet and
outlet and gas or oil does not flow.
"Worldng Interest: The interest in an oil or gas lease that entitles the owner to the
production from the property.
Item 3 GULP Attachement F Page 2 Of 2
Final GULP Recommendations
Utilities Advisory Commission
June 2, 2004
Presentation Outline
Staff’s request
Time Line
Recommendations highlighting
changes from preliminary
recommendations
o Next Steps
Staff s Request ..
Staff requests that the UAC
recommend City Council approval
of the six GULP recommendations.
(UAC had no changes to preliminary
recommendations)
I1. A~oproval of enerqy Risk Management Policies
12, AdoptIoI1 of gas commodity leddedeg strategy
3, Approval of DSM & Public Benelits Plan
4. Approval of planninglobjectlves and gutdlelnes
5. Revise Gas Leddering Strategy
6. Preliminary GULP Recommendations
17. Final GULP
Ig. Implementation
Icouncil approval ofdsk management poli~fes 2/20/2001 (CMR:i30.01)
Revised i0/oti02 (CMR:39g,02)
Ilnl’ormatlo n reporl to Finance Committee April 20oi (CMR:lgg:of }
ICounci~ approval : i 2/3/0i; (CMR:421:01)
UAC approved June 2003
C0ungii approved August 4, 2003 (CMR:355 03)
IPresented to UAC Janua~ 14, 2004
Information Report to Council March 15.2004 (CMR:I67:04)
~Presented to UAC - February 2004
ITo UAC June 2004
TO Council- Ju~y 2004
lStartlng Summer 2004
Recommendations
1. Do not contract for natural gas storage capacity at this time.
2. Do not acquire additional natural gas pipeline capacity at this time.
Recommendations Continued
3,Approve staff undertaking initial steps related to gas reserve aeqnisition
including;
a) Identifying and evaluating potential consortiums
including joint action opportunities;
b) Entering into consortium agreement to scout properties;
c) Through the consortium, employing an investment bank
and consultants to scout properties and spend up to
$65,000 in FY 04-05 related to this effort; and
d) Through the consortium, identifying attractive, feasible
opportunities.
Recommendations Continued
st-~ctur~ and cr~dR
4. Do not participate in a gas prepay deal at this time.
5.Pursue any low,cost, high-value prospects to acquire supply-related
resources that may arise from time to time.
Recommendations Continued
use tcclmclcgie:.
6. DeVelop eomprd~ensive deniand~side management goals anB implenientation
plan b~ Fall ~004 in time for incorporation into ~05-06 and ~uture
ratemakiug and budget decisions. In the interim~ continue implementation
of current and planneB FY 04-05 demanB-side management programs.
4
::"-,~1~ Next Steps
" "
[]Request Council approval
Implementation immediate following
UTILITIES ADVISORY. COMMISSION
MEETING MINUTES JUNE 2, 2004
ROLL CALL
Commissioner Rosenbaum called the meeting to order at 7:03 p.m. in the Chambers, 250
Hamilton Avenue, Palo Alto, California.
Present:Dick Rosenbaum, Elizabeth Dahlen, George Bechtel, and John Melton
Absent:Dexter Dawes, Mayor Beecham
ORAL COMMUNICATIONS
None
III,
IV.
APPROVAL OF MINUTES
Motion:Commissioner Bechtel moved that the minutes from May 5, 2004 be approved
as written with a second from John Melton.
Motion Passed: 4-0
AGENDA REVIEW AND REVISIONS
No changes to agenda.
REPORTS FROM COMMISSIONER MEETINGS/EVENTS
None
VI.DIRECTOR OF UTILITIES REPORT
John Ulrich shared that Dee Zichowic will be preparing sense minutes from the meeting
tonight. The intention is to move away from verbatim minutes in the future. We will keep
copies of both the video and audio. Hopefully, this will be more productive and result in a
cost saving. John asked for feedback from UAC.
Ulrich mentioned tours or trips and reported Mayor Beecham participated at the NCPA
congressional staff tour over Memorial Day weekend. John shared the event was very
well attended by key senator and representative districts and states. The new generation
facilities tours included tours of Turiock Irrigation, New Don Pedro Dam and Reservoir,
Silicon Valley Power new power plant and travel extensively around the territory. John
and Don Dame met the group in the East Bay at the end of the tour, gave insight about
uniqueness of Palo Alto, MDO2, and Iocational marginal pricing. It was put together very
well. it was Important-having key staff members meet with Senator Feinstein’s staff..
Ulrich shared upcoming Council events including June 7th Council- expect resolution
confirming prior contribution 2005 - 06, operations for CVP project which gives authority
to the City Manager to execute the agreement.
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 1 of 16
Second reading of ordnance authorize WAPA Custom Product contract. First reading
was May 10th, and passed 8-0 with Mayor being absent.
.There was information regarding the ISO in the newspaper stating Terry Winter, CEO;
resigned from his position, as well as the Vice-President of Corporate & Strategic
Development. This surprised everyone and there has not been much discussion on the
topic. The past CEO from 1997-99 is in place - Jeff Trend. He will take the position on
an interim basis. Expectations are that it will take up to 6 months to permanently fill the
position.
George Bechtel noticed UtilitiEs is hosting meetings to explain the City’s undergrounding
policy, on the local channel and asked for some background information.
Ulrich will get dates and times of the viewings. The purpose of this video is to explain
how the underground district works. For example, district number 38 has had a
significant amount of questions surrounding the project. We would like to give people an
idea of what we’re doing. We also plan to have some meetings withthe goal to provide
increased communications to the public.
VII.UNFINISHED BUSINESS
Utilities Quarterly (May 6, 2004 Mtg)
Ulrich shared we had agreed to supply quarterly reports which in the past had
individually reported. At the request of the UAC we now bundle them together and
the result is the Quarterly Reports. Due to agenda items at the last meeting, we
moved this .forward for questions and answers for the meeting tonight., We
presented this information on the Utilities web site and at the main library. Our goal
was to give everyone an opportunity to review and use tonight to ask questions, if
any.
Rosenbaum asked if there were any questions.
Elizabeth Dahlen questioned item 2 and the use of chloramines; will this be a ballot
measure in November and how does that affect us?
Jane Ratchye answered there has been some resistance to the use of
chloramines, including letters to the editor in local papers expressing serious
opposition. Yesterday’s Examiner front page story told of a woman in Menlo Park
claiming to have a very serious allergic reaction with medical back up and
attorneys who will take action against SFPUC. Most questions have been directed
to SFPUC, who came to the BAWSCA board meeting and they said they want to
take responsibility since it is their issue. ,They have offered to pass information on
to us. There is nothing we can do individually.
Dahlen asked if this will be on our ballot.
Ratchye stated no for our ballot but there have been many questions at council
meetings in Millbrae. Jane hasn’t heard of any activity in Palo Alto to put on ballot.
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 2 of 16
Dahlen questioned what they’re putting on ballot, the question do they want
chloramine?
Ratchye stated yes but she didn’t know what effect they can have and is not sure
what they want to do.
Melton asked about the SFPUC new director, wondered what our take on the new
person is and what impact, positive or negative, that might have on Hetch Hetchy.
Ratchye stated that SFPUC’s new director Susan Leal, just took position
yesterday. Since Leal is politically connected in SF and it will take political
resources, it could be beneficial. The chairman of BAWSCA wrote.a letter to
Mayor Newsome asking for a meeting and expressing his expectation that a
change in leadership not affect any project schedules. Leal has no water
management experience at all, but has financial experience and is an elected
official, City Treasurer.
Bechtel asked about SFPUC issues, specifically the, part of the report that
interested him was that BAWSCA is monitoring the SFPUC CIP project process
and have developed a method of showing progress, are we sharing this information
and are they receiving gracefully?
Ratchye agreed that we have shared information with San Francisco, BAWSCA’s
consultant is there at any project meeting he wants to go to. Brown and Caldwell
has made many recommendations and they have considered and SFPUC has
followed some of .them. They take his recommendations very seriously. The
BAWSCA board could take action if they disregarded Brown and Caldwell.
Bechtel’s second question referred to the SFPUC rehabilitated pipelines
replacement costs being higher in the ClP than they thought. He wanted to know if
there is any information on projected costs.
Ratchye hasn’t seen any numbers yet so can’t help with that question.. In a couple
of weeks at another meeting, we will expect to hear more from San Francisco. San
Francisco may be proposing schedule changes at that meeting.
Bechtel: Cost’ wise and time wise changes:
Rosenbaum moved on to gas and asked for questions. No questions except he
received a call from a gentleman who thought it was dumb to build a gas fired
generation plant since natural gas would run out before the end of the usefulness
of the plant.
Ulrich hadn’t heard of anyone asking that. At another meeting, someone asked
how prudent it is to consider using natural gas but not in terms of gas running out
but rather if this a smart type of fuel to use for a power plant. We recognize if you
look at the energy policy of the U.S,, that report said using natural has was not the
proper fuel, they moved on to talk about using coal. Coal is not viable for
California. Our analysis will take that into account; will also include the risk side for
what the cost of natural gas will be.
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 3 of 16
Balachandran stated he has never heard anything about it running out.
Rosenbaum mentioned that one of the other comments has to do with liquefied
natural gas and difficulties companies have had in trying to site LNG plants
because of the concerns about terrorism and other things and the possible impact
this might have if indeed it might prove difficult to import as much LNG as people
were contemplating importing.
Ulrich said a recent article in the Wall Street Journal last week stated that there
were a number of places proposed Mexico and the East Coast and down in
Louisiana and I believe there is a high level of concern of terrorism and how
prudent to put in. John thinks it is a much bigger matter since the price of oil has
gone to an all-time record high. We’re talking about a $15 per barrel price built in
as part of the fear factor of what could happen in the Middle East to our supply.
We’re already seeing this happen .in our prices. As oil prices go up, you’re going to
see this happen to natural gas prices in lock step except to those that have
contracts.
Bechtel asked on chart gas meter exchanges. Long term plan monitoring. Two
questions asked were do we have to do, do we do when providing new service,
change out gas lines, and are we thinking about the future when we might have
AMR meter, reading? Are new meters adaptable?
Bradshaw said we db think about doing this but we are not doing now. We are
changing because meters tend to wear out every 10, 12, 15 years and we change
to ensure accuracy. We target that number to keep a constant rotation to
completely cycle through our system every 8-10 years.
Bechtel agreed that we do spend a fair amount on changing out our meters and
thanked Scott for explaining the process.
Ulrich added that it’s necessary to obtaining accurate meter readings to ensure we
are billing our customers accurately..
Rosenbaum asked for questions on the electric quarterly report.
Melton asked about Item 2, the regulatory issues update. The FERC items are
both big,ticket items. We expect a ruling on May 6 and would like an update on the
back charge issue.
Balachandran stated that PG&E can actually bill us and we will be required to pay.
We are in the process of determining if PG&E is billing us the correct amount. If
too much, we’ll get refunds. Our attorneys In D.C. are preparing for the second
phase and expect .the decision from May by next week. Will be more that $8
million. Girish explained that PG&E is expected to back-bill and will also add
interest. This continued exposure will carry on to the end of this year.
Melton asked for an update on the FERC transmission cost dispute,
UAC Minutes of June 2, 2004 Final- Approved 7/7/04 Page 4 of 16
Balachandran expressed that the ruling came out and we’re not happy with it. Both
Western & FERC have filed comments to the Commission stating that DOE ruling
was made in error. Both cases are similar and will take about same time frame.
Trying to consolidate and keep eyes on both. NCPA is charged by load, Western
gets credits, we need to ensure no double accounting; if we pay for Western on the
load side we need to make sure we get offsetting revenue on the other side. Two
different judges will handle these cases. Money has not been accounted for at this
time.
Ulrich took this opportunity to repeat that one of the reasons for having the
reserves levels up is to try to have enough money to take care of contingencies like
this.
Rosenbaum stated that the reserves contain $10 million for this very type of
contingency.
Balachandran said that while contingency risks were known and put aside it is only
a fraction of the total bill from PG&E, we did not plan on this amount. One line item
is for legislative and regulatory contingencies. Did not budget for this
Rosenbaum repeated that there is money in the reserves,
Balachandran said the money will be drawn down to pay bills.
Dahlen questioned the feasibility study and status of the power plant.
Balachandran is assembling staff teams and looking at different consultants to hell~
but there is really nothing to report in results at this point. Public communication
and participation are key at this point. Karl Knapp will be the Project Manager.
Dahlen asked for the status of what they will be looking into?
-Ulrich stated that will be a decision of City Council.
Melton shared information about an information conversation he had with a council
member who asked why we are so focused on gas-fired plants. Specifically, why
are we not looking at photo voltaic on a broad citywide scale? Why not put a
panel on every roof of the city. John didn’t have an answer for the Councilmember.
Ulrich stated that a Councilmember did ask about this atthe Council meeting
where we voted on the proposal. Part of the reason is cost and, if you look at long
term energy plan, we’re trying to spread risk out and spread supply out into various
areas. This is one component of it. We think it is a prudent addition, assuming a
power plant is an appropriate resource to have in Palo Alto.
Knapp stated that we are not ignoring photovoltaic, we have a $3 million project
going on right now to install on public facilities. These. cost 5-6 times what
conventional generation provides. He assured the Commission that photo voltaic,
is indeed, part of our portfolio.
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 5 of 16
Ulrich stated we are being aggressive but not in photovoltaic, considering the cost
versus benefit. Moving ahead will have renewables up to 20% by 2015. John
shared we will go through details since staff wants the Commission to be
comfortable with the decision.
GB acknowledged that this question will come up again, We will be completely
prepared to answer. Information will be on the web site, FAQs for the public, entire
process.
Rosenbaum asked for questions on the fiber report. No questions asked.
Question on rates? None
Bechtel questioned the coordination of the utilities departments in public projects.
He did not mean to deal with the issue tonight but wanted to mention that the
Utilities had just completed a major rework of underground Utilities work in his
neighborhood. He noticed streets get repaired along the route of the pipes but
there still remain a lot of defects in our streets. George expressed his concern that
Utilities and Public Works could better, coordinate work that needs to be completed.
Mr. Bechtel encouraged staff to look at the street improvement plan along with the
Utilities improvement plan. He estimated there could be a possible saving of 20%
by doing so.
Bradshaw acknowledged that George had an interesting comment. He shared that
the Utilities Department works very closely with Public Works on our projects,
meeting quarterly and have developed both 5 and 10-year plans that are being
worked on. Coordination efforts make it hard to do all at once but Utilities tries to .
get in ahead of Public Works on their street improvement programs. One problem
is that they want to do an entire street at once, curb-to-curb so when they leave it
doesn’t look patched and spotted. The goal is to be out of there for the long-term
life of that pavement. We’ve made a commitment not to go back into it for at least
five years. Working very closely with administration of the projects to make sure
our staff work together very closely on these projects.Scott advised the
Commissioners that they should expect to see major results.
Bechtel stated that he was talking about nuisance things. He mentioned that it
would seem a City contractor (sewer for example) could take care of a lot of the
issues if someone authorized the work and he thought people would be happy with
that. Mr. Bechtel encouraged the City to not try to be perfect but do what’s just
good enough.
Bradshaw cautioned that when talking about general funds, each Utilities has their
own fund and we must be very careful of how to do work between the funds.
Ulrich said that Utilities and Public Works spend a lot of time coordinating our
projects and we think we are doing a wonderful job of coordination. He asked the
Commission to give. specifics if they know of a lack of coordination on our part.
Trench fees used by the General Fund for use of our effort be the least amount of
money, cutting fee is on graduated scale. After we do our work, we do not expect
Public Works, if they have two more years of useful life on that street, to go out and
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 6 of 16
do more work on the street. The City is not doing a very good job of having a
contractor who is doing work for city, stop and fix something they see. We don’t
give them many options to do this on their own volition. John asked for a directive
to this specifically if the Commissioners feel this is an area we need to improve, as
we’d be happy to look at the possibilities. People of Palo Alto are paying for this
work and any suggestions that are offered will be considered.
Bechtel stated he was hoping to continue to figure interventive ways of doing
double duty when contractors are doing business on our streets.
Energy Risk Management 3rd Quarter Report (May 6, 2004 Mtg)
Ulrich had Karl Van Orsdol join him at the front table. Rosenbaum asked for
questions on the Energy Risk Management Third Quarter Report. He stated that
page 2 of 9 had a nice chart showing electric purchases going up. He said he has
never seen what we paid for those contracts. He mentioned that the Commission
was told a couple of years ago what we paid for the Coral contract. How about
Duke and Sempra?
Van Orsdol directed the Commissioners-to look at Attachment A where there are
transactions out through October 06 for purchases from Sempra and Coral
according to month. To date, he has not listed overall fixed price as a lump sum.
Rosenbaum thought they were all gaspurchases.
Van Orsdol agreed, as he hasn’t put figures together for electricity. Have not listed
in this detai as yet, only begun to put transactions in database. Karl promised to
have in-depth detail in next Quarterly Report.
Rosenbaum asked for the figures.
Balachandran stated that it varies from 5.1 to 5.5 cents.
Rosenbaum would like to see these figures routinely listed starting with the next
report.
VIII.NEW BUSINESS
1.Water IRP Recommendations (Information)
Ulrich stated that Jane Ratchye was here to discuss and go through the guidelines
shown in the appendix.
Ratchye recalled that earlier we had made recommendations that we have
sufficient San Francisco water in all drought years, don’t need another supply for
normal years and don’t need to connect to the Santa Clara Valley Water District.
She cautioned that it is advisable to look more deeply into demand side measures
and recycled water, Main undone thing is to determine if we want to use wells in
drought and, if so, what level of water quality treatment do we want. This remains
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 7 of16
an open question, but Jane stated she has some new recommendations at this
time.
CPAU’s CIP is currently undergoing the environmental review process. We have
to wait until that process is complete to find the best place for any wells and/or
reservoir. Jane cannot make a recommendation in advance of the completion of
the environmental review process. Cost remains unknown. We do know that a
well and reservoir at El Camino Park would be cheapest by far for using
groundwater for drought. In addition, Jane does not recommend using reverse
osmosis for treatment of the grour~dwater. She stated the best way to treat the
groundwater is to mix it with San Francisco water and that the closer you are from
a SFPUC turnout, the less expensive it ~s.
In the last drought of 1988-1992, wells were used as a supplemental supply, but
that the water was introduced directly into the distribution system near the wells.
This system affected the people living closest to the wells. In addition, since water
.was introduced into the system in a different direction than normal water flows,
sediment was stirred up from the bottom of the pipes that got mixed into the water.
Therefore, many people associate using groundwater with very bad quality.
Jane thinks that a mix of three-parts San Francisco water to one-part well water
would be more acceptable to the community, especially if it were mixed in at a
turnout so that the quality would be more uniform in the community.
Jane repeated that her new recommendation is to not go with reverse osmosis as it
is extremely expensive. We would be paying a large cost to just sit there and when
you do use it, we would be paying a very high operation cost.
Having lived through last drought in 80’s, Melton mentioned that we were able to
do a terrific job on the demand management side. He mentioned that looking at
the results of the poll, there seems to be strong support for no well water. Is it
possible for the City to go through a drought similar to the 80’s with ’just
conservation?’
Ratchye replied that it is possible and in 1987 the community was able to cutback
usage substantially. Our usage has never recovered to pre-drought levels. Asking
people to cut back such a large amount now is different. It would be much more
difficult at this point in time make those cutbacks. San Francisco has changed the
way they run the system; when in 1988, it needed a 25% cutback, under the same
hydrologic conditions, it would probably need only be a 20% cutback. We still
could face a very serious drought with cutbacks of more than 20%. Not using wells
in time of drought will be something we look aL Jane did not make a
recommendation at this point. Cost will be a factor, If very cheap, the community
may want to do it; while some may not want to do at all. When it becomes more
and more expensive, people may want to cut back rather than extend a pipeline
from a turnout to a well. We will have to look at the alternative of not using it.
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 8 of 16
Bechtel asked to be reminded of timeline of making decision.
Ulrich stated this moves over to infrastructure side, which has been extended
longer than he’d like. He reminded the commissioners that we must go through the
EIR process, which is longer than we expected. It will probably be mid-2005 before
the final EIR is completed and actual siting of where the reservoir will go will be
made at that time and we can get started.
Dahlen asked about the recommendation to participate in the deve.opment of long-
term drought supplies with SFPUC and BAWSCA.
Ratchye was referring to jointly purchasing water in dry years rather than severity
of drought. Any agency that wished to participate in purchasing agreement could
participate. San Francisco has always claimed they are working on these issues
but we have never seen any results at all. Jane stated she doesn’t believe they
have any incentive to work on the problem. BAWSCA now has authority to bring
this issue to the forefront. We could do it independently. There are many sources
of water, including Modesto and Turlock Irrigation Districts, with whom we could
make some arrangement or exchange., Since they use Tuolumne River water, that
would be easiest and the best quality. It is also possible to get water stored
underground and pumped out for us in a dry year. We’ll look at these things at
BAWSCA.
Dahten stated that is sounded exciting and pooling efforts sounds very promising.
¯ She questioned how this would impact Palo Alto activities and would it truly
become option for drought supply?
Ratchye stated that this topic is not high on BAWSCA’s agenda at this time. Tile
CIP progress and negotiation of a water service contract will be their main focus in
04/05. But, Jane said, the issue is always there. She thought it could be worked
out to address these issues in new contract. For example, to work to actually
negotiate with farmers, there are no resources in 04/05 budget. We need to
continue to push and this is an excellent opportunity to work on. Wouldn’t have to
plan for droughts as much.
Dahlen asked if other BAWSCA communities are also pursuing their options into
looking at their own supplies.
Ratchye assured the Commission that many communities are looking at
alternatives. Redwood City is very aggressively pursuing recycled water and other
communities are also looking at that option. As far as drought planning, all
communities .have to complete an Urban Water Management Plan every five years
and the next is due to the State in 2005, BAWSCA facilitated a more regional
approach to looking at opportunities. They have a regional look to get the most
cost-effective project done in the region. She also noted that the Interim Water
Shortage Allocation Plan has a mechanism to trade water in case of drought, but
that this feature ends when the current contract ends in mid 2009.
UAC Minutes of June 2, 2004 Final- Approved 7/’//04 Page 9 of 16
Rosenbaum asked if this idea of blending groundwater with San Francisco by
piping into turnout is a new concept?
Ratchye said no, Carollo looked at this in the 2000 study wheq they looked at a
number of options. Reverse osmosis, treatment for Manganese and Iron at well
sites, blend at turnout. The report noted that treating for Mn and Fe at well sites
still did not meet TDS guidelines, but that blending does. The report included cost
estimates for each option at each of our well sites and possible future well sites.
Rosenbaum stated that this makes the use of groundwater more attractive than
putting into use at the well. He praised this very sensible report and stated he will
look forward to the next iteration.
Ulrich mentioned that with the options for Roth Park, increased cost would be
piping back to turnout at Lytton so we could do that blending.
¯Short-term electric laddering strategy (Information)
Ulrich remarked that we are at the very end of 40-year contract with Western. The
LEAP with Risk Management Policies and Guidelines take care of longer and
medium range, now we need to address guidelines and implementation from 0-35
months providing forecasts to make sure we are not purchasing more when we
have a load. This is a very complex issue.
Girish Balachandran stated that with STEAM, we have a 3-year window and will set
a minimum and maximum of how we buy gas. This will be similar to what Council
has approved for guidelines. We figure how to purchase power in a 3-year time
frame. City Manager has the authority to purchase and has delegated authority to
John. John approves strategy minimum and maximum month by month. Karl
Knapp and Shiva Swaminathin both worked on developing the strategy,
Rosenbaum asked about the numerators and denominators percent from Western
and Calaveras.. Our chart average hydro year, shows we expect 550 giga-watt hrs
but pie chart percentages suggest about 45% of energy from those two sources,
looks like closer to 55%. What is difference?
Karl Knapp stated this must be a graphic distortion; the figures in the pie chart are
the actual numbers. Karl promised to check the figures.
Bechtel asked if we want to have a short end view of where energy coming from for
the year and asked staff to look at the pie chart on page 7, figure 5.
Knapp stated about 45% comes from Western and Calaveras.
Bechtel asked if in the pie chart, to translate, if he wanted to see how it looks
during the year, he’d look at monthly graph.
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Knapp stated the pie chart only shows annual hydro variability, Chart in Fig 8
shows how much difference there can be from one wet year to another, is the
monthly pattei’ns are completely different, part of where seasonal variability comes
in, to try to have enough for peak load.
Bechtel mentioned that there is quite a bit of variation and it is difficult to follow. On
3-year program, we’re likely to see .... an effect on seasonality on hydro as we look
forward three years out and we have a dry year we’re in trouble because that’s
where we’re purchasing less. Wondering in contrast to gas, is the same timeframe
still the right one or should we be looking at a different time span for laddering?
Girish Balachandran said this is a rolling 3-year ladder and he believes it is a right
time span. We buy based on the actual forecast. If we see 3-year ladder is not
suitable, we’ll return to the UAC and Council and ask for a change. We believe it is
appropriate at this time.
Bechtel agreed that he hopes we are right and asked if from a market point of view,
does the market match up with our ability to buy with this marketing strategy?
Balachandran said with a power plant in place, it may be fixed. We are also
looking at gas tolling options and may propose a contract outside of the 3-year
window. Whatever resources we put in place, resources are variable so we need
some type of guidelines.
Knapp stated that staff doesn’t approve, this would be approved by council. We
would come back to the Commissioners and Council for the decision.
Bechtel wondered if this added too many levels of complexities to purchasing.
Balachandran stated that staff will soon bring wind and gas coming to the
Commission, 25-30 year deals. Our supply portfolio will change significantly. It is
not possible to predict and it is getting more complex. We weren’t exposed to this
level of vulnerability before.
Bechtel asked if the strategy had been reviewed with risk management.
Balachandran said Utilities has run through an independent risk overview. Future
repots will give all purchases we make in a similar format. These will be presented
to the UAC and Council on a quarterly basis.
Bechtel remarked that this sounds good.
Dahlen asked how the minimum and maximum targets were set and then the
projected load. How do you set the minimum and maximum guidelines?
Knapp summarized the combination of looking at the actual deviation, what year
verses normal, deviation in actual load forecast and forecast already done for
GULP, such as laddering versus dollar cost averaging strategies. The 20%
number is primarily derived from the first six months of the year. In a wet year, you
UAC Mfl~utes of June 2, 2004 Final - Approved 7/7/04 Page 11 of
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haven’t taken on a lot of market risk and in a dry year you don’t have to buy so
much.
Dahlen asked when will we do an analysis doing some months prior to forecast?
Not set up in advance based on actual ...
Knapp replied that will be based on what ends up to your financial reserves.
Dahlen questioned when does projected load become part of that analysis.
Knapp stated that you take projected load, since Palo Alto’s loads are actually
pretty flat during year.
Dahlen said we would shoot to have the projected load in the middle of minimum -
maximum?
Knapp replied yes.
Rosenbaum asked about capacity. We were supposed to have between 15-17%
capacity reserve, do we buy and where does it come from?
Balachandran asked the Commission to look at chart figure 10, you’ll see that in
several months we had adequate capacity. Also in figure 4; January 2006; before
we get to January 06 we will be buying energy. Energy cqmes with capacity. If we
need to buy to meet 15-17% reserve requirements we can buy from the market. In
the past, when we had an inter-connection agreement with PG&E, we used to buy
capacity in the power pool. For example, we had a. contract with Washington
Water Power to buy capacity. We can enter into contract buying combustion
turban capacity (CT) paying a fixed price for the capacity with a strike price that you
determine before hand and if you ever need to call on that, you call on it. The
whole purpose is to maintain system reliability, we used to have this, it’s not just
Palo Alto but the whole country had it. In 1998 when we had the new market
system, it went to the fewer energy pay system. Now this is being re-introduced
so we have adequate reliability.. So if one or more large units go off-line there is
enough capacity to keep the system up and all this capacity gets shared by the
whole system.
Rosenbaum asked if there really is not a cost to us? ,
Balachandran said yes, there is a cost. During the energy crises there was a cost
to us. The cost ended up being several blackouts. On a physical basis we didn’t
have enough energy committed and the system operator did not have control of it.
The cost to us may be more dollars. The benefit now will be greater reliability.
IX.Gas Utility Long-Term Plan (GULP) Recommendation (Action)
Girish Balachandran announced Karla, Bernard, and Shiva worked on this
presentation. They will go through the change from the last recommendations
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 12 of
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made to the Commission. Since then they have completed more analysis. Girish
handed it over to Karla.
Karla Daily began the presentation stating that the preliminary recommendation
was made to the UAC in February. This presentation will include staff’s request,
time line, recommendations highlighting changes from the preliminary
recommendations and end with suggested next steps.
Staff is requesting that the UAC recommend~ that City Council approve these six
GULP recommendations. If the UAC does recommend approval, we will take this
to Council in July and start implementing as soon as approved by Council.
The first two recommendations are identical to what you saw in February. Do not
contract for natural gas storage capacity at this time and do not acquire additional
natural gas pipeline at this time.
The third recommehdation is in sprit not changed but is reworded. For the gas
reserve acquisition part of GULP staff is asking that we can move forward to the
extent that we identified. We have reworded the gas reserve acquisition part of
GULP. We still are asking if the required reserve would be attractive to Pal0 Alto it
would have to be part of a consortium. We are asking that staff be allowed to
move ahead to identify a consortium and if we do find such a consortium, we could
spend up to $65,000 in consultants to look for properties. This is not to say
approvin’ !his recommendation approves in any way acquiring a reserve. This is
just a stei:., ~.o take towards studying it further. This is a very preliminary step. We
feel like this resource has enough potential, we’re not in a position to eliminate it
from possibilities yet. The gas pre-pay deal, when we brought recommendation to
you in February we proposed further investigation of gas pre-pays. Since that time,
we’ve come to the conclusion that this doesn’t make sense for us right now.
Possibly at some time in the future, it may become more attractive for us. We’ve
changed the recommendation to not participate in a gas pre:paid deal at this time.
We’ve added a new measure recommendation: pursue any low-cost high-value
prospects resources that may arise from time to time.
The last recommendation is for demand side management. The spirit of the
recommendation has not changed, just the wording. There is some discomfort
with having a goal of spending a certain amount of money as opposed to having a
goal of making good decisions and coming up with reasonable management goals
and an implementation plan. The recommendation was reworded that hopefully
has more meaning and something that could be followed better than what was
previously written.
Rosenbaum asked for questions.
Dahlen questioned on page 3 of 19, point 91 How did you come up with that
percentage and isn’t that high?
Dailey replied that the figure probably is high. Our base load in the summer is
about 5,000 MMBtu per day and our average annual load is about 10,000 a day.
UAC Minutes of June 2, 2004 Final - Approved 7/7/04 Page 13 of
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X=
Given that production is a fairly steady resource, we would need to take it,every
day of the year and wouldn’t want it to be more than our base load which would be
50%. Karla didn’t believe we would actually look at anything that big.
Dahlen asked if Karla thought it would be realistic to secure that much?
Dailey said yes, definitely, but She is not sure Palo Alto would want to.
Dahlen asked for Karla to give a more realistic percentage,
Daily replied that her gut-feeling range would be 20-30% but quickly stated that
figure might not be agreed on by everyone at the table.
Ulrich confirmed that staff will do an in-depth review of this information.
Melton asked on Item 3 he was wondering why we would limit to U.S. producing
regions as opposed to any North American?.
Daily asked on shore to off shore?
Melton inquired why isn’t Canada there as a possibility?
Dailey stated they wouldn’t have the tax exempt status which would make that
option less attractive to us. The GULP recommendations would apply to any.
project. Staff is not asking Council to officially stamp these criteria. We would
retain an opportunity if any project fell outside of these criteria and we could still
move forward if we had reason to. U.S. production makes much more sense. Off-
shore is very risky.
MOTION: Bechtel moved to accept the staff recommendation that Council approve
.6 GULP recommendations listed on page 1 of the staff report.
Dahlen seconded.
Rosenbaum commended our look at the options.
Motion Passed: 4-0
Ulrich thanked everyone.
Public Health Goals for Drinking Water (Information)
Scott Bradshaw stated that he had no presentation but was here to answer
questions on how we are prepared for goals set by the California Health and
Safety. He asked for any questions regarding the report.
Bechtel mentioned that the report says there were times we didn’t meet certain
standards or guidelines or so on but he didn’t see any discussion of when or
where. The table on A-5 didn’t follow that well. Mr. Bechtel asked for an
explanation if we didn’t meet certain things.
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Ulrich shared we worked on this quite extensively to try to make it clear. The word
’exceed’ is good and sometimes the word is not good. In layman’s terms, there
are public health goals adopted by the California EPA and then there are
maximum contaminant goals (MCLGs) which are adopted by the U.S.
Environmental Protection Agency. These PHGs and MCLGs are not enforceable
standards and no actions to meet them are mandated. They are attempting to
show a goal, similar to our goals for safety goals which is no accidents and no
injuries is where you want to be but to get there is extremely difficult. In some
cases, we deliver what we get. It’s important to be able to report information in the
report that goes out to our customers annually. Every three years, we need to
make this more detailed report about these PHGs and MCLGs so you can see we
are trying to get down to the goals and to report where there is a discrepancy
between meeting those goals and where we’ve not been successful in fluoride and
chloroform to meet all the standards for each of these periods of time.
Bechtel looked again at next to last paragraph and stated the following paragraph
explains what happened. He had no further questions. He stated that the tables
had so many columns he was unable to follow the "less-than" or "equals." He is
satisfied we’ve done what is expected.
Dahlen commented that Table 1 is great and will use for her own resources.
Bradshaw thanked Dahlen.
Rosenbaum referred to the three bullets on page 2. He said these were
exceedingly bureaucratic statements. He wanted to know how many times and
why isn’t the information provided?
Ulrich said we’re reporting what is expected to be reported. Part of this report is to
give a summary of what occurred. We keep records of everything but we don’t put
in a document and attach.
Rosenbaum said that raises the question if the information is not available.
Bradshaw made it clear that at no time did we ever exceed maximum levels. We
did find when .we went back and did recheck,, in keeping track of them, since they
did not exceed MCL’s we would have to go back to gather information. We
exceeded goals but at no time did we exceed MCL’s.
Ulrich thought putting it any other way in the report would be going beyond what is
expected and required.
Melton followed up on Scott’s comment about retesting. He asked if the test says
over goal and now when retesting it says not over goal, what does this imply? Is
what you’re measuring that variable from day to day? What do you think is
happening?
Bradshaw used an example of a coliform test, if there is a gram of dirt it could
show a hit. When we go back and test and find no .problem we know it was some
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IX.
type of abnormality. It could also be a contaminant at test source or could be
leaching lead at the homeowners property. We would go back in and retest.
Dahlen asked if Palo Alto does any testing for legionella .....
Bradshaw stated no.
Dahlen asked what legionella testing does SFPUC do?
SB didn’t know.
ADJOURNMENT
Regular business completed,
Ulrich spoke of the follow up report for FTTH and stated staff will have a report before we
go to City Council, which is scheduled for August 2nd. We will provide to you before the
meeting.
Budget adoption has recently been changed to June 28lh. August 2nd Fiber to the Home
is still an accurate date.
Rosenbaum checked his schedule stating Council might have questions about the
electric rate proposal so he will plan to attend the budget adoption meeting. In July we
will decide who will attend when FTTH is presented.
¯ George Bechtel will review minutes that Dee is preparing.
Meeting adjourned at 9:03 p.m.
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