1 Application No: A.08-02-001
Exhibit No.:
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Witness:
Richard M. Morrow
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5 In the Matter of the Application of San Diego Gas & )
Electric Company (U 902 G) and Southern California )
6 Gas Company (U 904 G) for Authority to Revise
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Their Rates Effective January 1, 2009, in Their
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Biennial Cost Allocation Proceeding.
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A.08-02-001
(Filed February 4, 2008)
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PREPARED DIRECT TESTIMONY
OF RICHARD M. MORROW
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SAN DIEGO GAS & ELECTRIC COMPANY
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AND
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SOUTHERN CALIFORNIA GAS COMPANY
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ON PHASE II ISSUES
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BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
December 5, 2008
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TABLE OF CONTENTS
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Page
3 I.
Qualifications and Purpose ........................................................................................ 1
4 II.
Summary .................................................................................................................... 1
5 III.
100% Balancing Account Treatment For Noncore Transportation Revenues ........... 2
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A.
Overview .......................................................................................................... 2
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B.
Commission Policy of Energy Efficiency ........................................................ 3
C.
System Planning and Expansion of Facilities .................................................. 5
D.
Noncore Throughput Is Highly Sensitive To External Factors ........................ 5
E.
Conclusion ........................................................................................................ 7
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1
PREPARED DIRECT TESTIMONY
OF RICHARD M. MORROW
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4 I.
Qualifications and Purpose
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My name is Richard M. Morrow. My qualifications are set forth in my Phase I testimony
6 that is also submitted in this proceeding. The purpose of my prepared direct testimony on behalf
7 of San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company
8 (SoCalGas) (Utilities) is to support the continued decoupling of the Utilities’ profits from their
9 noncore transportation revenues though continuation of 100% balancing account treatment for
10 those revenues.
11 II.
Summary
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The Utilities recommend continuing the 100% balancing account treatment currently in
13 place for system throughput in order to continue to align shareholder, customer and Commission
14 interests in achieving energy efficiency goals. Now would not be the time to make a change to
15 that policy and place shareholders at risk for the throughput on the system, effectively creating a
16 conflict between the interest of the Utilities to maximize profits and the state’s energy efficiency
17 policies. On October 18, 2007 in Decision D.07-10-032, the Commission affirmed that cost18 effective energy efficiency measures are the State’s highest energy priority. The Commission
19 instituted a comprehensive, long-term energy efficiency strategy to achieve the ultimate goal of
20 making energy efficiency a way of life. This goal reflects the Energy Action Plan II policy
21 placing energy efficiency at the top of the loading order in response to growing energy demand.
22 It would send the wrong message to place shareholders at risk for system throughput by
23 providing an incentive to increase energy usage. The 100% balancing account treatment for
24 noncore revenues should continue and is in alignment with the State and Commission’s
25 objectives concerning energy efficiency.
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1 III.
100% Balancing Account Treatment For Noncore Transportation Revenues
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A.
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In R.04-01-025, the Commission recognized that its effort to develop “new policies to
Overview
4 guard against a future natural gas shortage” required a reexamination of “at-risk” ratemaking
5 policies.1/ More specifically, the Commission expressed the concern that:
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“At risk” type of conditions may create incentives to the utilities to focus
too much upon short-term gains or potential losses rather than long-term
results. Yet it is the long-term supply situation, where we risk potentially
serious consequences … [T]hese ratemaking policies may create
incentives to the utilities not to have slack capacity, in order to protect
their shareholders from any risks. This could undermine the utilities’
cooperation with new suppliers of natural gas or independent storage
operators. Yet, we need slack capacity and flexibility to enhance
California’s access to sufficient supplies of natural gas at various times of
the year and to make sure that competition at the California border is
viable.
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Specific risk factors affecting potential profits or losses for the utilities could potentially
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14 shift the Utilities’ perspective away from ensuring adequate and reliable service to all of their
15 customers. First and foremost, the focus of the Utilities should be upon providing adequate, safe
16 and reliable service at reasonable rates to all of their ratepayers in their service territories.2/
There can be no doubt that placing the Utilities “at risk” for noncore gas throughput is
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18 entirely inconsistent with California energy and regulatory policy. The market conditions
19 forming the original basis for placing utility shareholders at risk for gas throughput have changed
20 significantly and do not support such an approach for the Utilities. The Commission should
21 ensure that the Utilities’ risk structure is fully aligned with California policy objectives
22 promoting energy efficiency and the construction and maintenance of sufficient utility
23 infrastructure and “slack capacity” to meet future demand.
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In considering this issue, the Commission should recognize that: a policy that promotes
25 throughput risk cannot be harmonized with policies promoting energy efficiency and
26 infrastructure “slack capacity,” there is no strong policy served by placing the Utilities at risk for
27 gas throughput, and the factors that influence EG demand on the utilities’ systems are largely
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OIR, mimeo, p. 22.
Id. at 22-23.
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1 influenced by factors outside the utilities control. The Commission therefore should not place
2 the Utilities at risk for noncore throughput.
Some parties might argue in favor of noncore throughput risk. This debate and the
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4 associated litigation over establishing noncore demand forecasts in the Utilities’ BCAP
5 proceedings has been a hotly-contested matter for many years. However, the Utilities submit
6 that now is the time for the Commission to put an end to this controversy and decide this
7 throughput “at-risk” issue as a matter of long-term public policy.
The Utilities support the continuation of the current 100% balancing account treatment
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9 for noncore transportation revenues because it aligns the long-term interests of shareholders,
10 customers and the Commission to maximize cost-effective energy efficiency by decoupling
11 utility profits from the level of gas throughput. We firmly believe that energy efficiency
12 program goals that the Utilities are obligated to achieve are mutually exclusive with an at-risk
13 condition predicated on maximizing system throughput.
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B.
Commission Policy of Energy Efficiency
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The Commission and the State of California clearly are fully committed to promoting
16 energy efficiency, an objective vigorously endorsed by the Utilities. Following the 2000-2001
17 energy crisis, there was widespread recognition that greater energy efficiency might have
18 mitigated the impact of the crisis by favorably affecting the supply/demand balance. Decoupling
19 of profits from sales and throughput has been regulatory policy in California for nearly 30 years
20 and is seen by many, including the Commission as being largely responsible for making
21 California the nation’s most energy efficient state while promoting economic growth.3/
The Energy Action Plan II (EAP) continued the strong support for the loading order that
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23 describes the priority sequence for actions to address increasing energy needs. The loading order
24 identifies energy efficiency and demand response as the State’s preferred means of meeting
25 growing energy needs. Energy efficiency is the least-cost, most reliable, and most
26 environmentally sensitive resource; it also minimizes our contribution to climate change. To
27 support this loading order, the Commission adopted aggressive energy efficiency goals for the
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Decoupling Policy, CPUC (2007);
http://www.cpuc.ca.gov/cleanenergy/design/docs/Deccouplinglowres.pdf
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1 Utilities’ customers, including core and noncore commercial and industrial customers, in
2 D.04-09-060. As Mr. Emmrich’s demand forecast testimony illustrates, the Commission’s
3 energy efficiency goals are expected to reduce the demand for natural gas by 26 MMcfd during
4 the BCAP period.
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The 2007 Integrated Energy Policy Report (IEPR) further emphasized that California’s
6 challenge is to maintain its growth and vitality while decreasing its contributions to global
7 greenhouse gases. Greenhouse gas (GHG) emissions are the largest contributor to global
8 warming, and reducing those emissions poses an enormous and urgent challenge. In passing
9 Assembly Bill 32 (the Global Solutions Act of 2006), the Governor and Legislature mandated
10 that California reduce its greenhouse gas emissions to 2000 levels by 2010 and to 1990 levels by
11 2020. Energy efficiency and demand response are key strategies for addressing climate change
12 and meeting the AB32 goals for GHG emissions.
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Recently, in D.07-10-032, the Commission re-emphasized that California’s highest
14 energy priority is to pursue cost-effective energy efficiency over both the short- and long-term.
15 The ultimate goal is to make energy efficiency a way of life. The Commission adopted a variety
16 of innovative strategies including, but not limited to: directing the Utilities to prepare a single,
17 comprehensive statewide long-term energy efficiency plan; endorsing a requirement that all new
18 commercial construction in California produce zero net energy by 2030; ensuring that the
19 heating, ventilation, and air conditioning industry utilize optimal equipment performance; and
20 establishing new, collaborative processes with key businesses, consumer groups, and
21 governmental organizations in California, throughout the West, across the nation, and even
22 internationally.
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To ensure alignment with the State’s response to growing energy demand by emphasizing
24 energy efficiency, the Utilities should not be placed at risk for changes in throughput. Continued
25 decoupling of utility profits from throughput will send the right message to the Utilities to
26 continue to maximize their energy efficiency efforts that will further reduce GHG emissions. It
27 would be highly inconsistent and counter-productive for the Utilities to be penalized for
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1 reductions in energy demand when energy efficiency is the State’s highest priority in response to
2 global warming.
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C.
System Planning and Expansion of Facilities
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In D.06-06-069, the Commission required the Utilities to expand their backbone and local
5 systems to meet a system planning requirement to meet a one-in-ten year reliability standard to
6 serve noncore customers on a firm basis. D.06-06-069 stated:
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We will direct the utilities to assure adequate backbone transmission
capacity under one-in-ten year cold and dry conditions. We will also
make explicit the requirement that the utilities plan their backbone and
storage systems so as to meet the peak day criteria already in place for
their local transmission systems.4/
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The utilities shall use system planning as well as open seasons, as
discussed herein, to minimize congestion and assure one-in-ten year
reliability for firm customers.5/
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In defining the open season to be held by the Utilities, the Commission went on to say
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14 that the Utilities will promptly expand the system to meet this requirement. The Decision stated
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We will require that SoCalGas and SDG&E hold open seasons for firm
capacity over those segments of the local transmission system which are
experiencing or are expected to soon experience congestion, and that they
publicize the results. Customers will be required to make the appropriate
use-or-pay commitments. If nominations exceed the available capacity,
then our expectation is that the utility will promptly upgrade the system.
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Having requirements to expand the Utilities’ pipeline system under an at-risk condition
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21 would be contrary to these adopted policies. The Utilities would be expected to expand the
22 system if projected demand exceeds capacity, but the at-risk condition would encourage the
23 Utilities to refrain from expanding the system because they would be at risk for the greater costs
24 resulting from expansion. The Commission should not send these mixed signals to the Utilities.
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D.
Noncore Throughput Is Highly Sensitive To External Factors
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The result of placing the Utilities at risk for noncore throughput is that any difference in
27 actual throughput compared to the Commission’s adopted demand forecast used to set customer
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For SoCalGas and SDG&E, this is one event in 35 years for core customers and one event in ten
years for firm noncore customers.
D.06-06-069, p. 63.
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1 rates would cause a variation in the recovery of the Utilities’ fixed costs. An at-risk structure
2 makes utility earnings rise or fall based on whether actual throughput is greater or less than the
3 adopted demand forecast.
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Noncore throughput, particularly for electric generation (EG), is highly sensitive to a
5 number of factors outside of the Utilities’ control. In particular, as Mr. Anderson explains in his
6 testimony, EG demand can be significantly affected by hydroelectric generation in the Pacific
7 Northwest, California electricity demand, and the availability of renewable resources, all of
8 which are entirely or largely outside the Utilities’ control.
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These factors are heavily influenced by weather that is clearly outside of the Utilities’
10 control. As shown in Mr. Anderson’s testimony, the Utilities’ EG demand is inversely
11 proportionate to hydroelectric power generation in the Pacific Northwest. When the hydro
12 conditions are at normal conditions, EG demand on the Utilities’ system averages 300 Bcf per
13 year. However, as hydro conditions vary from year-to-year, so will the EG gas demand. As Mr.
14 Anderson notes, historical hydro conditions have ranged between 56% and 124% of normal. For
15 example, in the 1-in-10 dry hydro condition, EG demand can increase by approximately 40 Bcf.
16 Conversely, if hydro runoff is 124% of normal, EG demand could be reduced annually by
17 approximately 30 Bcf. Thus, the annual variability of EG demand based on hydro conditions
18 alone can be nearly 70 Bcf based on historical experience or approximately 7.5% of the total
19 system demand forecasted during the BCAP period.
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Electricity demand is also a significant factor affecting EG demand for gas, as Mr.
21 Anderson explains. The EG gas forecast is based on normal weather conditions, but weather
22 variability can cause electricity demand in southern California to vary by almost 2% from
23 average weather. Given that natural gas is on the margin for generation, this can affect EG gas
24 demand by about 25 Bcf per year.
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Another factor affecting EG demand that is outside the Utilities’ control is the availability
26 of renewable resources. As Mr. Anderson explains, the availability of renewable power could
27 have an annual effect of nearly 15 Bcf on annual gas demand based on the electric utilities ability
28 to contract for and receive these resources. This 15 Bcf of gas demand does not account for any
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1 variability of the resources’ performance, something that also is outside the control of the
2 Utilities.
While each of these factors – weather, hydro and renewable availability – can have a
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4 significant and uncontrollable effect on EG demand, they can occur in the same year. This
5 would have the effect of either ameliorating or exacerbating the overall EG demand variation.
As Mr. Anderson testifies, the timing and uncertainties of electric transmission
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7 construction and EG plant development also play a significant role in EG gas demand.
8 “Nimbyism” over siting transmission lines and EG plants causes much uncertainty regarding the
9 timing of such projects. Add the sometimes unpredictable regulatory process for such projects
10 and these projects can be delayed for months or years. This uncertainty for large EG projects
11 creates significant uncertainty in EG demand forecasting.
As discussed above, there is a broad consensus view that energy efficiency is the number
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13 one priority in the fight against increased electricity usage and GHG emissions. According to the
14 CEC’s 2007 IEPR, natural gas is used to generate 50% of the electricity in the State.6/ As the
15 State proactively works to reduce energy demand statewide, downward pressure will also be
16 applied to the use of natural gas for electric generation.
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E.
Conclusion
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Accordingly, placing the Utilities at risk for gas throughput serves only to:
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Re-couple profits and sales, counter to the long-term policy of aligning
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shareholder and customer interests to promote energy efficiency by
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decoupling profits from sales;
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Provide Utilities a financial incentive to increase the demand on their systems;
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Provide the Utilities with a financial incentive to undermine the State’s and
Commission’s policies to encourage energy efficiency;
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Place revenue recovery at risk for factors that cannot be controlled;
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Create a more antagonistic and burdensome regulatory environment where
parties seek to shift forecasting risk to the Utilities’ shareholders; and
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California Energy Commission, 2007 Integrated Energy Policy Report, p.29.
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Conflict with Commission policy requiring the Utilities to expand their system
to meet defined planning requirements.
For all of these reasons, the Utilities strongly recommend that the Commission not place
4 them at risk for noncore throughput since it simply does not serve the public interest and is
5 contrary to sound regulatory policy. Since this policy is a long-term one, the Commission should
6 make clear in this proceeding that decoupling the Utilities’ profits from throughput is also a
7 long-term policy that should not be relitigated at every opportunity.
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This concludes my prepared direct testimony.
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