COMMENTS OF THE COGENERATION ASSOCIATION OF …€¦ · COMMENTS OF THE COGENERATION ASSOCIATION OF CALIFORNIA ON ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON 2017 PLANNING

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Develop an Electricity Integrated Resource Planning Framework and to Coordinate and Refine Long-Term Procurement Planning Requirements.

Rulemaking 16-02-007 (Filed February 11, 2016)

COMMENTS OF THE COGENERATION ASSOCIATION OF CALIFORNIA ON

ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON 2017 PLANNING ASSUMPTIONS RELATED TO COMBINED HEAT AND POWER

RESOURCES

Michael Alcantar Donald Brookhyser Alcantar & Kahl LLP 345 California Street Suite 2450 San Francisco CA 94104 415.421.4143 office 415.989.1263 fax [email protected] [email protected] Counsel to the Cogeneration Association of California

February 3, 2017

mailto:[email protected]





COMMENTS OF THE COGENERATION ASSOCIATION OF CALIFORNIA ON

ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON 2017 PLANNING ASSUMPTIONS RELATED TO COMBINED HEAT AND POWER

RESOURCES

The Cogeneration Association of California1 submits these comments on the

CPUC staff’s planning assumptions and scenario distributed in this matter by

Administrative Law Judge Julie Fitch on January 18, 2017.2

I. Introduction and Summary

The CPUC staff proposed planning assumptions include a particularly

troublesome and flawed assumption regarding the treatment of Combined Heat and

Power resources (CHP). As presented in these comments, the proposed CHP

assumption is:

Based on factually incorrect conclusions regarding the operating lives and characteristics of CHP resources;

1 CAC represents the combined heat and power and cogeneration operation interests of Midway Sunset Cogeneration Company and Watson Cogeneration Company. 2 See Administrative Law Judge’s Ruling Seeking Comment on Assumptions and One Scenario for Use in Long Term Planning in 2017, issued on January 18, 2017.

Page 2 – CAC Comments on Assumptions

Reflects an environmental policy contrary to state and federal objectives;

Inconsistent with the express objectives and policies reflected in the CPUC QF/CHP Program Settlement3, and;

An unsupportable departure from the assumptions for existing, efficient CHP resources exporting power to the grid used in the long-term planning dockets.

II. CAC Comments

A. Limited Scope of CAC Comments

At the outset, it is important to understand the scope of CAC’s position regarding

the CPUC’s CHP/QF Program relative to this docket. CAC is not urging planning

assumptions to sustain the adoption of a new, statewide CHP program for the

opportunity to develop new, incremental CHP resources. CAC’s narrow and targeted

focus is to preserve the relatively few, existing, efficient operational CHP resources in

California.

These existing resources reflect private capital investments by California

manufacturers and industry to sustain the competitive operation of California employers

and businesses supporting California communities. These are resources that were

induced to making these major capital investments by state policies, including

environmental policies, to provide clean, efficient and reliable thermal and electric power

serving industry and state interests. Assumptions that abandon these resources, such

as those reflected in CPUC staff’s proposals in this docket, are ill founded and signal a

3 The Qualifying Facility and Combined Heat and Power Program Settlement Agreement (QF/CHP Settlement or Settlement); Decision Adopting Proposed Settlement, D.10-12-035, A.08-11-001 (December 21, 2010), as modified by D.11-03-051 and D.11-07-010, available at http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/128624.pdf. FERC considered the Settlement as part of its evaluation of PURPA 210(m) conditions in Pacific Gas and Elec. Co., 135 FERC ¶ 61,234 (2011).

http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/128624.pdf


regulatory “bait and switch” to businesses who invested in, maintain and rely on highly

efficient CHP resources. In many instances, CHP is the only feasible operation to

provide needed thermal and electric power generation to support these businesses due

to air permit regulations or operational demands.

CAC is well aware of the concerns over the integration of intermittent renewable

resources and the goals to meet a 50% renewable target for the state’s generation

resources. CAC fully accepts the concept that the 50% renewable target is important to

many state environmental objectives. However, to borrow a concept coined by the

California Energy Commission staff, the other 50%, including resources like existing

CHP, matter too. With respect to existing, efficient CHP, these resources have provided

and should continue to provide electric grid reliability, relief for constrained distribution

and transmission locations, and locational and needed generation supply for load

pockets, sustaining California’s economic competitiveness, employment, tax base and

many other benefits.

A recently published quote attributed to Center for Energy Efficiency and

Renewable Technologies (CEERT) explains:

“…the solution [to addressing resource integration] involves much more than simply adding energy storage or substituting more wind or solar generation for the 55 percent of energy the state now derives from natural gas-fired generation. The key is to have the right mix. What you choose must also keep the grid properly synched, instantaneously balancing supply and demand, and maintaining the standard frequency and voltage needed to avoid blackouts.”4

In short, the assumed immediate departure of existing, efficient CHP from an

electrical system that relies on balance and diversity of resources is not consistent with

4 https://www.greenbiz.com/article/californias-grid-geeks-deep-green-time-trump.

https://www.greenbiz.com/article/californias-grid-geeks-deep-green-time-trump


a responsible balancing of diversified generation assets. CHP projects are generally

located at unique thermal and electric demand locations, and eliminating these existing,

efficient resources is imprudent for balancing the state’s complex interests. The scope

of CAC’s comments is to address one component of this balance. The scope of CAC’s

comments is not to focus upon some new expansion of a program for CHP baseload

resources, but the retention of the relatively few existing efficient CHP resources.

B. Commission Staff’s CHP Assumption

CPUC Staff’s planning assumption for CHP is reflected in paragraph 3.2.1 of the

proposed planning document as follows:

3.2.1 Combined Heat and Power

Combined Heat and Power resources identified in this section export electricity to the grid. [Footnote omitted] The default projection for exporting CHP assumes that all retiring CHP resources less than or equal to 20 MW that are on the 2016 NQC list would be replaced on a one-to- one basis by similar CHP resources; CHP resources that are greater than or equal to 20 MW will be assumed to retire based on a 40-year life cycle, or contract expiration date (whichever is furthest out).

Exporting CHP resources will be modeled as follows. First, one half of the exporting CHP capacity of each CHP resource will be assumed to operate on a historic profile as reflected by its monthly values on the 2016 NQC list and should be modeled as non-dispatchable resources. Secondly, the remaining half of the exporting capacity of each CHP resource will be assumed to be resources that are dispatchable by the CAISO.

The problematic assumption is that supply-side CHP greater than 20 MW “will be

assumed to retire based on a 40-year life cycle, or contract expiration date (whichever is

furthest out).”5 In addition, the perspective that the CAISO would be assumed to

5 January 18, 2017 ALJ Ruling, ATTACHMENT Draft 2017 Assumptions and Scenario for Long Term Planning, p. 19.


dispatch a CHP resource suggests the facility is really not a CHP operation. CHP is

providing thermal demand for an ongoing operation, and dispatching the CHP would

mean shutting down the host operation. Certainly, some limited dispatch may be

available on a case-by-case basis, but assuming that one half of all such resources may

be dispatched to zero capacity is flawed.

The following sections of these comments address in turn the perceived factual,

policy and inconsistency flaws with Staff’s proposed CHP assumptions, keeping in mind

the limited scope of CAC’s focus on existing, efficient CHP resources.

C. Operating Lives and Characteristics of CHP Resources

Staff’s assumption related to the timing of the retirement of existing CHP assets

is misplaced. CHP operations typically undergo major maintenance overhauls in five-

year cycles. This regularly scheduled maintenance provides opportunities to upgrade

equipment, enhance efficiency and effectively refresh anew the physical plant. These

units have demonstrated superior capacity and on-line performance factors, i.e.,

sustainable operating characteristics, and there is no reason to assume they will not

continue to do so. Moreover, the host facilities that rely on these CHP resources are

not typically planning on terminating operations. These hosts, usually industrial

facilities, have longevity requirements for thermal output far beyond what the CPUC

staff assumptions would support. Many of the units owned by CAC’s members are

approaching 40 years in operation, would likely be classified as exporting CHP units,

and continue to operate efficiently (all of which are greater than 20 MW). The industrial

operations that they support will continue to need the most efficiently-produced and

reliably supplied thermal and electrical energy for decades in the future.


The assumptions adopted here should not contemplate a decrease in the amount

of CHP capacity on the grid from existing, efficient resources for the period of this TPP

planning cycle (2017-2027) without a compelling factual basis. Even with California’s

commitment to reduce (not eliminate) fossil-fuel use, particularly in existing, efficient

applications, the “other 50%” of grid resources relying on clean natural gas generation

matter, and need to be prudently sustained. This Commission should embrace a

responsible and balanced set of assumptions that supports a policy that industries

relying on existing, efficient CHP should obtain their thermal and electrical requirements

in the most feasible and proficient means possible.

D. CHP and Environmental Policy

Past Commissioners and CPUC senior staff have recognized in various forums

the fact that the California CHP program is likely the singularly most significant

successful energy efficiency measure adopted and implemented by the state. Yet the

CPUC staff assumptions in this docket would seeming seek to abandon even the

existing, efficient CHP resources. These resources have and continue to provide, as

combined heat and power, sustained efficiencies and environmental benefits compared

to separate heat and power generation. While this gap may be narrowing with the

infusion of more renewable resources into the grid, there are a range of other benefits,

beyond GHG emission reductions, that these facilities provide.

The Commission should take note that the original California CHP fleet from the

1980s has continued to improve efficiencies and emission reduction benefits. Far from

simply meeting the efficiency requirements for a QF under PURPA, virtually all of the

existing resources have moved to much higher efficiency rating in their fuel to power


percentages. From the perspective of making the most efficient and environmentally

sensitive use of natural gas as a generation fuel, CHP has been and should continue to

be the preferred resource from an environmental and efficiency perspective.

E. Does the Commission Have a Sustainable CHP Program and Policy?

The assumption of retirement and decreasing CHP capacity is inconsistent with

the CPUC’s QF/CHP Program and representations made to the Federal Energy

Regulatory Commission to sustain the state administered program. The CPUC

QF/CHP Program was expressly intended, in part, to create an on-going procurement

program for existing, efficient CHP resources. The Settlement itself promised the

platform for an ongoing CHP retention program.

1.2.2.9 [Among the CHP Program objectives] Establishes a platform for a State CHP Program with identified features through 2020, and sets a framework for a sustained State CHP Program beyond 2020. The CPUC Staff’s proposed assumptions would appear to call for an end to a

sustained state CHP program for existing resources.

Moreover, express policy objectives of the CPUC QF/CHP Program call for the

encouragement of the continued operation of existing CHP, and for policies and

procedures to support that goal.

1.2.1.3 The purpose of the State CHP Program is to encourage the continued operation of the State’s Existing CHP Facilities, and the development, installation, and interconnection of new, clean and efficient CHP Facilities, in order to increase the diversity, reliability, and environmental benefits of the energy resources available to the State's electricity consumers.

1.2.1.4 These policies and purposes will be achieved by a State CHP Program that procures CHP as set forth in this Settlement, retains existing efficient CHP, supports the change in operations of inefficient


CHP to provide greater benefits to the State, and replaces CHP that will no longer be under contract with the IOUs with new, efficient CHP.

The proposed Staff assumptions on CHP are in direct conflict with these express

goals. As noted above, the Staff CHP assumptions conclude (without a factual basis)

that existing CHP resources and presumably the associated thermal requirements will

be retired and cease operation.

FERC relied on the opportunities offered to CHP facilities by the Settlement as

contributing to a competitive market for such resources.6 Abandoning such resources

and presuming there is no on-going development forces the inevitable conclusion that

California no longer offers a competitive market for CHP, which was assumed to provide

an alternative to the mandatory purchase obligation under PURPA.

The Commission’s later decisions on procurement requirements for the Second

Program Period of the Settlement (2015 – 2020) confirm this goal of preserving and

replacing CHP resources. The decision on CHP policy issues in the 2014 LTPP

proceeding set a new target for the Second Program Period:

“While we will reduce the GHG Emissions Reduction Target, we are persuaded by EPUC/CAC and others that the Second Program Period GHG Emissions Reduction Target needs to be robust enough to achieve the CHP policy objectives established in D.10-12-035 beyond GHG emissions reductions.”7

The target established for the Second Program Period relied on the same ICF Study for

CEC upon which the 2012 assumptions were based:

6 Order Granting Application, Pacific Gas & Electric, et al, Docket QM11-2, 135 F.E.R.C. ¶61,234, ¶¶ 28, 29 (June 16, 2011). 7 Decision On Combined Heat And Power Procurement Matters, D.15-06-028 (June 11, 2015), p. 16.


[W]e will use the June 2012 CEC Report’s Medium Case to establish the Second Program Period GHG Emissions Reduction Target. The Medium Case has assumptions that reflect policies in effect today.8

That decision recognized the benefits that continued use of CHP could provide to the

grid and to California’s environment:

Ideally, CHP would be situated at locations where inefficient boilers are displaced by a system that can generate both industrial-grade heat and electricity. We note that CHP, as a form of distributed generation, both displaces electric load and delivers baseload generation onto the grid. Thus, if we drastically alter the GHG Emissions Reduction Target associated with CHP procurement, we may unintentionally cause efficient existing CHP facilities without future contract certainty to shut down, and undermine the state’s efficiency and distributed generation goals.9

If the Staff assumptions are indeed reflective of the Commission’s position on the

state’s going forward CHP Program, then the Commission should be explicit about this

evolution of its position on the CHP Program. It seems, assuming Staff’s assumptions

relative to CHP reflect a Commission-adopted vision, that the Commission and some of

the non-CHP parties to the Settlement consider the Settlement ambiguous on the

objective to sustain existing resources. CAC and other CHP parties did not and do not

view the Settlement as a means to end CHP procurement in California. Rather, the

understanding was the Settlement established a sustainable state CHP procurement

program to address PURPA Section 210(m) options. Absent that understanding, the

CHP parties would not have agreed to relinquish PURPA rights for CHP resources.

8 Id., at p. 20. 9 Id., at pp. 21-22.


F. Inconsistency with Established Procurement Planning Assumptions Related to CHP

The assumption of retirement without replacement is also contrary to the

assumptions related to supply-side CHP resources in prior LTPP proceedings, including

the retention of existing CHP export generation. For example, the assumptions

approved for the 2012 plans (for the planning period through 2032) are shown in the

following table10:

Incremental Supply‐Side CHP Low Mid High

Assumptions No change in net CHP capacity

ICF Base Case ICF Mid Case

Assumption Details

33% RPS; Retirements are replaced with new CHP, keeping the current CHP capacity unchanged

Cap and trade; SGIP with program expiration in January 2016; 33% RPS; AB 1613 CHP Pricing for CHP under 20 MW; SRAC export pricing for CHP over 20 MW

SGIP is extended beyond 2016; 33% RPS; stimulus for export projects larger than 20 MWs; increased market participation due to removal of barriers

and risk by 5‐20%

Nameplate MW

0 213 1,661

Vintage:

Revised February 2012 ICF CHP Policy Analysis and 2011‐ 2030 Market Assessment Consultant

Report, expected Summer 2012

The assumptions for the 2014 LTPP plans were similar to those in 2012, relying

on the ICF study. The ruling set projections for 2024 in the CAISO area of installed

capacity of 164 MW in the low case, and 1,855 MW in the high case. This was a

projection for 2024, within the planning horizon for this current proceeding.

10 Assigned Commissioner’s Ruling on Standardized Planning Assumptions, R.12-03-014, June 12. 2012, p. 18; referencing the ICF Study: Combined Heat and Power, Policy Analysis and 2011-2030 Market Assessment, June 2012, http://www.energy.ca.gov/2012publications/CEC-200-2012-002/CEC-200-2012-002-REV.pdf.

http://www.energy.ca.gov/2012publications/CEC-200-2012-002/CEC-200-2012-002-REV.pdf


III. Conclusion

The CPUC staff assumption of “retirement without replacement” related to

existing, efficient CHP resources conflicts with this substantial precedent, abandoning

the commitment to a continued presence of CHP resources in California’s resource mix.

The assumption for supply-side CHP should be revised to provide, at a minimum, for

the retention of existing, efficient CHP resources and sustained exports from such CHP

resources throughout the planning period.

Respectfully submitted,

Michael Alcantar Donald Brookhyser Counsel to the Cogeneration Association of California

February 3, 2017

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to Develop an Electricity Integrated Resource Planning Framework and to Coordinate and Refine Long-Term Procurement Planning Requirements.

Filed Public Utilities Commission

February 11, 2016 San Francisco, CA

Rulemaking 16-02-007

COMMENTS OF THE CALIFORNIA ENVIRONMENTAL JUSTICE ALLIANCE AND

SIERRA CLUB ON THE JANUARY 18, 2017 ADMINISTRATIVE LAW JUDGE RULING REQUESTING COMMENT ON ASSUMPTIONS AND ONE SCENARIO

Deborah Behles Of Counsel for CEJA Email: [email protected] (415) 841-3304 Shana Lazerow Communities for a Better Environment 120 Broadway, Suite 2 Richmond, CA 94804 Email: [email protected] (510) 302-0430 Representing CALIFORNIA ENVIRONMENTAL JUSTICE ALLIANCE

William Rostov Staff Attorney Email: [email protected] Adenike Adeyeye Senior Research and Policy Analyst Email: [email protected] Earthjustice 50 California Street, Suite 500 San Francisco, CA 94111 (415) 217-2000 Representing SIERRA CLUB

February 3, 2017

1

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to Develop an Electricity Integrated Resource Planning Framework and to Coordinate and Refine Long-Term Procurement Planning Requirements.

Filed Public Utilities Commission

February 11, 2016 San Francisco, CA


COMMENTS OF THE CALIFORNIA ENVIRONMENTAL JUSTICE ALLIANCE AND

SIERRA CLUB ON THE JANUARY 18, 2017 ADMINISTRATIVE LAW JUDGE RULING REQUESTING COMMENT ON ASSUMPTIONS AND ONE SCENARIO

CEJA and Sierra Club file these comments in response to the January 18, 2017

Administrative Law Judge’s Ruling Seeking Comment on Assumptions and One Scenario for

Use in Long Term Planning in 2017 (“ALJ Ruling”). These comments focus on the

appropriateness of the assumptions for use in the California Independent System Operator’s

(“CAISO’s”) 2017-18 Transmission Planning Process (“TPP”).

INTRODUCTION

In the ALJ Ruling, the Commission requested comment on assumptions for the current

iteration of the CAISO’s TPP process.1 The ALJ Ruling emphasized that these assumptions act

essentially as a placeholder and that future assumptions and scenarios will be developed based on

the Commission’s integrated resource planning process.2 The ALJ Ruling and its attached Staff

Paper further assume only a 33% renewable portfolio standard (“RPS”) and rely on assumptions

that do not take into account the mandates of SB 350.3

CEJA and Sierra Club agree with the Staff’s reasoning that future assumptions and

scenarios should be based on the results of the integrated resource planning and that it makes

sense to only model the 33% RPS scenario at this time. This proposal will most likely maintain

1 ALJ Ruling at p. 1. 2 ALJ Ruling at p. 2. 3 ALJ Ruling at pp. 3-4.

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the status quo on transmission while providing room for this proceeding to develop a plan and

portfolio of renewable resources to comply with the 50% RPS mandate and the other

requirements of SB 350.

Staff, however, should not rely on assumptions that do not take into account the demand-

side mandates of SB 350 and other requirements, because Staff is currently proposing to use the

TPP’s analysis of local capacity need in the modeling in this proceeding. Local capacity need can

be significantly impacted by the amounts of energy efficiency (“EE”), demand response (“DR”),

and distributed energy resources (“DER”) assumed. In fact, these assumptions and CAISO’s

local capacity requirements have been the source of significant litigation in past Long Term

Procurement Planning proceedings.4 CAISO’s TPP will not provide a reliable value for local

capacity need unless, at the very least, the demand side assumptions are changed to reflect the

current requirements of SB 350 and other mandates.

In addition, demand-side resources such as energy efficiency and distributed generation

are likely to significantly impact transmission needs. Higher penetrations of demand side

resources can lead to reductions in the need for transmission and generation. Indeed, CAISO

recently found less need for a new transmission line “because of primarily growth of rooftop

solar and demand response and energy efficiency.”5 Furthermore, in its last TPP, CAISO

cancelled a number of transmission projects “in light of materially lower load forecast levels

since those projects were approved.”6

4 See, e.g., D.13-02-015 at pp. 13-62. 5 See Lindt, John. “Big power lines may be unneeded.” Hanford Sentinel 11 Jan. 2017, http://hanfordsentinel.com/news/local/business/big-power-lines-may-be-unneeded/article_afcfa7c6-7f1c-5b64-ad45-d55123575b99.html. 6 California Independent System Operator, 2015 -2016 Transmission Plan at pp. 2-3 (March 28, 2016), https://www.caiso.com/Documents/Board-Approved2015-2016TransmissionPlan.pdf.

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Consequently, CEJA and Sierra Club primarily focus their comments on several separate

assumptions for: energy efficiency, distributed generation, and demand response. All of these

assumptions should be modified to fully reflect the statutory requirements and California Air

Resources Board’s (“CARB’s”) Scoping Plan. Even if the assumptions for the TPP will only be

used in the 2017 TPP, the Commission should adopt assumptions that reflect California’s

demand-side regulatory mandates to help ensure that the TPP does not call for unnecessary local

capacity and transmission.

In addition, CEJA and Sierra Club request that continued work is performed to ensure

optimization of locational information for resources for use in planning processes such as the

TPP. Locational information is increasingly important. As the Staff Paper aptly summarizes:

“[a]s California chooses to meet its electricity needs with increasing proportions of demand-side

management resources, such as energy efficiency and customer-sited solar photovoltaic (PV)

self-generation, it becomes increasingly important to accurately forecast the locations of these

demand-side impacts in order to capture the benefits that these resources provide to the system.”7

In addition, Staff should clearly delineate IRP inputs for all results that Staff imports

from the TPP into the IRP, such as the local capacity requirements. The Commission must

provide an opportunity to litigate these results within the context of the IRP because the results

may be based on stale and/or inaccurate assumptions. For example, this year’s IRP will be using

the local capacity requirement from the 2016 TPP, which is based on stale assumptions that do

not conform to California’s clean energy mandates. The use of requirements based on out of date

assumptions raises significant concerns about the integrity of the modeling for this year’s IRP.

7 ALJ Ruling Attachment: Draft 2017 Assumptions and Scenario for Long-Term Planning (“Staff Paper”) at p. 10.

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Staff must create a designated place in the process where the outputs from the TPP can be

litigated in the IRP.

DISCUSSION RELATED TO SPECIFIC ASSUMPTIONS

(1) Energy Efficiency

The energy efficiency assumption should be modified to reflect the requirements for

doubling under Senate Bill (“SB”) 350. Specifically, SB 350 requires California “[t]o double the

energy efficiency savings in electricity and natural gas final end uses of retail customers through

energy efficiency and conservation” by 2030.8 SB 350’s EE requirement is not optional – it is the

law. In addition, it represents an integral part of how the State plans to achieve its GHG

requirements.

SB 350’s EE doubling requirement is not currently reflected in the assumptions. The

assumptions include “[n]o projection for the doubling of Additional Achievable Energy

Efficiency (AAEE) due to Senate Bill 350 (De Leon, 2015), since the setting of that goal is

currently underway at the [California Energy Commission].”9 The draft assumptions propose

using the Integrated Energy Policy Report’s (“IEPR’s”) mid-case for additional achievable

energy (“mid-AAEE”). This assumption, however, dramatically underestimates the amount of

EE required under SB 350.

A more accurate assumption of the amount of EE required pursuant to SB 350 is

currently available in CARB’s January 2017 Scoping Plan. As discussed in that plan, to meet SB

350’s EE requirements, CARB assumes that “[r]elative to the California Energy Demand 2016-

2026 Adopted Forecast, electric energy efficiency is 2 times higher than the 2015 IEPR

8 Clean Energy and Pollution Reduction Act of 2015, Senate Bill No. 350 § 2(a)(2). 9 See ALJ Ruling at p. 4.

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AAEE.”10 CARB’s other scenario assumes EE is 2.5 times the 2015 IEPR AAEE.11 To better

align with SB 350’s requirements as well as CARB’s Scoping Plan, the EE estimates should at

least reflect the current estimate by CARB until the CEC develops a more specific estimate.

Otherwise, the TPP may project a need for unnecessary transmission resources as it has done in

the past.

(2) Distributed Generation

The Staff Paper proposes using the mid behind-the-meter solar photovoltaic (“BTM PV”)

assumption from the CEC’s demand forecast. That forecast assumes that PV peak demand

reaches around 2,800 MW for residential load and 1,700 MW for non-residential load.12 This

assumption is significantly lower than the assumption CARB uses in its Scoping Plan. CARB’s

Scoping Plan’s Scenario assumes 18.2 GW statewide from BTM PV by 2030.13 Notably,

CARB’s Scoping Plan Alternative scenario assumes 28.4 GW statewide from BTM PV by 2030

“based on an extrapolation of the California Energy Demand 2016-2026 Adopted Forecast high

rooftop PV scenario.”14 Solar PV penetration is likely to significant expand given SB 350’s

emphasis on distributed energy resources15 as well as low PV prices and predicted increased

10 See California Air Resources Board, The 2017 Climate Change Scoping Plan Update, Attachment D, pg. 8 (January 20, 2017), available at https://www.arb.ca.gov/cc/scopingplan/app_d_pathways.pdf. 11 Id. at p. 6. 12 See California Energy Commission, California Energy Demand 2016-2026, Revised Energy Forecast, Volume 1: Statewide Electricity Demand and Energy Efficiency, at pp. B-18-B-19, available at http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-03/TN207439_20160115T152221_California_Energy_Demand_20162026_Revised_Electricity_Forecast.pdf. 13 See California Air Resources Board, The 2017 Climate Change Scoping Plan Update, Attachment D, p. 12, available at https://www.arb.ca.gov/cc/scopingplan/app_d_pathways.pdf. 14 See California Air Resources Board, The 2017 Climate Change Scoping Plan Update, Attachment D, pp. 13, available at https://www.arb.ca.gov/cc/scopingplan/app_d_pathways.pdf. 15 See, e.g., Cal. Public Util. Code § 400.

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solar penetration in California.16 At the very least, the TPP should align with an extrapolation of

the 18.2 GW in CARB’ Scoping Plan Scenario.

The Staff Paper also questions the need for location specific information related to PV:

“CPUC staff believes the benefit of incorporating such granular information in long-term

planning assumptions is small because the overall uncertainty in BTM PV aggregate installed

capacity in the long term is a much larger driver of modeling results.”17 While this may reflect

the type of assumptions necessary for the high level RESOLVE modeling that Staff intends to do

for the reference plan, it is less true with relation to the CAISO’s work in the TPP and for the

IRPs prepared by the Load Serving Entities. Targeting PV to particular locations will reduce

loads on transmission and needs in local area. The location of the PV can be critical for reducing

eventual needs for transmission and generation. Thus, CAISO and the Commission should work

to develop as much granular information as possible related to PV to help minimize need for

additional expenditures of transmission and generation.

(3) Demand Response

The Staff admits that the current values do not necessarily reflect the likely impacts of

demand response: “There may also be additional DR impacts that need to be explored. For

example, a future DR impact may come from defaulting residential customers to TOU rates.”18

The Commission Staff states that it will work with the CEC to develop this during the next IEPR

16 See Solar Energy Industry Association, http://www.seia.org/state-solar-policy/california. SEIA states that: “Over the next five years, California is expected to install 20,487 MW of solar electric capacity, ranking the state first over that time span. This amount is more than 2 times the amount of solar installed over the last five years.” Id. “Installed solar PV system prices in the U.S. have dropped steadily-by 12% from last year and 66% from 2010.” Id. 17 Staff Paper at p. 14. 18 Staff Paper at p. 16.

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cycle, but better assumptions are currently available in the DR Potential Study performed by

Lawrence Berkeley National Laboratory (“LBNL”).19

In addition, the Staff’s demand response assumptions assume no growth for demand

response programs between now and 2026. To justify this, the Staff states: “[f]or modeling

purposes we assume capacity from existing programs described in the Load Impact Reports are a

reasonable proxy for DR in 2026. It could turn out that by 2026, capacity from existing programs

will be ‘retired’ and ‘replaced’ by significant growth in DRAM capacity.”20 The Staff further

assumes that dispatchable DR remains constant from the 2026 value through the second planning

period.21 Better assumptions related to growth are also available in the DR Potential Study.

Indeed, the Staff Paper’s assumptions related to DR programs and growth do not reflect

the anticipated DR from the LBNL Potential Study. In its study, LBNL found that the medium

case for DR potential was 4.2 GW.22 This is significantly more than the under 2 GW the Staff

Paper assumes for 2026. The Staff should not assume such a low level when the potential study

has found a higher value and SB 350 requires increased reliance on DR.23

AB 2454 requires consideration of the DR Potential Study when determining DR

resources providing: “In determining the availability of cost-effective, reliable, and feasible

demand reduction resources, the commission shall consider the findings regarding technically

and economically achievable demand reduction in the Demand Response Potential Study

19 Lawrence Berkeley National Laboratory, Final Report on Phase 2 Results: 2015 California Demand Response Potential Study, Charting California’s Demand Response Future (Final Draft)(November 14, 2016), available at http://www.cpuc.ca.gov/General.aspx?id=10622. 20 Staff Paper at p. 27. 21 Staff Paper at p. 44. 22 See Lawrence Berkeley National Laboratory, 2015 California Demand Response Potential Study: Updated Phase 1 Results, at Slide 17 (August 18, 2016), available at http://www.cpuc.ca.gov/General.aspx?id=10622. 23 See, e.g., Cal. Public Util. Code § 400.

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required pursuant to Commission Order D.14-12-024.”24 The LBNL Demand Response Potential

Study was the study performed pursuant to this Commission order.25

The DR value should be revised to the values from LBNL’s Phase 2 DR Potential

Study.26 This will more closely parallel the modeling in the IRP that is anticipated incorporate

those values.

(4) Energy Storage

The Staff Paper’s assumptions did not include the 1% target of load for the ESPs and

CCAs.27 There is no reason to not include this. Energy storage is likely to be developed in these

areas in the near future.28 This load should be included.

(5) Frequency Response

CEJA and Sierra Club support the removal of the 25 percent regional generation

requirement constraint. The Staff Paper further provides that “the need to supply sufficient

frequency response must still be met, and this will be modeled by a new constraint in production

cost simulation models that would ensure each balancing area can meet its obligations under the

24 Cal. Public Util. Code § 454.5(b)(9)(C)(ii). 25 See, e.g., See Lawrence Berkeley National Laboratory, Final Report on Phase 2 Results: 2015 California Demand Response Potential Study, Charting California’s Demand Response Future (Final Draft)(November 14, 2016), available at http://www.cpuc.ca.gov/General.aspx?id=10622, (“LNBL Phase 2 Report”), p. 1-2; see also California Public Utilties Commission, Demand Response Evaluation and Research, http://www.cpuc.ca.gov/General.aspx?id=10622 (describing the study). 26 LBNL’s Phase 2 Report describes the potential for other DR products. 27 Staff Paper at p. 20. 28 See, e.g., Bloom, Max. “Pilot Energy Storage Project Installed at College of Marin in California” Renewable Energy World, available at http://www.renewableenergyworld.com/articles/2016/07/pilot-energy-storage-project-installed-at-college-of-marin-in-california.html.

9

new [constraint in production cost simulation models]…”29 CEJA and Sierra Club also support

Staff’s assumption that energy storage can meet the frequency response requirements.

In future iterations of the assumptions, the Commission and CAISO should also develop

a projection for frequency response from solar PV. As a recent report by CAISO found:

“[a]dvancement in smart inverter technology combined with advanced plant controls allow solar

PV resources to provide regulation, voltage support and frequency response during various mode

[sic] of operations.”30

CONCLUSION

CEJA and Sierra Club request the Commission to ensure that its demand-side values for

the TPP are consistent with requirements related to SB 350 and other requirements.

Dated: February 3, 2017

Respectfully Submitted,

William Rostov Staff Attorney Email: [email protected] Adenike Adeyeye Research and Policy Analyst Email: [email protected] Earthjustice 50 California Street, Suite 500 San Francisco, CA 94111 (415) 217-2000 Representing SIERRA CLUB

29 Staff Paper at p. 39. 30 See California Independent System Operator, Using Renewables to Operate Low-Carbon Grid, at p. 56, available at http://www.caiso.com/Documents/UsingRenewablesToOperateLow-CarbonGrid.pdf.

10

/s/ Deborah Behles Deborah Behles Of Counsel for CEJA Email: [email protected] (415) 841-3304 Shana Lazerow Email: [email protected] Communities for a Better Environment 120 Broadway, Suite 2 Richmond, CA 94804 (510) 302-0430 Representing CALIFORNIA ENVIRONMENTAL JUSTICE ALLIANCE




COMMENTS OF EAGLE CREST ENERGY ON THE DRAFT 2017 ASSUMPTIONS AND SCENARIO FOR LONG TERM PLANNING

J. DOUGLAS DIVINE Chief Executive Officer Eagle Crest Energy Company 3000 Ocean Park Blvd., Suite 1020 Santa Monica, CA 90405 Tel.: (310) 450-9090 Fax: (310) 450-9494 Email: [email protected] WILLIAM D. KISSINGER Morgan, Lewis & Bockius LLP One Market, Spear Street Tower San Francisco, CA 94105 Tel.: (415) 442-1480 Fax: (415) 442-1001 Email: [email protected]

February 3, 2017

1




COMMENTS OF EAGLE CREST ENERGY ON THE DRAFT 2017 ASSUMPTIONS AND SCENARIO FOR LONG TERM PLANNING

Eagle Crest Energy Company (“Eagle Crest”) appreciates the opportunity to submit these

comments in response to the Administrative Law Judge’s Ruling on January 18, 2017, inviting

comments on the Draft 2017 Assumptions and Scenario for Long Term Planning (“Draft

Assumptions”).

I. Background

Eagle Crest is developing the 1,300 MW Eagle Mountain Pumped Storage Project

(“Eagle Mountain”) near Desert Center, California in eastern Riverside County.1 As detailed in

earlier comments filed in this proceeding, development of pumped hydro resources like Eagle

Mountain could serve as the critical final element needed to achieve California’s ambitious goal

of dramatically reducing greenhouse gas (“GHG”) emissions. It could do so while also cost-

effectively helping the State to meet or exceed the 50% RPS by storing renewable power that

might otherwise have been curtailed and instead make it available when GHG-producing

generation would otherwise be required to serve load.

On December 16, 2016, the Commission’s Energy Division staff held a public workshop

regarding the proposed approach to developing the reference plan for 2017 for the Integrated

Resources Plan (“IRP”). The presentation for the workshop indicated that Energy Division is

considering modeling a 500 MW “bulk storage” scenario. Staff requested informal party input

1 Eagle Mountain has received virtually all of its major permits and approvals, including a hydroelectric generation license from the Federal Energy Regulatory Commission (“FERC”). The only material outstanding approval is a right-of-way grant for the generation tie-line from the U.S. Bureau of Land Management, which is well underway.

2

and Eagle Crest submitted comments commending the Energy Division for doing so but also

urging that the scenario be for at least 1,300 MW of bulk storage, which, as noted in our

comments, is much more realistic given the size of Eagle Mountain in addition to other bulk

storage projects that are under development.2 As detailed below, this observation is relevant to

assumptions that are now being proposed in the Draft Assumptions.

II. Comments on the Draft Assumptions

The Administrative Law Judge (“ALJ”) has afforded the parties the opportunity to

comment on the Draft Assumptions. The ALJ asks:

Are the updates to the demand-side and supply-side assumptions reasonable and accurate? Please specify any assumptions that should be revised and provide a detailed justification supporting the recommended revisions.

ALJ Ruling at 5. Unlike prior year’s versions of this document, this iteration specifically describes itself as

serving as something of a bridge between past Long Term Procurement proceeding (“LTPP”)

and the new IRP proceeding.3 As a result, this year’s Draft Assumptions may likely have less

significance than in prior years. That said, they will continue to be highly significant in the

CAISO’s development of the 2017-2018 Transmission Plan in the CAISO’s Transmission

Planning Process (“TPP”).

Eagle Crest’s comments are limited to the portion of the Draft Assumptions relating to

storage and, in particular, the assumptions about storage attributes and capabilities set forth in

Section 3.2.4. In essence, the Draft Assumptions proposes that all existing storage projects will

be treated as if they have the same attributes and capabilities. The document states:

For modeling purposes, the entire 1,325 MW energy storage target shall be assumed to be operated such that the storage provides energy shifting, capacity, and flexibility services. The interconnection point of a storage resource does not determine its effectiveness for providing resource adequacy capacity, including flexible capacity, or ancillary services. In other words, regardless of interconnection domain (transmission-connected, distribution-connected, BTM), all storage shall be modeled as dispatchable and providing Resource Adequacy capacity and operational flexibility services. This represents a change in assumptions from the previous LTPP A&S.

2 See “Informal Comments of Eagle Crest Energy on the Questions for Parties Following Public Workshop on 12/16/16,” CPUC Docket No. R. 16-02-007, filed Jan. 13, 2017. 3 Draft Assumptions at 8.

3

Draft Assumptions at 20. This assumption is significantly different from the assumption the

Commission adopted in the 2016 Assumptions and Scenario for Long Term Planning.4 In that

document, the Commission developed assumptions which differentiated among the types of

storage procured. In addition, the Draft Assumptions exclude any scenario that includes

additional bulk storage above the mandated 1,325 MW, notwithstanding consideration of such an

assumption in the equivalent document being developed in the IRP.

We assume the Commission’s proposed simplifications about the amount of storage, and

the attributes and capabilities of such projects are all aimed at streamlining the modeling effort

for the 2017-2018 TPP given the much more robust Assumptions and Scenarios being developed

in the IRP.

Recognizing this fact, Eagle Crest does not urge a different approach in the Draft

Assumptions other than to urge that the document contain an express acknowledgment of the

limitations embedded in the storage assumptions being used. All storage is not created equal.

There are substantial differences between different kinds of storage projects. Battery and

flywheel storage technologies have different duration curves from one another and other

technologies such as pumped storage. For example, once built Eagle Mountain will be able to

discharge its full 1,300 MW capacity for up to 18 hours, which is quite different from the 1,325

MW of storage included in the Draft Assumptions.

Similarly, even within those 1,325 MW of storage, significant differences exist that are

not fully detailed in the Draft Assumptions. Where storage projects are deployed -- whether

“behind the meter” or on the distribution/transmission systems -- and the technology deployed

will result in dramatically different capabilities. For example, some storage is designed to

provide only regulation service without load-shifting, with only 15 minutes of sustainable output

capability and much less Resource Adequacy value, while other installations with the same

maximum output level may contain much more storage and load shifting ability. Other “behind-

the-meter” storage is designed solely for load reduction and cannot provide any of the benefits

that come with the ability to inject energy into the grid.

Yet the Draft Assumptions assume all storage should be modeled as fully dispatchable

and providing Resource Adequacy capacity and load-shifting/operational flexibility services. 4 See “Assigned Commissioner’s Ruling Adopting Assumptions and Scenarios for Use in the California Independent System Operator’s 2016-17 Transmission Planning Process and Future Commission Proceedings,” CPUC Docket No. 13-12-010, issued May 5, 2016, at Section 4.2.4.

4

By making this assumption, the Draft Assumptions will likely overstate the system benefits

afforded by the current Commission-authorized 1,325 MW storage procurement mandate.

As noted, Eagle Crest recognizes the “bridging role” this document serves in the

transition from the LTPP to the IRP process. Rather than urge the inclusion of additional bulk

storage scenarios (as in the IRP) or differentiating between existing storage projects, Eagle Crest

urges only that the Commission properly note the simplified assumptions which will influence

the study results, results which presumably will be carried over into the CAISO’s 2017-18 TPP.

III. Conclusion

Eagle Crest appreciates the opportunity to submit these comments and looks forward to

continuing to work with Commission during the course of the proceeding.


By: /s/ William D. Kissinger WILLIAM D. KISSINGER Morgan, Lewis & Bockius LLP One Market, Spear Street Tower San Francisco, CA 94105 Tel.: (415) 442-1480 Fax: (415) 442-1001 Email: [email protected]

Date: February 3, 2017

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Develop

an Electricity Integrated Resource

Planning Framework and to Coordinate Rulemaking R-16-02-007

and Refine Long-Term Procurement

Planning Requirements

COMMENTS OF THE GREEN POWER INSTITUTE

ON THE DRAFT 2017 ASSUMPTIONS AND SCENARIO

FOR LONG TERM PLANNING

February 3, 2017 Gregory Morris, Director

The Green Power Institute

a program of the Pacific Institute 2039 Shattuck Ave., Suite 402

Berkeley, CA 94704

ph: (510) 644-2700

fax: (510) 644-1117

[email protected]

GPI Comments on the Draft 2017 Assumptions and Scenario Document, in R.16-02-007, page 1

COMMENTS OF THE GREEN POWER INSTITUTE

ON THE DRAFT 2017 ASSUMPTIONS AND SCENARIO

FOR LONG TERM PLANNING

Pursuant to the January 18, 2017, Administrative Law Judge’s Ruling Seeking Comment on

Assumptions and One Scenario for Use in Long Term Planning in 2017, in Proceeding R-

16-02-007, the Order Instituting Rulemaking to Develop an Electricity Integrated

Resource Planning Framework and to Coordinate and Refine Long-Term

Procurement Planning Requirements, the Green Power Institute (GPI), the renewable

energy program of the Pacific Institute for Studies in Development, Environment, and

Security, provides these Comments of the Green Power Institute on the Draft 2017

Assumptions and Scenario for Long Term Planning. We address various matters from the

Attachment to the Ruling, and the question on page 5 of the Ruling.

Draft 2017 Assumptions and Scenarios Document

As explained in the introduction to the Attachment, the draft 2017 assumptions and scenario

document prepared for the TPP process at the CAISO is the outgrowth of a process of

producing these documents that has been ongoing for some time. As a result, a good deal of

the content has already been vetted in past rounds of the LTPP. As with each new version of

the document, some of the content is new. The GPI’s expertise in the IRP proceeding is in

the area of preferred supply-side resources, particularly renewables, so our comments are

focused on Section 3.2 of the Attachment, Supply-Side Assumptions.

We are gratified to see that the supply-side assumptions include a complete section on the

topic of storage resources, which are supported by a Commission-imposed mandate for the

state’s three IOUs of 1,325 MW. On page 20 the text notes: “It is assumed that there will

be no further growth in energy storage capacity targets, post 2024, beyond 1,325 MW.” The

GPI questions the appropriateness of this assumption. The purpose of the energy storage

program that was put into place by D.13-10-040 was not to create 1,325 MW of storage as a

goal in-and-of itself. Rather, the purpose was to prime and stimulate what was hoped would


be a growth market in the state. In that spirit, we believe that it would be appropriate to

assume something like continued linear growth in storage capacity from 2024 to the end of

the planning period. No further growth post-2024 sends the wrong signal to the

marketplace. Projecting reasonable continuing growth in storage capacity post-2024

requires no more than a modest amount of effort.

Section 3.2.6 of the Attachment, RPS Portfolios, explains that a single, 33-percent-by-2020

scenario is included in the assumption set. The text notes:

Various studies are underway that could inform planning beyond the 33% RPS goal. Thus,

various pathways may eventually be identified that lead to a beyond-33% goal. To include a

portfolio of increased renewables for long term planning would be to presuppose the

conclusions of the various studies underway, particularly as it relates to potential infrastructure

authorizations needed to meet future goals. Thus, no new RPS portfolios are specified this year

for additional resources needed to meet RPS goals. [Attachment, pg. 32.]

We disagree with this reasoning. The stretch-goal of 50 percent is already on the books, and

the Commission, in the RPS proceeding (R.15-02-020), has already established a schedule

of annual RPS targets for 2021 – 2030, culminating at 50 percent. We understand that there

are various studies underway that will be looking at future scenarios, and indeed that

ultimately the IRP studies will generating such scenarios. Nevertheless, we do not

understand why the 33-percent RPS level achieved by 2020 cannot be projected to the end

of the planning period using the targets already enacted in the RPS program (D.16-12-040)

that implement the stretch 50-percent-by-2030 target already in statute. Projecting

reasonable continuing growth in RPS capacity post-2024 requires no more than a modest

amount of effort, and would significantly improve the 2017 Assumptions and Scenarios

document.

The Attachment notes:

The IRP process is expected to include a new and more appropriate methodology for

developing RPS portfolios than the RPS calculator. As a result, it would be more prudent to

incorporate the results of the IRP process in the 2018-2019 TPP. [Attachment, pg. 32.]


We applaud the news that the Commission will adopt, in the IRP process, a new, more

appropriate methodology for developing RPS portfolios, and in the process retire the RPS

Calculator. However, as we have explained above, that does not presuppose projecting to

the end of the planning period in the 2017 version of the assumptions, using already

established RPS targets. We believe that this simple step will provide greater consistency

between the 2017 assumptions, and future versions of the assumptions.

Section 3.2.10 of the Attachment, Renewable and Hydro Retirement Assumptions, explains:

Retirement assumptions are based on a facility’s age as a proxy for determining a facility’s

remaining operational life. In previous versions of the LTPP A&S document, three options for

renewable retirement levels were provided , which corresponded to “low-”, “medium-”, and

“high-” levels of renewable retirement assumptions. In the 2017 A&S, it is assumed there will

be no renewable retirements within the planning horizon. [Attachment, pg. 37.]

The GPI disagrees with the assumption that there will be no renewable retirements within

the planning horizon. In fact many of the original SO#4 PPAs will expire over the next few

years, well within the planning horizon, and it is most unlikely that all of the affected

generators will be able to continue operating post expiration. We offer the example of the

California biomass energy industry. The California biomass energy industry peaked at 750

MW of operating capacity in 1990, and stabilized at approximately 600 – 650 MW of

operating capacity during the period 2000 – 2014. With no new large biomass power plants

in the planning stages, and considering the fact that biomass generators have failed to secure

any new PPAs through the competitive RPS solicitation process, most of the facilities

looked to be destined to shut down when their contracts expired. This process was

interrupted in 2016 by the offering of targeted biomass solicitations in response to the state’s

2015 declaration of a tree-mortality crisis. These solicitations provided a lifeline to the

successful bidders, but they are a one-time, unique offering. Several facilities will be

shutting down over the next several years, and the remaining industry will fall well below

500 MW of operating capacity. This should be reflected in the assumptions document.

Considering the fact that the growth in the California renewable energy sector since 2011has

been concentrated almost exclusively in solar PV, circumstances similar to those facing the


biomass industry are also facing other, non-PV sectors of the state’s aging, pre-RPS

renewable infrastructure. Thus the GPI believes that an assumption of no renewable

retirements within the planning horizon is unsupportable, and leads to an under-projection of

the need for near-term and medium-term procurement of new renewables.

Finally, we note that the Section on Planning Scenarios in the Attachment, Section 4, repeats

the arguments that were made in Section 3.2.6 regarding limiting the 2017 Assumptions and

Scenarios document to a single, 33-percent-only RPS scenario. As we argued above, we

disagree with the reluctance to extend the RPS scenario to 50-percent-by-2030, consistent

with the current RPS statutes.

Question from Ruling

In addition to introducing the Draft 2017 Assumptions and Scenario for Long Term

Planning document into the record, the January 18, 2017, ALJ’s Ruling poses a single

question that Parties are asked to address:

Are the updates to the demand-side and supply-side assumptions reasonable and accurate?

Please specify any assumptions that should be revised and provide a detailed justification

supporting the recommended revisions. [Ruling, pg. 5.]

On the whole, the GPI believes that the updates to the supply-side assumptions in the draft

2017 document are reasonable and accurate. As we discuss above, there are several supply-

side assumptions in the document that should be revised, mainly the following:

In Section 3.2.4, Energy Storage, the draft document assumes no growth in the

storage market beyond the 1,325 MW mandated in the Commission’s landmark

storage decision, D.13-10-040. However, the rationale behind the creation of the

initial 1,325 MW mandate was to prime the marketplace for a growing energy

storage industry. The document should assume continuing growth in the energy

storage industry through the end of the planning period.

In Section 3.2.6, RPS Portfolios, the draft document declines to include an RPS

scenario that rises above 33-percent renewables. The RPS statutes current specify

50-percent renewables by 2030, and this should be reflected in the RPS scenario.


In Section 3.2.10, Renewable and Hydro Retirement Assumptions, the draft

document adopts the assumption that there will be no renewables retirements within

the planning horizon. This is a vert poor assumption, and should be replaced with a

more realistic assumption about the retirement of existing renewables subsequent to

the expiration of their PPAs.

Conclusion

The Draft 2017 Assumptions and Scenario document represents in many respects a

transition from the established, LTPP A&S document, to what will emerge from the IRP

process, which is currently under development. The GPI appreciates that it is a document in

transition; however we believe that it is still worth making it into as useful a document as it

can be. We recommend that the draft document be amended as we have described above

before being sent to the CAISO.

Dated February 3, 2017.


Gregory Morris, Director

The Green Power Institute

a program of the Pacific Institute

2039 Shattuck Ave., Suite 402

Berkeley, CA 94704

ph: (510) 644-2700

e-mail: [email protected]

February 3, 2017 L. Jan Reid




(Filed February 11, 2016)

COMMENTS OF L. JAN REID ON PLANNING ASSUMPTIONS AND ONE SCENARIO

February 3, 2017 L. Jan Reid 3185 Gross Road Santa Cruz, CA 95062 Tel/FAX (831) 476-5700 [email protected]

R.16-02-007 L. Jan Reid

L. Jan Reid -i- Planning Assumptions

TABLE OF CONTENTS

Page

I. Introduction .................................................................................................. 1

II. Summary and Recommendations .............................................................. 1

III.

R.16-02-007 L. Jan Reid

L. Jan Reid -ii- Planning Assumptions

Proposed Findings ................................................................................................... 2

IV. Reasonableness and Accuracy of Assumptions ...................................... 2

A. Combined Heat and Power .................................................................. 2

B. Energy Storage ........................................................................................ 3

C. Plant Retirement Assumptions ............................................................ 5

V. Searchable PDF Files ................................................................................... 5

VI. Conclusion .................................................................................................... 6

R.16-02-007 L. Jan Reid

L. Jan Reid -1- Planning Assumptions

I. Introduction

Pursuant to the January 18, 2017 ruling (Ruling) of Administrative Law

Judge (ALJ) Julie Fitch, I submit these comments on the revised planning

assumptions and on one scenario. Opening comments are due on Friday,

February 3, 2017. I will send this pleading to the Docket Office using the

Commission’s electronic filing system on the due date, intending that it be timely

filed.

The Ruling requests that parties comment on a question provided by the

ALJ. I answer this question in Section IV below.

II. Summary and Recommendations

I have relied on state law and past Commission rulings in developing

Recommendations concerning the standardized planning assumptions. I recom-

mend the following:1

1. For planning purposes, the Commission should assume that all Com-bined Heat and Power (CHP) capacity is dispatchable. (pp. 2-3)

2. The Commission should base its Energy Storage assumptions on bids received by the IOUs in their 2016 and 2017 Energy Storage Request for Offers (RFOs). (pp. 3-5)

3. The Commission should order parties to use a “Low” level of retire-ment when modeling “Other” resources. (p. 5)

____________________

1 Citations for these recommendations and proposed findings are given in pa-rentheses at the end of each recommendation and finding.

R.16-02-007 L. Jan Reid


III. Proposed Findings

My recommendations are based on the following proposed findings.

1. The Commission has an obligation under Public Utilities Code Sec-tion (PUC §) 451 to protect ratepayers and to ensure that rates are just and reasonable. Consistent with PUC § 451, the Commission must protect ratepayers from resource over-procurement associated with uncertainties such as the dispatchability of CHP resources. (p. 3)

2. In part, Rule 1.10(c) of the Commission’s Rules of Practice and Proce-dure states that “Documents must be in readable, downloadable, printable, and searchable formats, unless use of such formats is infea-sible.” (pp. 5-6)

IV. Reasonableness and Accuracy of Assumptions

1. Are the updates to the demand-side and supply-side assumptions reasonable

and accurate? Please specify any assumptions that should be revised and pro-

vide a detailed justification supporting the recommended revisions.

No, some of the demand-side and supply-side assumptions are not reason-

able or accurate. I discuss these assumptions below.

A. Combined Heat and Power

The Ruling states that: (Attachment A, p. 19)

Exporting CHP resources will be modeled as follows. First, one half of the exporting CHP capacity of each CHP resource will be assumed to operate on a historic profile as reflected by its monthly values on the 2016 NQC list and should be modeled as non- dispatchable resources. Secondly, the remaining half of the export-ing capacity of each CHP resource will be assumed to be resources that are dispatchable by the CAISO.

The Energy Division has not provided a basis for its assumption that half

of the exporting capacity of each CHP resource should be modeled as non-

dispatchable. In the absence of empirical data, the Commission should assume

that all CHP capacity is dispatchable.

R.16-02-007 L. Jan Reid


If it were incorrectly assumed that 50% of CHP resources are non-

dispatchable, then ratepayers would be subject to unnecessary procurement costs

as a result of a faulty assumption. Public Utilities Code Section 451 requires that

the Commission establish rates that are just and reasonable. It is not possible for

the Commission to establish just and reasonable rates if the underlying costs are

not just and reasonable. It is not possible for the underlying costs to be just and

reasonable if ratepayers are required to pay for unnecessary procurement costs.

B. Energy Storage

The Ruling states that: (Attachment A, pp. 19-20)

Unless otherwise noted via the IOUs’ energy storage Applications, CPUC staff has assumed that 40% of the megawatts associated with transmission-connected and distribution-connected projects will provide two-hour storage, 40% of these projects’ megawatts will provide four-hour storage, and the remaining 20% will pro-vide six-hour storage. For energy storage projects connected on the “customer-side” - that is, behind-the-meter - CPUC staff assumes that 50% of these projects’ megawatts will provide two-hour storage and 50% will provide four-hour storage.

The meaning of the phrase “Unless otherwise noted via the IOUs’ energy

storage Applications” (Ruling, Attachment A, p. 19) is unclear and should be

clarified by the Commission. Does the ED propose that the IOUs would deter-

mine the percentages of different types of storage which are to be procured? If

yes, that would constitute a potentially unlawful transfer of regulatory authority

from the Commission to the IOUs.

R.16-02-007 L. Jan Reid


The Energy Division’s (ED’s) recommendations are apparently based on

Table 4 in Attachment A of the Ruling. (Ruling, Attachment A, p. 21) I do not

believe that all of the data in Table 4 is accurate. The ED implies that the data is

based on Decision (D.) 13-10-040. Table 4 indicates that the Commission has

established a goal of 218 MW of transmission-connected storage be 2-hour stor-

age and 218 MW be 4-hour storage. I have reviewed D.13-10-040 and the num-

ber “218” does not appear in the decision.

Since the ED’s recommendations are apparently not based on empirical

data, I recommend that the Commission base its Energy Storage assumptions on

bids received by the IOUs in their 2016 and 2017 Energy Storage Request for

Offers (RFOs).

PG&E last completed an Energy Storage RFO in 2015. PG&E received 215

bids in this solicitation for a total of 5,941 megawatts (MW) of capacity. Of the

5,941 MW, PG&E received bids totaling 468 MW (8%) for less than one-hour stor-

age, 285 MW (5%) for 1.00-1.99 hour storage, 313 MW (5%) for 2.00-2.99 hour

storage, 92 MW (2%) for 3.00-3.99 hour storage, 4,526 MW (78%) for 4-5 hour

storage, and 173 MW (3%) for 6-10 hour storage.2

Thus, if the Commission were to base its assumptions on PG&E’s 2015

RFO, it would assume that approximately 18% of energy storage would be for 2-

hour storage; 78% of energy storage would be for 4-hour storage; and 4% would

be for 6-hour storage.

____________________

2 Percentages do not total 100% due to rounding.

R.16-02-007 L. Jan Reid


Bids were submitted to PG&E’s RFO on January 31, 2017. The Commis-

sion has noted that “SDG&E is currently in the process of soliciting energy stor-

age resources via their All-Source RFO.” (D.16-01-032, slip op. at 14-15)

C. Plant Retirement Assumptions

The Ruling states that: (Attachment A, p. 37)

A “Low” level of retirement assumes that “Other” resource types stay online unless there is an announced retirement date. A “Mid” level assumes a retirement schedule based on resource age of 40 years or more. A “High” level assumes a retirement schedule based on resource age of 25 years or more. . . .

“Other” includes all resources whose retirement assumptions are not explicitly described above - for example, peaker and cogenera-tion facilities. The default assumption for planning studies is a “Mid” level of retirement for “Other” resources.

Historically, projections of plant retirements have been inaccurate, overes-

timating the number of plants that will retire in a given year. Uneconomic plants

and aging plants are often repowered, thereby extending their useful life. For

example, the Moss Landing plant was originally scheduled to be retired by

December 31, 2017. As a result of a settlement agreement between Dynegy (the

plant owner) and the State Water Resources Control Board, Dynegy will shut

down Moss Landing units 6 and 7 and continue operating units 1 and 2. (See

Ruling, Attachment A, p. 36)

Therefore, I recommend that a “Low" level of retirement be used when

modeling “Other” resources.

V. Searchable PDF Files

In part, Rule 1.10(c) of the Commission’s Rules of Practice and Procedure

states that “Documents must be in readable, downloadable, printable, and

searchable formats, unless use of such formats is infeasible.” The PDF file that

R.16-02-007 L. Jan Reid


contains the Ruling is not fully searchable. For example, although a word search

for “procurement” shows it on pages 7 and 20 of Attachment A, the word also

appears on pages 8, 9, 15, and 19 but does not show up in a word search.

It appears that pages 8-19 of Attachment A are not searchable. This could

have been caused by combining a non-searchable PDF file with a PDF/A file. In

order to prevent this problem in the future, I recommend that the following

method be used:

1. Create a single .doc file that contains the document.

2. Print the file to a PDF/A file so that the entire file will be searchable.

VI. Conclusion

The Commission should adopt Reid’s recommendations for the reasons

given herein.

* * *

Dated February 3, 2017, at Santa Cruz, California.

/s/ L. Jan Reid 3185 Gross Road Santa Cruz, CA 95062 Tel/FAX (831) 476-5700 [email protected]

R.16-02-007 L. Jan Reid

VERIFICATION

I, L. Jan Reid, make this verification on my behalf. The statements in the

foregoing document are true to the best of my knowledge, except for those mat-

ters that are stated on information and belief, and as to those matters I believe

them to be true.

I declare under penalty of perjury that the foregoing is true and correct.

Dated February 3, 2017, at Santa Cruz, California.

/s/ L. Jan Reid 3185 Gross Road Santa Cruz, CA 95062 Tel/FAX (831) 476-5700 [email protected]

1


COMMENTS OF LS POWER DEVELOPMENT, LLC ON 2017 LTPP ASSUMPTIONS

Sandeep Arora Vice President, Transmission LS POWER DEVELOPMENT, LLC Address: 5000 Hopyard Rd, Suite 480 Pleasanton CA

Telephone: (925) 201 5252 Fax: (925) 201 5230 Email: [email protected] Feb 3, 2017


Rulemaking 16-02-007 (Filed Feb 11, 2016)

2


COMMENTS OF LS POWER DEVELOPMENT, LLC ON 2017 LTPP ASSUMPTIONS

In accordance with Rules of Practice and Procedure of the California Public Utilities

Commission (“Commission”), LS Power Development, LLC (“LS Power”) hereby submits these

reply comments on the Administrative Law Judge’s Ruling Seeking Comment on Assumptions

and One Scenario for use in Long Term Planning on January 18, 2017 (“Ruling”). Please note

that LS Power’s comments and reply comments are focused on the recommendation to use only

one scenario and RPS assumptions for this scenario, and the dispatch assumptions for storage

resources.

COMMENTS

(1) Use of One Scenario for the Study with only 33% RPS

The ALJ ruling states that based on joint agreement between CAISO, CEC and CPUC

only a 33% RPS scenario will be studied, and no RPS-related policy-driven analysis to identify

new infrastructure needs beyond 33% RPS will be considered for the CAISO 2017-18

Transmission Planning cycle.

LS Power respectively disagrees with this approach. The 2017-18 transmission planning

cycle uses a 10 year out planning case, which will be the 2027 case. While the 50% RPS

requirements are for the planning year 2030 there are other interim requirements, namely 40%


Rulemaking 16-02-007 (Filed Feb 11, 2016)

3

RPS by 2024 and 45% RPS by 2027. Clearly both these requirements are within the 10 year

planning horizon. In the same manner that all other planning assumptions are modelled for a 10

year out case such as new generation additions, existing generation retirements, OTC

assumptions, etc., these interim RPS goals should be also modelled to make the study more

reflective of the expected system conditions and more useful. Failure to consider these interim

RPS requirements that clearly fall within the 10 year planning horizon would not be prudent

planning, particularly given the long lead time to develop and construct new assets. We

understand that there are discussions ongoing in regards to the resource and location mix for the

50% RPS portfolio and before a 50% RPS portfolio is finalized Commission cannot recommend

using it for the CAISO TPP process. At the same time, we also believe that not modelling any

incremental RPS beyond 2020 would make this planning cycle less valuable and the findings

will look more or less like the 2016-17 TPP cycle. This would delay making decisions on any

infrastructure needs that the grid may have to support the 2024 and 2027 interim targets which

could eventually pose reliability risks and increase ratepayer costs. We strongly recommend that

CAISO, CPUC and CEC should reconsider this joint decision and the Commission should

propose draft portfolios to include interim 40% and 45% RPS targets which should be used as

inputs into this planning cycle.

(2) Dispatch assumptions for Storage

One of the assumptions proposed to be used for CAISO 2017-18 TPP study is that all

1325 MW of mandated storage should be modelled dispatchable and providing Resource

Adequacy and Flexibility attributes.

LS Power believes that this assumption is not completely accurate. While a significant

portion of Transmission connected storage should be able to provide these attributes and be

disptachable by CAISO, but most Customer side (or Behind the Meter) and some Distribution

side storage will not be dispatchable by CAISO. Using the attributes as currently proposed from

all storage resources will mask the overall grid flexibility needs, which could pose reliability

risks, more renewable curtailments and potentially cause increased ratepayer costs down the line

to address this. We recommend that only a small portion of Customer side and Distribution side

resources should be assumed flexible for the purpose of following CAISO dispatch instructions.

4

LS Power appreciates the opportunity to submit these comments.



By __/s/ Sandeep Arora__________________________ Name: Sandeep Arora Title: Vice President, Transmission LS POWER DEVELOPMENT, LLC

Address: 5000 Hopyard Rd, Suite 480 Pleasanton, CA

Telephone: (925) 201 5252 Fax: (925) 201 5230 Email: [email protected]





OPENING COMMENTS OF THE NATURAL RESOURCES DEFENSE COUNCIL (NRDC) ON ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON

ASSUMPTIONS AND ONE SCENARIO FOR USE IN LONG TERM PLANNING IN 2017

February 3, 2017

Mohit Chhabra Merrian Borgeson

Carl Zichella Natural Resources Defense Council

111 Sutter St., 20th Floor San Francisco, CA 94104

(415) 875-6100 [email protected]

1


Order Instituting Rulemaking to Develop an Electricity Integrated Resource Planning Framework and to Coordinate and Refine Long-Term Procurement Planning Requirements



OPENING COMMENTS OF THE NATURAL RESOURCES DEFENSE COUNCIL

(NRDC) ON ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON ASSUMPTIONS AND ONE SCENARIO FOR USE IN LONG TERM PLANNING IN 2017 I. Introduction

The Natural Resources Defense Council (NRDC) respectfully submits these comments in response to the Administrative Law Judge’s Ruling Seeking Comment on Assumptions and One Scenario for Use in Long Term Planning released on January 18, 2017. NRDC is a non-profit membership organization with more than 70,000 California members who have an interest in receiving affordable energy services while reducing the environmental impact of California’s energy use. NRDC’s comments are focused in two areas:

Energy efficiency (EE) inputs: The proposed 2017 Assumptions and Scenario for Long Term Planning (LTP) need to be (1) aligned with SB350’s requirements and (2) be considered at the appropriate locational granularity.

Longer term IRP TPP considerations: NRDC recommends moving to a master planning approach that identifies transmission lines with multiple values. The Midcontinent Independent System Operator (MISO) already utilizes such an approach; we believe this approach could be customized to meet California’s needs and the criteria used in this process readily incorporated into the IRP process.

II. Energy Efficiency Inputs

The proposed 2017 Assumptions and Scenario for LTP assume Mid-Baseline-Mid-AAEE level savings1. NRDC recommends that the amount of EE being considered in the LTP scenario be compliant with SB350 requirements2. Not accounting for the expected EE savings potential may lead to over estimation of local and regional resource requirements among other inaccuracies. NRDC understands that an interpretation of SB350 compliant EE potential is being developed at the CEC and that future LTP studies plan to use that CEC interpretation as the EE savings potential input. However, NRDC would like to note that including a doubling of the Mid- 1 Draft 2017 Assumptions and Scenario for Long Term Planning, Section 3.1.4. 2 Specifically, SB350’s requirement of doubling cumulative energy efficiency goals by 2030 should be met by doubling annual incremental energy savings potential in each year. The energy efficiency included in the TPP modeling scenario should include IOU and POU AAEE savings.

2

AAEE savings potential as an input to the current LTP process is bound to be closer to the interpretation of SB350 that CEC develops than the current proposed assumption of simply using Mid-AAEE level savings potential. In addition, Section 3.1.2 of the Assumptions and Scenario’s proposal states that “Efforts are underway to further refine the locational certainty of all BTM demand-side resources, to the transmission substation level so that capacity benefit provided by these resources can be appropriately counted on as a potential alternative to local conventional generation.” Although NRDC supports the effort to account for EE savings at granular locational levels, NRDC would advise caution against accounting for potential EE savings at a substation or even climate zone level for the 2017 analysis. Data do not (yet) exist to support applying Mid-AAEE savings potential estimates at a level more granular than IOU-Sector. AAEE potential is broken down to climate zone levels by the Potential Goals and Targets model using reasonable assumptions of population and measure availability; although this is useful and illustrative, these estimates are not reliable at a local level for TPP. Majority of the data that inform the inputs to the current Potential Goals and Targets study (e.g., baseline studies, recent program evaluations, measure savings estimates etc.) are reliable only at the IOU and Sector levels. NRDC supports efforts to further refine locational certainty of EE modeling, but localized assumptions should not be used until these improvements are developed and tested. III. Long Term TPP Considerations: Adopt a Master Planning Approach that Identifies

Transmission Lines with Multiple Values

NRDC recommends that the Commission and CAISO refocus TPP efforts on a master planning approach that identifies transmission lines with multiple values. This is not a novel approach. At least one other ISO utilizes a form of such an approach: the Midcontinent Independent System Operator (MISO). We believe this approach could be customized to meet California’s needs and the criteria used in this process could be readily incorporated into the Integrated Resource Planning process.

A. Align agency planning processes to prioritize transmission to new and existing high-potential areas

California transmission planning realignment should prioritize the planning and approval for transmission projects that meet multi-value tests and serve identified present and future CREZ (Competitive Renewable Energy Zone), BLM solar zones, San Joaquin Valley least conflict areas, and DRECP resource areas. Focusing on transmission that serves broader system benefits and opens new high priority, low-conflict areas and which meet present and expected future greenhouse gas reduction and reliable electricity supply should be the method we use going forward. Aligning how the agencies coordinate to identify these CREZ and their transmission solutions should be a high priority. NRDC would prefer to see a more unified approach rather than the planning hand-offs we currently see in the project portfolio approach we now use. We greatly appreciate the increased level of coordination between the CPUC, CEC and CAISO we have seen in recent years. We also believe this can be improved upon and simplified by using the master planning, multi-value transmission approval process.

3

B. The Multi-Value Transmission Planning Approach

The approach is used by the MISO to identify and build transmission with multiple values allows them to more easily integrate renewable (mainly wind) energy into their footprint. Our recommendation also builds on the original goals of the Renewable Energy Transmission Initiative (RETI) which sought to “meet California’s renewable energy goals most cost effectively, with the least impact to the environment, in a reliable manner.” The rationale for the MISO approach is described as “Public policy decisions over the last decade have driven changes in how the transmission system is planned. The recent adoption of Renewable Portfolio Standards (RPS) and clean energy goals across the MISO footprint have driven the need for a more regional and robust transmission system to deliver renewable resources from often remote renewable energy generators to load centers3”.

Figure 1 MISO states with RPS mandates and goals, Multi Value Project, Portfolio Results and Analyses, MISO January 10, 2012 The MISO approach aims to meet state and national policy objectives such as:

Reduces greenhouse gas emissions, reduces air pollution, supports economic development in targeted communities

Serve present and planned future renewable energy zones

Can be expanded (adding a circuit, re-conductoring or increasing the transfer capacity (ATC) with more efficient conductors, etc.) within existing corridors to facilitate rapid and strategic expansion

Minimize land use, cultural and wildlife conflicts

Provide access to constrained grid assets that help optimize grid operations (such as pumped hydroelectricity storage

3 See: Multi Value Project, Portfolio Results and Analyses, MISO, January 10, 2012 for a full description of the drivers, proposed lines and related analysis.

4

Provide access to regional renewable resources with uncorrelated variability to California resources (geographic diversity as an integration strategy)

Support regional grid coordination and sharing of reserves

Enhance system reliability

Improve power flows

More efficiently utilize the existing transmission system and avoids environmental conflicts

MISO’s approach identifies lines that meet financial, policy, and system reliability needs, such as:

Provide benefits in excess of its costs under all scenarios studied, with its benefit to cost ratio ranging from 1.8 to 3.0.

Maintain system reliability by resolving reliability violations on approximately 650 elements for more than 6,700 system conditions and mitigating 31 system instability conditions.

Enable 41 million MWh of wind energy per year to meet renewable energy mandates and goals

Provide an average annual value of $1,279 million over the first 40 years of service, at an average annual revenue requirement of $624 million.

Support a variety of generation policies by using a set of energy zones which support wind, natural gas and other fuel sources

Metrics similar to these but based upon California’s specific needs could provide a foundation for a multi-value master planned approach in this state. A master planning approach would consider values beyond the purely electrical system needs traditionally utilized by the CPUC to justify the need for new transmission. These help identify and prioritize present and future competitive renewable energy zones for transmission service and could include:

Economic development and job creation in financially distressed part of the state

Facilitating renewable energy development on chemically altered and marginally productive agricultural lands being retired from cropping, such as those in the west side of the Westlands Water District

Concentrating renewable energy development on the least environmentally sensitive lands

Mitigate pollution in impacted communities

Reducing water consumption by retiring irrigated, chemically altered, and marginally productive agricultural lands

Planning for the long term conservation of other prime farmlands

Avoiding impacts to and preserving cultural resources

Master planning takes a longer term view than is characteristic for transmission planning; where three to five year looks-forward are the norm (as in California). However, California’s climate goals (80% reduction in GHG emissions from 1990 levels by 2050), which will require a fundamental restructuring of the electrical sector, requires flexible planning for more than 30 years

5

into the future. While it is impossible to predict with certainty what electricity generation and load should look like in 2050, by planning to serve present and future renewable energy zones, new transmission lines or upgrades can be scaled to meet California’s zero emission needs under a variety of plausible futures. In so doing we can design a transmission system that is not just least cost, but best fit, in the sense that the developments made could be used to support expansions in renewable power generation where we want it (least environmentally sensitive locations), when we need it, without having to identify, permit and construct duplicative or unnecessary rights of ways and transmission lines.

C. Master Planning Zones and Transmission

Using geospatial information in a RETI-like analysis to identify additional CREZ, especially in the San Joaquin Valley on retired agricultural land, and then performing CEQA (California Environmental Quality Act) and NEPA (National Environmental Policy Act) analysis and permitting on these lands could greatly enhance the original RETI concept. Areas which have already been subject to environmental review, and for which mitigation burdens were known in advance (if required at all) would be highly desirable for developers. The greater certainty that projects could be quickly brought on line, and that transmission would be made available in a timely way should greatly enhance access to low cost project financing. This in turn enables generators to bid into RFOs at lower costs. By planning transmission such that its transfer capacity can be expanded, these future CREZ can be served at least cost to consumers and reduce power costs for procuring entities. IV. Conclusion

NRDC appreciates the opportunity to comment on LTP process regarding CAISO’s Transmission Planning Process. Dated: February 3, 2017 Respectfully submitted,

Mohit Chhabra, Scientist Natural Resources Defense Council 111 Sutter St., 20th Floor San Francisco, CA 94104 (415) 875-6100 [email protected]




Rulemaking 16-02-007 (Filed February 11, 2016 )

NRG ENERGY, INC. COMMENTS ON ASSUMPTIONS AND SCENARIO

FOR USE IN LONG TERM PLANNING IN 2017

NRG ENERGY, INC. Brian D. Theaker Director, Regulatory Affairs 100 California, Suite 400 San Francisco, CA 94111 Telephone: (530) 295-3305 Email: [email protected]


1





NRG ENERGY, INC. COMMENTS ON ASSUMPTIONS AND SCENARIO


In accordance with the Administrative Law Judge Julie Fitch’s January 18, 2017

Administrative Law Judge’s Ruling Seeking Comment on Assumptions and One Scenario For

Use in Long Term Planning in 2017 (“Ruling”), NRG Energy, Inc.1 (“NRG”) hereby submits

these comments on the Draft 2017 Assumptions and Scenario for Long-Term Planning, which

was attached to ALJ Fitch’s Ruling.

1 NRG Energy, Inc. is the parent of NRG Power Marketing LLC, GenOn Energy Management, LLC, Cabrillo Power I LLC, Cabrillo Power II LLC, El Segundo Power LLC, NRG Delta LLC, NRG Marsh Landing LLC, NRG California South LP, High Plains Ranch II, LLC, Long Beach Generation LLC, NRG Solar Alpine LLC, NRG Solar Borrego I LLC, NRG Solar Blythe LLC, NRG Solar Roadrunner LLC and Avenal Solar Holdings LLC, each of which owns and operates or markets generating resources in California. Because the focus of this proceeding is on California issues, NRG Energy, Inc. appears on behalf of these entities.

2

I. COMMENTS

The Draft 2017 Assumptions and Scenario for Long-Term Planning includes this

paragraph (at page 38, footnotes omitted):

From a technical and operational perspective, the Long Beach peaker plants can remain in operation at least through 2025 due to recent refurbishments. These peaker plants’ economic lifespan, however, depends on whether this facility can successfully re-contract once its current contract expires in 2017. The planning assumptions in studies informing D.14-03-004 and the 2015-16 CAISO TPP assumed that the Long Beach Peakers would retire at the end of its current contract. In contrast, the retirement assumptions specified in the Rulings on 2014 LTPP planning assumptions dated March 4, 2015 assumed that the Long Beach Peakers would remain online at least through 2025. The May 2016 LTPP A&S assumed [ ] that the Long Beach Peakers would retire by December 31, 2047, which is a date based on the year (2007) these peakers were refurbished and our “Mid” level 40 year lifespan assumption.

The assumption that the Long Beach peakers would remain in service beyond the

expiration of their current contract (e.g., until 2047) is questionable. Given the current low

wholesale energy and ancillary service revenues, it is unlikely that any conventional resource

will remain in operation unless it is under some form of contract that provides additional (e.g.,

longer-term capacity) revenues. Despite the fact that these resources were refurbished in 2007,

the economic reality is that these units will remain in service only to the extent that they are

contracted for. Accordingly, it is reasonable to revert to the assumption, adopted in D.14-03-004

and used in the 2015-2016 TPP, that the Long Beach peakers will cease operation after their

current contract expires in 2017.

3

Similarly, the Draft 2017 Assumptions and Scenario for Long-Term Planning assumes

that non-renewable generation will remain in operation based on its age.2 As last year’s lay-up

of Calpine’s Sutter facility3 demonstrates, conventional resources are highly unlikely to remain

in long-term operation without contracts.

II. CONCLUSION

NRG appreciates the opportunity to provide these comments.


By /s/ Brian D. Theaker Brian D. Theaker

NRG ENERGY, INC. Brian D. Theaker Director, Regulatory Affairs 100 California, Suite 400 San Francisco, CA 94111 Telephone: 530-295-3305 Email: [email protected]

Date: February 3, 2017

2 Draft 2017 Assumptions and Scenario for Long-Term Planning, page 37: “Retirement assumptions are also based on facility age as a proxy for determining a facility’s operational life. Similarly to renewable and hydro retirement assumptions, the operational history of non-renewable/hydro facilities will not be considered in this planning cycle.” 3 See, e.g., http://www.powermag.com/calpine-to-take-uneconomic-ccgt-plant-offline-in-calif/ .

174257149




THE OFFICE OF RATEPAYER ADVOCATES’ COMMENTS ON ASSUMPTIONS AND ONE SCENARIO


RADU CIUPAGEA MEA HALPERIN XIAN MING (CINDY) LI Analysts for Office of Ratepayer Advocates California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Telephone: (415) 703-5235 Email: [email protected]

MATT MILEY DIANA L. LEE Attorneys for Office of Ratepayer Advocates California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Telephone: (415) 703-3066 Email: [email protected]

February 3, 2017


1

I. INTRODUCTION

The Office of Ratepayer Advocates (ORA) submits the following comments in response

to the January 18, 2017 Administrative Law Judge’s Ruling Seeking Comment on Assumptions

and One Scenario for Use in Long Term Planning in 2017 (Ruling), which invites comments on

“any and all aspects” of the Draft 2017 Assumptions & Scenario Update for Long Term Planning

(A&S Update). The California Public Utilities Commission (Commission) will use the

assumptions and scenario for purposes of long-term electricity planning in 2017, with emphasis

on the California Independent System Operator Corporation’s (CAISO) Transmission Planning

Process (TPP).1 The Ruling also poses one question related to the assumptions and scenario.

ORA generally supports the standard planning assumptions (SPAs) presented in the A&S

Update and the Reliability Scenario that has been proposed for use in the 2017-2018 CAISO

TPP. In response to the Ruling, ORA provides the following comments and recommendations:

The A&S Update and the Reliability Scenario should be used exclusively for the CAISO’s 2017-2018 TPP;

The net exports assumptions should be revised to account for 2000 megawatts (MW) of net exports for the Low-case, 5000 MW for the Mid-case, and 8000 MW for the High-case;

Revisions should be made to the supply side Demand Response (DR) assumptions;

The assumptions for Combined Heat and Power (CHP) resources should be revisited and updated;

Revisions should made to the energy storage planning assumptions;

Renewables Portfolio Standard (RPS) assumptions are reasonable; however, the Commission should ensure that load serving entities (LSEs) do not over-procure resources, which could lead to stranded costs and ratepayer burden; and

Minor edits should be made to the 2017 A&S Update.

1 Ruling, p. 5.

2

II. ORA RESPONSES TO QUESTION POSED IN THE RULING - ARE THE UPDATES TO THE DEMAND-SIDE AND SUPPLY-SIDE ASSUMPTIONS REASONABLE AND ACCURATE? PLEASE SPECIFY ANY ASSUMPTIONS THAT SHOULD BE REVISED AND PROVIDE A DETAILED JUSTIFICATION SUPPORTING THE RECOMMENDED REVISIONS

First, ORA recommends that the A&S Update and the Reliability Scenario should be

used exclusively for the CAISO’s 2017-2018 TPP. Senate Bill (SB) 350 mandates, among other

things, a doubling of Energy Efficiency (EE) and a 50% RPS by 2030. Neither of these two

assumptions is factored into the A&S Update. Although ORA agrees with the rationale for

excluding these two assumptions for the purposes of the 2017-2018 CAISO TPP, the

Commission should clarify that the A&S update should not be used in the Integrated Resource

Planning – Long Term Procurement Plan (IRP-LTPP) studies for capacity need determinations

and/or procurement authorizations. The Ruling states that the A&S Update is “proposed to be

utilized for any long-term resource planning studies that may be needed to support planning in

2017 prior to the Commission adopting formal guidance for the Integrated Resource Planning

(IRP) process”2 and that the Reliability Scenario “is for use in long-term electric system planning

for the state of California.”3 ORA recommends that the final A&S update clarify that the use of

the Reliability Scenario will be limited to the CAISO’s 2017-2018 TPP.

Second, ORA recommends that the net exports assumptions should be revised to

2000 MW for the Low-case, 5000 MW for the Mid-case, and 8000 MW for the High-case.

These revised assumptions are consistent with the numbers used in the CAISO’s

SB 350 Study.4

Third, ORA has reviewed the assumptions for supply-side DR and makes several

recommendations for clarification and accuracy. First, the A&S Update states that information

for utility programs is based on Load Impact Report values for “portfolio-adjusted August 2026

1-in-2 weather year condition ex-ante impacts at CAISO peak.”5 ORA reviewed the DR Load

2 Ruling, p. 2. 3 A&S Update, p. 45. 4 Senate Bill 350 Study, The Impacts of a Regional ISO-Operated Power Market on California, pp. I-4 – I-5, available at https://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=4C17574F-73AE-40E3-942C-59C3A13BBDF1. 5 A&S Update, p. 27.

3

Impact Reports (LI Reports) for each utility under these same conditions and found discrepancies

as summarized in the following table.

Table 1: Discrepancies between A&S Update and Load Impact Reports

Utility Program Table 8 of

A&S Update (MW)

Utility Load Impact Reports

(MW)6

PG&E Capacity Bidding Program (CBP) 120 38

SCE Base Interruptible Program (BIP) 607 602

SCE Agricultural Pumping-Interruptible (AP-I) 63 59

SCE AC Cycling Residential 218 56

SCE Air Conditioning (AC) Cycling Non-residential 40 20

SCE CBP 141 48

ORA recommends that the final 2017 A&S Update clarify DR assumptions by

identifying the exact table of each LI Report used for DR assumptions, explaining any

differences or correcting DR assumptions as needed. In addition, some adjustments to the values

in the LI Reports may be necessary to take into account more recent program developments. For

example, Southern California Edison Company’s (SCE) LI Report states that enrollment in

AC Cycling programs is expected to decline significantly as the program is closed to new

enrollment and phased out, leading to lower estimated impacts in 2026.7 However, SCE’s recent

Application for Approval of its 2018-2022 DR Programs seeks to maintain its AC Cycling

programs, so higher assumptions of DR capacity than estimated for 2026 in the LI Report would

be reasonable.8 The LI Report estimates 54 MW for the non-residential option and 236 MW for

6 Executive Summary: 2016-2026 Demand Response Portfolio of Pacific Gas and Electric Company, April 1, 2016, Table L.11, p. L-12. http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M164/K950/164950894.PDF; Southern California Edison’s 2015 Demand Response Portfolio Summary Report, April 1, 2016, Table G-11, p.108. “Portfolio adjusted” ex-ante values were not included in the report so ORA reviewed the “Portfolio Aggregate” information. http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M164/K174/164174986.PDF 7 Southern California Edison’s 2015 Demand Response Portfolio Summary Report, April 1, 2016, p. 8. 8 SCE A.17-01-018, Testimony In Support of Its Application for Approval of Its 2018 – 2022 Demand Response Programs: Volume 2 – SCE’s 2018 – 2022 Proposed Demand Response Programs by Category, p. 29.

4

the residential option for 2016.9 The Commission should assume that the AC Cycling programs

will continue, similar to the other DR programs, and that there will be at least the same level of

enrollment and load impact in the programs in 2026 as in 2016.

Additionally, the A&S Update includes 124.6 MW for the Demand Response Auction

Mechanism (DRAM).10 This value is based on the sum of the 2017 DRAM auction results for

each utility: 56.2 MW for SCE, 56.4 MW for Pacific Gas and Electric Company (PG&E) and

12 MW for San Diego Gas & Electric Company (SDG&E).11 However, SDG&E has since

procured an additional 8 MW for its 2017 DRAM so the total assumption for DRAM should be

increased to 132.6 MW.12

The A&S Update also assumes that capacity procured through DRAM will participate in

the CAISO market through the Proxy Demand Resource (PDR) mechanism and is not assumed

to respond within 30 minutes.13 However, PDR resources can participate in both the day-ahead

and real-time markets14 and could respond within 30 minutes if cleared in the real-time market.

With increased penetration of renewable resources, it is likely that DR providers with the

capability would choose to participate in the real-time market to provide additional flexibility

and capture additional revenue, particularly by 2026.15 Therefore, the Commission should

assume that at least a portion of the capacity procured through DRAM will respond within

30 minutes. The Commission can estimate DRAM capacity that can respond within 30 minutes

by identifying the expected source of the DR for the DRAM contracts. For example, DR

providers that rely on direct load control devices or storage have the capability for fast response

and their associated capacity can be assumed to respond within 30 minutes. Adoption of a more

9 Southern California Edison’s 2015 Demand Response Portfolio Summary Report, April 1, 2016, Table G-1, p. 98. http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M164/K174/164174986.PDF 10 A&S Update, p. 27. 11 Id., pp. 30-31. 12 SDG&E Advice Letter 3004-E, p. 13. 13 Draft 2017 Assumptions and Scenario for Long Term Planning, p. 27. 14 CAISO PDR & Reliability Demand Response Resource (RDRR) Participation Overview, p. 2. http://www.caiso.com/Documents/PDR_RDRRParticipationOverviewPresentation.pdf 15 CAISO recently implemented its Flexible Ramp Up and Flexible Ramp Down market products, which are intended to incentivize more flexible ramping capability in the 15- and 5-minute markets. http://www.caiso.com/informed/Pages/StakeholderProcesses/CompletedStakeholderProcesses/FlexibleRampingProduct.aspx

5

accurate value for DR capacity that can respond within 30 minutes will ensure that DR is

counted towards meeting local capacity reliability needs and avoid the need for unnecessary

additional procurement.

Fourth, the assumptions for CHP resources have not changed from the 2014 Long Term

Procurement Planning (LTPP) ruling. However, ORA questions the modeling assumption that

“one half of exporting CHP capacity of each CHP resource … should be modeled as

non-dispatchable resources. … [T]he remaining half of the exporting capacity of each CHP

resource will be assumed to be resources that are dispatchable by the CAISO.”16 This

assumption is based on the difference between the minimum load of a CHP resource, which is

presumed to be used entirely for the operation of the resource, and the maximum load, which

will be dispatched into the CAISO market. The total sum minimum load is one-half of the total

sum of maximum load. This breakdown is based on 2011 data. ORA only came to understand

these assumptions based on conversations with Energy Division staff because the rationales for

the assumptions were not clearly based on the text of the A&S Update. ORA recommends that

the CPUC clarify these terms in the A&S Update, and recalculate the CHP data based on newer

maximum and minimum load values.

Fifth, the A&S Update identifies assumptions for energy storage that have not changed

from the 2014 LTPP ruling. The A&S Update states:

Unless otherwise noted via the IOUs’ energy storage Applications, CPUC staff has assumed that 40% of the megawatts associated with transmission‐connected and distribution‐connected projects will provide two‐hour storage, 40% of these projects’ megawatts will provide four‐hour storage, and the remaining 20% will provide six‐hour storage. For energy storage projects connected on the ’customer‐side’ – that is, behind‐the‐meter – CPUC staff assumes that 50% of these projects’ megawatts will provide two‐hour storage and 50% will provide four‐hour storage.[17]

ORA questions whether these assumptions are appropriate. ORA investigated existing

and planned energy storage projects to see the current distribution of service hours per category

of projects and found inconsistencies. Very few storage projects, either customer-side or

transmission-distribution-side, provide two hours of storage, let alone 40-50%. Furthermore,

16 A&S Update, p. 19. 17 A&S Update, pp. 19-20.

6

there are a significant number of projects that provide three- and seven-hour storage.18 There

have been an increased number of storage contracts between 2014 and 2017. It is possible that

assumptions that were reasonable in 2014 are now out of date and worthy of re-examination.

ORA recommends that the Commission revisit the inputs that contributed to these assumptions

and either update them or explain how the Commission reached this conclusion.

ORA also recommends that the Commission clarify how Permanent Load Shifting (PLS)

resources will be modeled in IRP. Currently, the investor-owned utilities (IOU) have procured a

number of PLS storage contracts under their Local Capacity Requirement (LCR) Request for

Offers (RFO). These resources contribute to the IOUs’ energy storage targets but they do not

behave in the same manner as other “customer-side” storage resources. PLS storage is not

connected to the grid, but rather permanently offsets a customer’s load from peak hours to

non-peak times. Because of this function, it is not a supply-side resource, but it is also not a

conventional demand-side resource. ORA is aware that PLS resources are included in the

demand forecast of the Integrated Energy Policy Report (IEPR) but recommends that the

Commission provide clarity on how PLS resources will be included in IRP models.

Sixth, the assumptions provided for RPS portfolios include the statement, “IOUs under

CPUC jurisdiction for purposes of compliance with the states [sic] RPS program are generally

long on RPS resources and may not require much additional procurement, if any, to achieve their

50% targets by 2030.”19 Additionally, “no new RPS portfolios are specified this year for

additional resources needed to meet RPS goals.”20 ORA finds these assumptions for RPS

portfolios reasonable.

However, it is worth noting that a significant contributing factor to the IOUs’ long RPS

position is the departure of bundled customers to community choice aggregators (CCAs) and

direct access (DA) programs. While the IOUs are on track to meet their RPS goals, future load

serving entities (LSEs) will be required to provide IRP portfolios to the Commission and will

have their own RPS targets to meet. Through the IRP process, the Commission should ensure

18 Local Capacity Requirement Request for Offers from PG&E (A.15-12-004), SCE (A.15-12-003), and SDG&E (A.16-03-014). 19 Id., p. 32. 20 Id.

7

that in the effort to meet 50% RPS goals, the IOUs do not over-procure resources, which could

burden ratepayers with stranded costs.

Finally, although the 2017 A&S Update is similar to the 2016 A&S Update, some of the

language carried over from the 2016 A&S Update should be removed from the final 2017 A&S

Update. For example, the following reference should be removed because it refers to a scenario

that is no longer included in the 2017 A&S Update:

The net export constraint assumed by modelers should be set at the Mid-case in all but the Interregional Coordination Scenario. For the Interregional Coordination Scenario, the net export constraint should be set at the High-case.[21]

Also, footnote 60 should be updated to reflect 2017 import capability.22 Lastly, the

reference to the 2016-2017 TPP modeling, at page 18, should be revised to state 2017-2018 TPP.

III. CONCLUSION

ORA respectfully requests that the Commission incorporate these recommendations into

the Assumptions and Scenarios to be used in the CAISO’s 2017-2018 TPP.

Respectfully submitted, /s/ MATT MILEY ___________________________

Matt Miley Attorney for

Office for Ratepayer Advocates California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Telephone: (415) 703-3066

February 3, 2017 E-mail: [email protected]

21 A&S Update, p. 39. 22 Id., p. 38.

BEFORE THE

PUBLIC UTILITIES COMMISSION


Order Instituting Rulemaking to Develop an

Electricity Integrated Resource Planning

Framework and to Coordinate and Refine

Long-Term Procurement Planning

Requirements

R.16-02-007


COMMENTS OF

PACIFIC GAS AND ELECTRIC COMPANY (U 39 E)

ON 2017-2018 TRANSMISSION PLANNING PROCESS

SCENARIO AND ASSUMPTIONS

CHARLES R. MIDDLEKAUFF

Pacific Gas and Electric Company

77 Beale Street, B30A

San Francisco, CA 94105

Telephone: (415) 973-6971

Facsimile: (415) 973-5520

E-Mail: [email protected]

Attorney for

PACIFIC GAS AND ELECTRIC COMPANY


BEFORE THE

PUBLIC UTILITIES COMMISSION






Requirements

R.16-02-007


COMMENTS OF

PACIFIC GAS AND ELECTRIC COMPANY (U 39 E)

ON 2017-2018 TRANSMISSION PLANNING PROCESS

SCENARIO AND ASSUMPTIONS

Pursuant to a January 18, 2017 ruling (“Ruling”) of the Administrative Law Judge

requesting comments on the staff’s proposed assumptions and scenario (“Reliability Scenario”)

for use in the California Independent System Operator’s (“CAISO”) transmission planning

process (“TPP”), Pacific Gas and Electric Company (“PG&E”) respectfully provides general

comments and responses to questions contained in the Ruling.

I. GENERAL COMMENTS

PG&E offers the following general comments on the Reliability Scenario. First, PG&E

appreciates the information provided in Section 4.1 (“2017 Planning Scenario – Reliability

Scenario”) of the document attached to the Ruling explaining that the Reliability Scenario does

not include renewables in excess of a 33 percent Renewable Portfolio Standard (“RPS”) level

because it would be inappropriate to plan for transmission expansion investment without

studying alternative renewable portfolios and other policy choices needed to satisfy Senate Bill

(“SB”) 350 requirements. This context is helpful for parties to comment on whether the

proposed changes in assumptions are reasonable or accurate. Therefore, for purposes of

preparing its comments, PG&E assumes that the Reliability Scenario is intended for the CAISO

2

to develop a no regrets transmission plan, before additional RPS generation is added to satisfy

SB 350 requirements.

Second, PG&E also asks for clarification about the interactions between this TPP study

and CAISO’s reliability work as part of the California Public Utilities Commission’s

(“Commission”) long-term procurement plan (“LTPP”) and integrated resource planning (“IRP”)

proceeding. In the future, PG&E anticipates increased need for coordination among state

agencies and an approach that integrates and adjusts their existing planning functions in an effort

to develop an integrate plan for the state. For example, PG&E expects that the CAISO will

continue to participate in the LTPP/IRP process by reviewing the reliability need (system, local,

and operating flexibility) of the Commission-determined Preferred or Reference System Plan,

and at some point prepare an update to the TPP that reflects the multi-LSE optimal portfolio

(“Reference System Plan”) produced by the IRP process.1 In addition, future California Energy

Commission (“CEC”) load forecasts should also reflect the demand-side resources that are found

to be least-cost best-fit in the prior IRP process.

II. RESPONSE TO QUESTION

PG&E offers the following response to the question “Are the updates to the demand-side

and supply-side assumptions reasonable and accurate?” asked by the ALJ regarding the single

Reliability Scenario. PG&E’s response is provided by type of assumption.

A. Demand-Side Assumptions

1. Load: The updates to the CED 2015 load forecast discussed in Section 3.1.3

seem reasonable for the Reliability Scenario, and in particular the “peak

shift” due to the increased behind the meter Photovoltaics (“BTMPV”)

penetration.

1 CPUC Staff Concept Paper of August 11, 2016, Figure 3.

3

2. Energy Efficiency: PG&E supports the planning assumptions included for

Energy Efficiency (“EE”). These include: (1) the deferral of incorporation of

SB 350 EE impacts until after the CEC has established SB 350 EE targets,

which is currently underway; and (2) the incorporation of EE load shapes and

the peak shift, which will better align EE impacts with current peak

conditions.2 However, PG&E recommends using, for this TPP only, a mid-

baseline-mid-AAEE for both system-level studies and local reliability

studies. This is to account for the omission of higher levels of EE due to

SB 350, which is very likely to increase EE goals and savings once SB 350

EE targets are established.

3. Solar Photovoltaics: PG&E supports the change in modeling of BTMPV

discussed in Section 3.1.5 as a supply resource for reliability studies, rather

than as a demand side adjustment. This change will allow modelers to

represent the “peak shift” effect due to increased BTMPV penetration, and

more accurately measure BTMPV’s reliability contribution, compared to

today’s reduction to gross peak demand measure. PG&E recommends that

the scenario which includes this “peak shift” be the base scenario for this

TPP, rather than used as an alternative scenario as suggested in the scenario

documentation attached to the Ruling.

4. Demand Response: The assumptions presented in Section 3.1.7 are

consistent with PG&E’s understanding of load modifying Demand Response

(“DR”). As recognized in the assumption, the move towards defaulting

residential customers to time-of-use (“TOU”) rates in the next few years may

have a significant impact. At the same time, anticipated load loss due to

CCA/DA growth may temper that impact, as such growth directly reduces

customer eligibility and load impacts for TOU rates and critical peak pricing

programs, unless Community Choice Aggregators (“CCAs”) offer the same

programs or customers choose to opt out of CCAs.

B. Supply-Side Assumptions

1. Resource representation: PG&E supports the change from the current

exceedance method to an Effective Load Carrying Capability (“ELCC”)

method to estimate the system reliability contribution of wind and solar

generation, whether resources are located in front or behind the meter.3 The

ELCC more accurately estimate these resources’ contribution to system

2 Current EE measure peak values use outdated peak hours to define peak impacts. Using EE

energy savings values (kwh), EE load shapes, and updated peak values will correct for this in the 2017-18

TPP. Additional background on this issue can be found in PG&E’s Energy Efficiency Business Plan, at

page 47: http://prccappiiswc002/Docs/EnergyEfficiency2018-2025-

RollingPortfolioBusinessPlan/Pleadings/PGE/2017/EnergyEfficiency2018-2025-

RollingPortfolioBusinessPlan_Plea_PGE_20170117_399327.pdf.

3 Reliability Scenario documentation, p. 18.

4

reliability. For local reliability, an exceedance method can be used provided

that it is based on the resource’s contribution to local net load (gross load less

wind and solar generation), whether solar is in front or behind the meter.

2. Energy Storage: Section 3.2.4 states that all 1,325 megawatts (“MW”) of

storage, regardless of whether it is interconnected at transmission,

distribution, or customer connected, should be assumed to be dispatchable,

provide operational flexibility services, and count for resource adequacy

(“RA”) purposes. The Reliability Scenario documentation provides no

explanation for the change in reliability counting of storage. It is therefore

difficult to understand why such a change is reasonable without additional

explanation. Further, PG&E suggests assuming 100% of behind-the-meter

(“BTM”) storage to have two-hour duration for this planning cycle, as this is

the predominant duration of BTM storage seen in the market today.

3. Demand Response: The assumptions presented in Section 3.2.5 are

consistent with PG&E’s understanding of supply resource DR. The

integration of DR programs into the CAISO’s market by May 2017 for

Reliability Demand Response Resource (“RDRR”) and January 2018 for

Proxy Demand Resource (“PDR”) is transitioning the bulk of DR MW from

load modifying to supply resource DR. Therefore, the dispatch assumptions

listed on page 29 for RDRR and PDR appear reasonable. With respect to the

Demand Response Auction Mechanism (“DRAM”) MWs, the stated value of

124.6 MW is reasonable for the 2017 period. However, it should be noted

that if the DRAM pilot transitions to a permanent program by 2020, as

anticipated, the CPUC has initially stated that the target level could be up to

One GW per year across the three IOUs. See D.16-09-056, Ordering

Paragraph 12.

4. RPS Portfolios: To better integrate the planning efforts of the Commission

and CAISO, PG&E agrees that the 2018-19 TPP should incorporate the

results of the IRP process.4 Additionally, the previous updates to the RPS

Calculator to estimate the cost-effective levels of transmission investment

needed – based on allowing both Full Capacity Deliverability Status and

energy-only RPS resources – should continue through the IRP process. This

functionality is required to properly supplement the transmission planning

function previously provided by the RPS Calculator. Since the IRP process

may consider higher RPS levels driven by greenhouse gas (“GHG”) planning

targets, it is appropriate to consider how the value of deliverable RPS

resources may compare to other GHG-reducing technologies. This will align

the IRP and TPP processes to determine what – if any – levels of

transmission investment may be required for new RPS resources.

4 Reliability Scenario documentation, p. 32.

5

5. Renewable and Hydro Retirement Assumptions: Previous Commission-

adopted scenarios have included renewable retirements. This year’s

Reliability Scenario documentation states that no renewable retirements are

assumed within the planning horizon. It is difficult to understand why this

change is reasonable without additional explanation. (NOTE: Version 6 of

the RPS Calculator estimates what level of existing RPS resources might be

recontracted versus retired, and may provide a reasonable estimate rather

than assuming no RPS retirements.)




By: /s/ Charles R. Middlekauff


Pacific Gas and Electric Company

77 Beale Street, B30A

San Francisco, CA 94105

Telephone: (415) 973-6971

Facsimile: (415) 973-5520

E-Mail: [email protected]

Attorney for

PACIFIC GAS AND ELECTRIC COMPANY

BEFORE THE PUBLIC UTILIES COMMISSION




PROTECT OUR COMMUNITIES FOUNDATION

COMMENT ON DRAFT 2017 ASSUMPTIONS AND SCENARIO FOR USE IN

LONG TERM PLANNING

Bill Powers P.E. Protect Our Communities Foundation [email protected] April Rose Sommer Executive Director and Lead Counsel Protect Our Communities Foundation 1547 Palos Verdes Mall #196 Walnut Creek, CA 94597 (619) 363-6790 [email protected]

POC Comment 1

BEFORE THE PUBLIC UTILIES COMMISSION




PROTECT OUR COMMUNITIES FOUNDATION

COMMENT ON DRAFT 2017 ASSUMPTIONS AND SCENARIO FOR USE IN

LONG TERM PLANNING

In accordance with the Administrative Law Judge Julie Fitch’s January 18, 2017 ruling,

the Protect Our Communities Foundation (“POC”) submits these comments on the Draft 2017

Assumptions and Scenario for Long-Term Planning (“Draft 2017 A&S”) proposed by California

Public Utilities Commission (“Commission” or PUC) staff for use in long-term planning.

POC is a San Diego County based 501(c)(3) nonprofit dedicated to protecting wild and

rural communities and the people, plants, and animals that inhabit them from destructive, industrial

energy infrastructure development. POC advocates on behalf of Southern California utility

ratepayers against fossil fueled energy development and in support of transition to sustainable

energy systems. POC and its board members, members, and supporters have advocated before the

Commission for the past decade representing the unique perspective of small and medium-sized

communities throughout Southern California.

POC Comment 2

I. Solar Photovoltaics

A. Behind-the-meter PV should be modeled as supply resource

Behind-the-meter (BTM) PV consists of the same solar panels used in utility-scale solar PV

projects. The only difference between rooftop and utility-scale PV systems is the project location

on the transmission and distribution grid. There is therefore, no reason why BTM PV should not

be modeled as s supply resource.

B. Assumed amount of BTM PV in 2030 is low and inconsistent with California

Energy Efficiency Strategic Plan

The Draft 2017 A&S uses the CEDU’s January 2016 CEC Mid-BTM PV case. The CEC

Mid-BTM PV case is low, in terms of installed BTM PV capacity, compared to what would be

needed to conform to the California Energy Efficiency Strategy Plan (CEESP).

In the Draft 2017 A&S, staff assumes, based upon the Mid-BTM PV case, that

approximately 12,000 MW of BTM PV will be online by the end of 2020 and 22,000 MW by the

end of 2026.1 Extrapolating from 2026 to 2030 at a linear rate, approximately 29,000 MW of

BTM PV will be online by 2030.2 As of December 2016 approximately 5,000 MW of BTM PV

was online in California.3

The Mid-BTM PV case assumes an average BTM PV installation rate of about 1,700

MW per year.4 This assumed average BTM PV installation rate through 2030 is comparable to

the actual 2016 BTM PV installation rate in California of 1,500 MW per year.5 But, using the

1 PG&E, Presentation - Behind the Meter Solar PV in CA Load Forecasting and Planning, June 22, 2016, p. 5 (CEC Mid BTM PV case – January 2016). 2 (22,000 MW – 5,000 MW) ÷ 10 years = 1,700 MW per year. 3 California Distributed Generation Statistics: http://www.californiadgstats.ca.gov/. 4 See footnote 2. 5 California Distributed Generation Statistics: http://www.californiadgstats.ca.gov/. Total installed BTM PV at end of 2015 = 3,469 MW. Total installed BTM PV at end of 2015 = 4,975 MW. Therefore, 2016 BTM PV installation rate = 4,975 MW – 3,469 MW = 1,506 MW [Note: The webpage states two different values for total installed BTM

http://www.californiadgstats.ca.gov/

http://www.californiadgstats.ca.gov/

POC Comment 3

Mid-BTM PV case, the BTM PV assumption of 29,000 MW of BTM PV online by 2030, falls

short of the CEESP targets for 2030 of approximately 41,000 MW statewide.

The CEESP was developed through a formal CPUC regulatory process,6 approved in September

2008 and updated in January 2011.7 A primary objective of the Commission in directing the

investor-owned utilities (IOUs) to develop the CEESP was to evolve the Energy Action Plan

policy guidelines into regulatory goals with timelines.

The CEESP includes the energy efficiency and BTM PV targets shown in Table 1:

Table 1. California Energy Efficiency Strategy Plan Goals

Goal Target year (2008 baseline)

1. All new residential construction is zero net energy (ZNE)

2020 2. 25 percent of existing single-family homes achieve 70 percent decrease

in purchased energy 2020

3. 75 percent of existing residential achieves 30 percent decrease in purchased energy

2020

4. 100 percent of multi-family housing achieves a 40 percent decrease in purchased energy

2020

5. All new commercial construction is ZNE

2030 6. 50 percent of existing commercial buildings achieve ZNE

2030 7. Industrial facilities will reduce energy intensity by 25 percent

2020 8. Agricultural operations will reduce production energy intensity by 15

percent 2020

9. 50 percent improvement in efficiency in the heating, ventilation, and air conditioning sector

2020

10. 75 percent improvement in efficiency in the heating, ventilation, and air conditioning sector

2030

PV at the end of 2016: 4,975 MW (IOU and public utilities) and 4,577 MW (IOU only). The higher value is used here to calculate the 2016 BTM PV installation rate.] 6 CPUC Decision D.07-10-032, Interim Opinion on Issues Relating to Future Savings Goals and Program Planning for 2009-2011 Energy Efficiency and Beyond, October 18, 2007, p.5, pp. 10-11. “As a key tool to implement this strategic approach, we direct the utilities to develop a single, statewide IOU strategic plan for energy efficiency through 2020 and beyond . . ..Public Utilities Code Section 454.5(6)(9)(c), the Energy Action Plan and past Commission decisions have established a policy to procure all cost-effective conservation and energy efficiency resources before adding generation resources.” 7 CPUC California Energy Efficiency Strategic Plan webpage: http://www.cpuc.ca.gov/General.aspx?id=4125.

http://www.cpuc.ca.gov/General.aspx?id=4125

POC Comment 4

Achieving these targets by 2020 on residential, multi-family residential, and commercial

structures will require approximately 17,000 MW of BTM PV statewide by 2020.8 To meet

statewide targets of 50 percent ZNE on existing residential and commercial structures by 2030,

assuming a linear expansion of BTM PV over the 2020 to 2030 period, approximately 34,000

MW of BTM PV must be online by 2030.

No PV is assumed in the CEESP for industrial or agricultural loads, only use of energy

efficiency measures to reduce industrial and agricultural demand by 25 percent and 15 percent

respectively by 2020. If this same percentage of incremental reduction is targeted in the 2020 to

2030 timeframe for industrial and agricultural demand, and this reduction is achieved using BTM

PV, approximately 7,000 MW of additional BTM PV will be required by 2030.

Extrapolating the CEESP targets to 2030 for all sectors, the installed BTM PV in

California in 2030 across residential, commercial, industrial, and agricultural customer classes

would be approximately 41,000 MW statewide.9

The Commission should assume compliance with existing and extrapolated 2030 CEESP

targets as base case assumptions for IRP planning purposes.

c. Distribution Grid Upgrade Implications of High Levels of BTM PV

For many years in California, LSEs have been raising concerns that high levels of BTM

PV on distribution circuits would negatively impact grid reliability and require major investment

to address. However, recently available information suggests this may not be the case. A 2015

8 Powers Engineering, Bay Area Smart Energy 2020, Table 10-4, p. 87: http://pacificenvironment.org/downloads/BASE2020_Full_Report.pdf. 9 Installed BTM PV on residential, commercial, industrial, and agricultural sectors in 2030 = 34,000 MW (residential and commercial) + 7,000 MW (industrial and agricultural) = 41,000 MW.

http://pacificenvironment.org/downloads/BASE2020_Full_Report.pdf

POC Comment 5

Haas analysis of the impact of high levels of BTM PV on PG&E distribution circuits

concluded:10

Based on our engineering simulations of PV impacts on distribution circuits, we find PV's impacts on voltage magnitudes and voltage regulator operations are relatively small (Cohen and Callaway, 2013, 2015). If we assume that voltage regulator maintenance scales linearly with the frequency of operation, results in this paper indicate that distributed PV would increase PG&E's annual costs by $442,000 if all circuits in PG&E territory had 100% PV penetration { an extremely small amount of PG&E's roughly $6 billion operations and maintenance budget. Because we do not have circuit-level data from PG&E on voltage maintenance, we are not able to accurately quantify the heterogeneity of PV's impacts on the cost to address voltage issues. However our earlier engineering simulations showed feeder location and design can significantly impact the likelihood that PV will create voltage problems, suggesting that proactive distribution planning may serve to avoid these voltage problems altogether at relatively low cost.

SCE distribution circuits would appear even more amenable to very high penetrations of

BTM PV, as SCE standard distribution substation design includes capacitor banks that facilitate

optimizing voltage across distribution feeders in real time.11 This information is important when

assessing least cost-best fit solutions to achieving 50 percent RPS by 2030, as the high BTM PV

alternative would appear to have low associated transmission and distribution expenditures

relative to alternatives that require an expansion of the transmission system to assure

deliverability.

10 M.A. Cohen, P.A. Kauzmann, D.S. Callaway - Energy Institute at Haas (UC Berkeley), Economic Effects of Distributed PV Generation on California's Distribution System, June 2015, p. 2: http://ei.haas.berkeley.edu/research/papers/wp260.pdf. 11 SCE, 2015 General Rate Case Application Workpapers - Transmission & Distribution System Planning Capitol Projects, SCE-03 Volume 03, Part 01, November 2013, p. 4: http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/7E7226312446DC8488257C22007512A6/$FILE/APP%20SCE-03%20Vol.%2003%20Pt.%2001.pdf. “At all levels of our electric power system, capacitor banks are used to supply needed reactive power to our system and help maintain voltage at adequate levels. These capacitor banks may be installed inside substations (at our A-substations and B-substations) or directly connected to our distribution circuits.”

http://ei.haas.berkeley.edu/research/papers/wp260.pdf

http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/7E7226312446DC8488257C22007512A6/$FILE/APP%20SCE-03%20Vol.%2003%20Pt.%2001.pdf

http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/7E7226312446DC8488257C22007512A6/$FILE/APP%20SCE-03%20Vol.%2003%20Pt.%2001.pdf

POC Comment 6

II. Peak Shift

A. LSE peak load is declining, not increasing

Peak loads have not increased in 10 years in PG&E and SCE territories, and 2016 peak

load in SDG&E territory, 4,262 MW, was the lowest peak in 10 years. This is reflected in the

CAISO control area actual peak load which has been trending downward since the all-time 2006

peak of 50,270 MW.12 In 2016 the CAISO control area 1-hour peak load was 45,849 MW.13 The

CEDU 2016 “clear upward trend in modeled LSE peak load” described on p. 15 of the Draft

2017 Assumptions and Scenario for Long Term Planning is inconsistent with the downward

trend of the last 10 years of actual IOU peak load data. The model should be corrected to

reasonably reflect the well-established downward trend in actual peak load. The model should

also produce an accelerated downward peak load trend as behind-the-meter energy efficiency,

solar PV, and battery storage are increased above the assumptions for these variables in the base

case Reliability Scenario.

B. Modeled LSE peak load does not appear to account for aggressive air-

conditioning load reduction consistent with CEESP 2030 target

Peak shifting will be impacted by the CEESP 2030 goal of “75 percent improvement in

efficiency in the heating, ventilation, and air conditioning sector” as listed in Table 1. The

achievement of this goal would shift the peak back toward to late afternoon and away from post-

sunset evening hours, as heavy summer peak air conditioning loads would be much lighter than

they currently are. It is not clear from the documentation in the Draft 2017 Assumptions and

Scenario for Long Term Planning whether the achievement of a 75 percent reduction in HVAC

12 CAISO, California ISO Peak Load History 1998 through 2015: http://www.caiso.com/Documents/CaliforniaISOPeakLoadHistory.pdf. 13 2016 CAISO OASIS database, July 27, 2016, HE17 (PG&E, SCE, and SDG&E only).

http://www.caiso.com/Documents/CaliforniaISOPeakLoadHistory.pdf

POC Comment 7

loads is assumed for 2030, or if not why the CEDU 2016 assumed a lesser reduction in HVAC

loads. The term “California Energy Efficiency Strategic Plan” is not referenced or cited in

CEDU 2016.

III. Technical Attributes of Solar PV projects

A. Tracking PV arrays have sharp late afternoon output decline

A primary contributor to the abruptness of the “duck curve,” and therefore a primary

justification for continued procurement of fast-start simple cycle gas turbines, is the selection of

tracking PV arrays instead of fixed-tilt PV arrays. Fixed-tilt PV arrays have a substantially more

gradual output decline over the afternoon than a tracking PV array. This more gradual output

decline is advantageous from grid reliability standpoint as it facilitates the predictable scheduling

of a variety of dispatchable gas-fired resources, simple cycle units, combined cycle units, and

steam boiler units, to substitute for the declining solar output.

B. Commission should be directing LSEs to prioritize fixed-tilt PV arrays The Commission should be directing LSEs to prioritize fixed-tilt solar projects over

tracking solar in their IRPs, precisely to moderate the steepness of the duck curve. The

Commission should not passively project that LSEs will overwhelmingly contract for tracking

solar arrays without critically examining the grid reliability implications of this assumption. To

do so would be to ignore the significant negative grid reliability implications, in the form of

flexible gas-fired generation resource costs, of the LSEs prioritizing tracking PV over fixed-tilt

PV.

//

// (Signature Page Follows)

POC Comment 8


/s/ Bill Powers, P.E. Protect Our Communities Foundation /s/ April Rose Sommer Executive Director and Lead Counsel Protect Our Communities Foundation 1547 Palos Verdes Mall #196 Walnut Creek, CA 94597 (619) 363-6790 [email protected]


BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA




SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) COMMENTS ON

ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON


JANET S. COMBS CATHY A. KARLSTAD

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1096 Facsimile: (626) 302-3990 E-mail: [email protected]


1

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA




SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) COMMENTS ON

ADMINISTRATIVE LAW JUDGE’S RULING SEEKING COMMENT ON


In accordance with the Administrative Law Judge’s Ruling Seeking Comment on

Assumptions and One Scenario for Use in Long Term Planning in 2017 (“ALJ Ruling”),

Southern California Edison Company (“SCE”) submits the following comments.

I.

RESPONSE TO QUESTION IN ALJ RULING

A. Are the updates to the demand-side and supply-side assumptions reasonable and

accurate? Please specify any assumption that should be revised and provide a

detailed justification supporting the recommended revisions.

It appears that the assumptions provided are accurate and reflect future conditions.

However, in the future, the Transmission Planning Process (“TPP”) and any elements of the TPP

that may be incorporated into the Integrated Resource Plan (“IRP”) proceeding should address

the impacts of Senate Bill (“SB”) 350. Although the joint agencies – the California Public

Utilities Commission (“Commission”), the California Independent System Operator (“CAISO”),

and the California Energy Commission (“CEC”) – recommend not including SB 350

2

requirements in this cycle, future cycles should measure the impacts of SB 350 to determine the

effects of a higher Renewables Portfolio Standard (“RPS”) on transmission needs. The current

scenario only addresses a 33% RPS by 2020 scenario.

II.

COMMENTS ON DRAFT 2017 ASSUMPTIONS AND SCENARIO FOR LONG-TERM

PLANNING

A. Planning Scenarios – Reliability Scenario

The Draft 2017 Assumptions and Scenario includes a single scenario – the Reliability

Scenario. SCE acknowledges the time constraints in excluding additional scenarios addressing

the impacts of SB 350 at this time. It is important, however, that future cycles of the TPP

include scenarios to address state policy mandates, especially those that impact transmission

needs and resource requirements. SCE also suggests the Commission clarify whether the TPP

will address other state policy mandates as part of the policy-driven analysis. It is unclear if

additional analysis will be conducted, beyond the one scenario analysis.

B. Inter-Agency Coordination

The ALJ Ruling states “[i]t is anticipated that the attachment will also be used to support

additional work in this proceeding on assumptions for use in [IRP], and will ultimately be

replaced by a similar document to be used in the IRP process.”1 This suggests that elements of

the TPP may become part of the IRP process in the future. If this is the case, SCE encourages

intra-agency coordination efforts as soon as possible. The Commission, the CAISO, the CEC,

and the California Air Resources Board need to work together to ensure the development of a

viable, usable IRP process. A joint effort, in the form of joint workshops, joint rulings, and

coordination of efforts should start immediately. This will enable all agencies to work together

1 ALJ Ruling at 1.

3

and reach consensus on IRP-related issues that are important to the successful implementation of

the state’s policy goals.

Respectfully submitted, JANET S. COMBS CATHY A. KARLSTAD

/s/ Cathy A. Karlstad By: Cathy A. Karlstad

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1096 Facsimile: (626) 302-3990 E-mail: [email protected]

February 3, 2017

#311776





COMMENTS OF SAN DIEGO GAS & ELECTRIC COMPANY (U 902 E) IN RESPONSE TO RULING SEEKING COMMENT ON ASSUMPTIONS AND ONE SCENARIO FOR USE IN LONG TERM PLANNING IN 2017

AIMEE M. SMITH 8330 Century Park Court, CP32 San Diego, California 92123 Telephone: (858) 654-1644 Facsimile: (858) 654-1586 [email protected] Attorney for SAN DIEGO GAS & ELECTRIC COMPANY

February 3, 2017





COMMENTS OF SAN DIEGO GAS & ELECTRIC COMPANY (U 902 E) IN RESPONSE TO RULING SEEKING COMMENT ON ASSUMPTIONS AND ONE SCENARIO FOR USE IN LONG TERM PLANNING IN 2017

In accordance with the Rules of Practice and Procedure of the California Public Utilities

Commission (the “Commission”) and the direction set forth in the Administrative Law Judge’s

Ruling Seeking Comment on Assumptions and One Scenario for Use in Long Term Planning in

2017 (“ALJ Ruling”) issued on January 18, 2017, San Diego Gas & Electric Company

(“SDG&E”) submits these comments concerning the Draft 2017 Assumptions and Scenario for

Long-Term Planning document (“Draft A&S”) attached to the ALJ Ruling.

The ALJ Ruling notes that the finalized version of the Draft A&S will be used primarily

in the context of the California Independent System Operator’s (“CAISO’s) 2017-18

Transmission Planning Process (“TPP”), as well as for any long-term resource planning studies

that may be needed to support planning in 2017 prior to the Commission adopting formal

guidance for the Integrated Resource Plan (“IRP”) process.1/ The ALJ Ruling further notes that

while the finalized assumptions will be used to support additional work in the instant proceeding

on assumptions for use the IRP context, the assumptions will ultimately be replaced by a similar

document to be used in the IRP process and parties will have additional opportunities in the

1/ ALJ Ruling, p. 2.

2

future to comment on the assumptions to be used for IRP purposes. 2/ The ALJ Ruling directs

parties to respond to the following question:

Are the updates to the demand-side and supply-side assumptions reasonable and accurate? Please specify any assumptions that should be revised and provide a detailed justification supporting the recommended revisions.

Consistent with this direction, SDG&E provides the following comments on specific

assumptions included in the Draft A&S:

3.1.3 Use of the 2016 California Energy Demand Update (“CEDU”) 1-in-10

weather sensitivity: Consistent with previous years, the planning assumptions

proposed in the Draft A&S reflect the latest load forecast from the California

Energy Commission (“CEC”). While use of the latest statewide forecast makes

sense in certain instances, in this case it is not the right approach due to the

potential inaccuracy of the SDG&E-specific 1-in-10 year peak included in this

update. The adverse weather peak is an important assumption in all transmission

reliability studies. In the 2016 CEDU forecast, the 1-in-10 adverse peak for

SDG&E is only 5.5% higher than the expected (1-in-2) peak. This is substantially

lower than the 11.5% difference in the 2015 CEDU forecast, or over a 250 MW

reduction in adverse peak from the change in this factor alone. Data from the

CEC supporting such a reduction have not been made available; until these data

are reviewed and the accuracy of the statewide forecast is affirmed, the 1-in-10

CEC load forecast for SDG&E should not be relied upon for resource planning

purposes. In the meantime, the Commission should rely on the ratio from the

2/ ALJ Ruling, p. 5.

3

2015 CEDU and calculate a new 1-in-10 value using the 2016 1-in-2 forecast

multiplied by the adjustment of 11.5% from the 2015 CEDU.

3.1.5 CEC Peak Shift Analysis: The Draft A&S discusses the peak shift analysis

undertaken by the CEC.3/ SDG&E strongly supports the effort to examine this

issue given the critical need to get the load shape right and to account for the shift

in peak load to later in the day. As important as it is to recognize changing load

shape, based on SDG&E’s review of the CEC analyses, SDG&E cautions against

its use as an alternative scenario at this time. The CEC analysis represents an

initial attempt to capture the effects of Energy Efficiency (“EE”) and Photovoltaic

Solar (“PV”). While this work is important and should continue, it is not

currently producing results that can be fully explained or verified. In fact, the

results produced differ substantially from what one would see from simply

comparing load shapes. In addition, certain of the proposed adjustments are

difficult to validate. It is unclear, for example, how an adjustment upward of 356

MW in 2019 would occur with only 327 MW of solar in the base. Even more

perplexing is how three year later in 2022, the adjustment is only 246 MW, or 110

MW less than three years before, but the amount of solar increased by 73 MW.

Thus, while SDG&E supports the CEC’s efforts and believes that work in this

area should continue, it submits that the current CEC Peak Shift Analysis should

not be used for resource planning at this time, even as an alternative scenario.

3.1.5 Solar Photovoltaics (“PV”): The Draft A&S asserts that “hourly production

simulation models need to model [behind-the-meter (‘BTM’)] PV as a supply

3/ Draft A&S, p. 15.

4

resource with a fixed profile, rather than as a load reduction in order to account

for the hourly shape of solar generation.”4/ SDG&E agrees that it is important to

account for the change in the load shape that will occur in response to the

forecasted growth of BTM PV, or if different levels of penetration of BTM PV

are assumed in different scenarios. SDG&E disagrees, however, with the

implication in the Draft A&S that the only way to account for this change in load

shape is by modeling BTM PV as a supply resource. The Draft A&S should

provide for greater modeling flexibility and be revised to provide as follows:

“All modeling needs to account for the change in the amount and

shape of the load served by the grid due to growth in BTM solar.

One way to accomplish this is to model BTM PV as a supply

option; however, other modeling methods are also acceptable. The

modeling should address how it accounts for this resource and its

impacts.”

3.1.8 Energy Storage: The Draft A&S assumes that all demand-side (or BTM)

storage should be modeled as supply. Due to the current relatively limited

deployment of energy storage and the lack of meaningful data as to how these

resources are operating, this assumption is likely acceptable for 2017. However,

the Commission should look to reevaluate and improve on this assumption in

future years. The issue is that by modeling these resources as supply-side

resources, the assumption is that energy storage will operate based on grid needs

and wholesale market prices. In actuality, BTM storage is typically operated by

4/ Draft A&S, p. 14.

5

the customer to reduce their bill – in other words, the resource is operated most

often to reduce a specific customer’s non-coincident demand charges, irrespective

of grid needs. Non-coincident demand charges, as the name implies, are not

coincident with system peaks. Thus, this current modeling assumption may

overstate the extent to which energy storage resources will operate based on peak

grid needs and provide “energy shifting, capacity and flexibility services” as

suggested in the Draft A&S.5/

3.2.4 Energy Storage (Page 21): Table 4 (p. 21) of the Draft A&S proposes a

distribution of the duration of energy storage to be procured to meet D.13-10-040

targets. SDG&E is unaware of what the other investor-owned utilities (“IOUs”)

may do in this regard, but SDG&E does not plan to procure any transmission

level storage of 2 hours or 6 hours. SDG&E is instead focusing its storage

procurement to meet the D.13-10-040 targets for energy storage that can

contribute to SDG&E’s local capacity needs as discussed on page 43. Thus,

SDG&E recommends that the Commission further examine the accuracy of the

proposed attributes. SDG&E also notes that having some 2 hour storage and

some 6 hours, which averages to 4 hours, is not equivalent to all storage being 4

hours.

3.2.14 Existing Procurement Authorizations: SDG&E’s comments are limited to

the last three line items in Table 12 (p. 41). First, it is unclear what the item

identified as “Authorized/Pending” for 25 MW in 2019 is intended to represent.

SDG&E assumes that this reference is based on SDG&E local capacity need

5/ See Draft A&S, p. 20.

6

authorized in D.14-03-004. If so, SDG&E notes that the existing storage included

in Table 3 on page 21, satisfies the 25 MW minimum target that was established

under D.14-03-004. Accordingly, SDG&E recommends that this item be deleted.

Second, the following line refers to “Pending A.16-03-014” for 18.5 MW. This

application was approved on December 15, 2016; thus, the contracted energy

efficiency should be built into the load forecast. Lastly, the 20 MW of storage

also referred to (in the last line of Table 12) in that decision was terminated and

should therefore be removed from the table.

Additionally, this section of the Draft A&S discusses SDG&E’s remaining

local capacity requirement (“LCR”) need as determined in D.15-05-051.6/ There

are two important points regarding SDG&E’s LCR need that must be reflected in

the assumptions. First, D.15-05-051 determined that SDG&E’s remaining

procurement authorization is for 200 – 300 MW of local capacity and is limited to

preferred resources and/or energy storage. The approved 18.5 MW of EE satisfies

part of this need. Additionally, all of the incremental energy storage SDG&E is

adding will satisfy both the energy storage targets and SDG&E’s LCR need.

Thus, SDG&E recommends deletion of the reference to 261.5 MW of assumed

remaining authorization. SDG&E further recommends that the Approved EE and

the assumed storage be included for the 2017 modeling in order to allow the

modeling to determine if any additional local resources are needed.

6/ See Draft A&S, p. 42.

7

Respectfully submitted this 3rd day of February, 2017.

/s/ Aimee M. Smith__________________ AIMEE M. SMITH 8330 Century Park Court, CP32

San Diego, CA 92123 Telephone: (858) 654-1644 Facsimile: (858) 654-1586 E-mail: [email protected]

Attorney for SAN DIEGO GAS & ELECTRIC COMPANY






COMMENTS OF SOLARCITY CORPORATION ON


Jason B. Keyes KEYES & FOX LLP 436 14th Street, Suite 1305 Oakland, CA 94612 Telephone: (206) 919-4960 Email: [email protected]

Counsel to SolarCity Corporation

February 3, 2017

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COMMENTS OF SOLARCITY CORPORATION ON


In accord with the California Public Utilities Commission (Commission) Administrative

Law Judge (ALJ) Julie A. Fitch’s Ruling Seeking Comment on Assumptions and One Scenario

for Use in Long Term Planning in 2017” (Ruling) issued on January 18, 2017, SolarCity

Corporation (SolarCity) respectfully submits the following comments.

I. Description of SolarCity

SolarCity is California’s leading full service solar power provider for homeowners and

businesses – a single source for engineering, design, installation, monitoring, and support. The

company currently has over 4,000 California employees based at more than 40 facilities around

the state and had installed solar energy systems for over 300,000 customers nationwide as of

September 30, 2016. Tesla Inc. acquired SolarCity on November 21, 2016.

II. Introduction

While the long term electric system planning landscape at the Commission is undergoing

changes, including significant modifications proposed for the Integrated Resources Planning

(IRP) framework, the development of the assumptions and the “reliability” scenario continues to

serve a critical role in the 2017-2018 Transmission Planning Process (TPP) studies. In general,

- 2 -

SolarCity identifies several areas of improvement from the 2016 to 2017 assumptions and

scenarios, which will be discussed in more detail in Section IV of our comments. Nevertheless,

we note that similar to previous long term planning assumptions and scenarios, uncertainties

remain; in particular those that affect the shape of electricity demand.

As Commission Staff (Staff) points out, these uncertainties include the near term impact

of pending time-of-use (TOU) rates that are currently not fully evaluated in the California

Energy Demand (CED) forecast developed by the California Energy Commission (CEC).1 We

not only appreciate Staff’s recognition of this uncertainty, but are also pleased to see that Staff

plans to collaborate with the CEC staff and facilitate the study of “default residential customer

TOU rate impact in the next major CEC IEPR [Integrated Energy Policy Report] CED planning

cycle.” 2 SolarCity will continue to evaluate future assumptions and scenarios for long term

planning with an eye toward addressing remaining uncertainties in modeling efforts and with the

goal of minimizing the possibility of building stranded assets.

III. SolarCity Reiterates Its Previous Comments from CAISO 2015-2016 TPP Request for Alternate Proposals

Prior to addressing the question outlined in the Ruling, SolarCity would like to provide a

brief review of our comments submitted to California Independent System Operator (CAISO)

regarding the 2015-2016 TPP as well as our comments in the prior Long Term Procurement

Planning (LTPP) proceeding regarding the 2016-2017 TPP.3 Our initial comments in 2015 were

in response to the CAISO’s request for developers to submit alternative proposals to the

1 Draft 2017 Assumptions and Scenario for Long Term Planning, p. 15. 2 Id., p. 16. 3 SolarCity Comments to CAISO: 2015-2016 TPP Alternate Proposal/Comments, Oct. 15, 2015 (available at https://www.caiso.com/Documents/SolarCityComments-2015-2016PreliminaryReliabilityAssessmentResults.pdf); SolarCity Comments in R.13-12-010 (closed): Comments on Assumptions and Scenarios for Use in CAISO 2016-2017 TPP, Feb. 22, 2016; and Reply Comments, Feb. 29, 2016.

- 3 -

conventional solutions presented at the September 2015 stakeholder meeting. The CAISO since

then has taken several steps to attempt to further advance the consideration of non-transmission

alternatives as potential solutions to some of the reliability issues found in planning studies. Yet,

the inadequate information that is publicly provided through the TPP by the CAISO and the three

investor owned utilities (IOUs) continues to preclude distributed energy resources (DERs) from

successfully offering alternatives with sufficient technical detail to be seriously considered.

Progress in the Distribution Resources Planning (DRP) and Integrated Distributed Energy

Resources (IDER) proceedings have improved understanding about how IOUs can provide

actionable information about grid needs and constraints on hosting capacity, but this work has

focused on the distribution system and not on transmission planning. Hence, SolarCity re-

submits the following list of technical specifications (as presented in our October 2015

comments to CAISO and our February 2016 LTPP comments) that are required at a minimum in

order for us to provide a sufficiently robust technical proposal comparable to those submitted by

the three IOUs for conventional wires solutions:

• Project size: examples of this include the required megawatts (MWs) deferred or the

required volt ampere reactive (VARs) to be provided.

• Required completion date of project

• Operation requirement: time of day, months required, speed of response required,

duration of response, etc.

• Electrical location of the project: this would ideally include the transmission model of

the area requiring the solution, but it may be sufficient to provide information regarding

the surrounding grid conditions necessary to determine how to integrate the alternative

solution.

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• Geographical location of the project: this would include information regarding the

region in which the solution would be provided.

• Additional limitations or constraints that an alternative solution would need to

consider: examples of this include space limitations at the substation or communication

requirements.

It is not possible to provide alternate technical proposals that are as robust and on par

with some of the more traditional infrastructure investments proposed by the IOUs lacking this

type of information. We therefore look forward to replicating the progress being made in the

DRP working groups through collaboration with the IOUs in the TPP context, and the future

opportunity to provide non-wire alternative solutions by utilizing more robust, technical data that

is made available to all parties.

IV. Comments on Assumptions and One Scenario

In response to the single question posed in the Ruling, SolarCity focuses its comments on

the following points that address the reasonableness of the demand-side and supply-side

assumptions and to some extent touch on the Reliability Scenario as a whole:

• 33% Renewable Portfolio Standard (RPS) Assumption

In general, SolarCity supports Staff’s approach to use the same 33% RPS utilized in

previous planning cycles.4 This approach recognizes that there is sufficient time to model a

possible greater-than-33% RPS assumption over multiple planning cycles before rushing into

building significant new transmission to access that future portfolio. Using the current proposed

assumption helps minimize the possibility of overbuilding the transmission system and creating

future stranded assets that place a further burden on the rate base. This is supported by the fact

4 Draft 2017 Assumptions and Scenario for Long Term Planning, p. 46.

- 5 -

that over the last few months, several announcements have been made cancelling or deferring the

need for new transmission projects. For example, in 2016 CAISO announced the cancellation of

13 transmission projects due to energy efficiency and rooftop solar resulting in $192 million in

transmission cost savings for PG&E customers.5

• Dispatchable Storage Assumption

Proposing to model all storage as dispatchable is a positive change from previous LTPP

assumptions and scenarios.6 Dispatchability of behind-the-meter (BTM) or customer-sited

storage allows these assets to be represented in the market, therefore co-optimized at a system

level along with other generating assets to determine least cost solutions to serve California-wide

system load. This is due to the more recent availability of enabling market mechanisms such as

Energy Storage and Distributed Energy Resources (ESDER) I and II, which allow BTM storage

today to be better integrated into the wholesale market and optimized directly by CAISO.

Therefore, considering all storage to be dispatchable in the base scenario for the 2017-2018 TPP

is well aligned with policy driven market mechanism changes taking place at the CAISO.

• Storage beyond the Procurement Mandate

For storage, Staff essentially assumes that there will be no storage capacity uptake

beyond the procurement target established by D.13-10-040.7 SolarCity recommends that in

future years, the CEC reconsider this assumption as there certainly could be deployment of both

BTM and in-front-of-the-meter (IFTM) storage beyond the targets established in D.13-10-040.

5 https://www.greentechmedia.com/articles/read/Californians-Just-Saved-192-Million-Thanks-to- Efficiency-and-Rooftop-Solar; Solar Energy Industries Association (SEIA) IRP Informal Comments, Jan. 13, 2017, p. 4 (not docketed, but served on all parties); available at http://www.cpuc.ca.gov/uploadedFiles/CPUC_Website/Content/Utilities_and_Industries/Energy/Energy_Programs/Electric_Power_Procurement_and_Generation/LTPP/Opening%20Comments_combined.pdf. 6 Ruling, p. 4; Draft 2017 Assumptions and Scenario for Long Term Planning, p. 20. 7 Id.

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Specifically, SolarCity suggests that the CEC should develop assumptions about market driven

BTM storage, similar to how it currently forecasts future solar photovoltaic (PV) additions.

• Optimal Location for Storage Deployments Assumption

Among the assumptions Staff makes for storage resources, it determines that due to cost

effectiveness requirements, storage will be sited at the most optimal locations in order to “allow

these resources to help satisfy the local area reliability requirement.”8 We support this

assumption because, it minimizes unnecessary transmission infrastructure approvals that could

add an additional cost burden for ratepayers.

V. Conclusion

SolarCity appreciates the Commission’s consideration of these comments on the Draft

2017 assumptions and scenario for long term planning and looks forward to continuing to

participate in the IRP development process.

Respectfully submitted at Oakland, California.

/s/ Jason B. Keyes

Jason B. Keyes KEYES & FOX LLP 436 14th Street, Suite 1305 Oakland, CA 94612 Telephone: (206) 919-4960 E-mail: [email protected]

Counsel to SolarCity Corporation

February 3, 2017

8 Id., p. 22.

1


COMMENTS OF TRANSCANYON, LLC ON 2017 ASSUMPTIONS AND SCENARIOS

Jason Smith President

TransCanyon, LLC Tel: 602 250-2668

Email: [email protected]

Shelly-Ann Maye Regulatory Manager

TransCanyon, LLC Tel: 515 281-2206 Email: [email protected]

February 3, 2017

Order Instituting Rulemaking Develop an Electricity Integrated Resource Plan Framework and to Coordinate and Refine Long-Term Procurement Planning Requirements

Rulemaking 16-02-007 Filed (February 19, 2016)

2

I. INTRODUCTION

Pursuant to the Administrative Law Judge’s Ruling seeking comment on the

Assumptions and one Scenario for Use In Long Term Planning In 2017, TransCanyon

respectfully submits these comments. TransCanyon’s comments are limited to the decision

to model only one scenario, namely a reliability scenario. TransCanyon believes that from a

long term planning perspective, such an approach fails to incorporate the range of probable

futures and public policy initiatives that would inform the least cost-best fit resource mix

necessary to meet the state’s energy demand.

II. COMMENTS

A. In order to determine the most cost effective resource mix for long term planning, the California agencies should model a range of scenarios reflecting the state’s public policy goals and initiatives.

By mutual agreement among the California Public Utilities Commission, the California

Energy Commission and the California ISO (“Agencies”), the Draft 2017 Assumptions and

Scenario document looks at a single reliability scenario. This scenario assumes that no RPS-

related policy analyses are needed to identify new infrastructure needs beyond what is necessary

to support a 33% RPS scenario. The Agencies largely support this approach by arguing that

additional studies are needed to determine the optimal resources needed to meet the 50% RPS

goal before transmission needs can be evaluated. TransCanyon believes that this approach does

not appropriately reflect the range of public policy goals and initiatives needed to inform a long

term planning process.

3

Achieving the 50% RPS policy goal at the lowest cost, which is a requirement under SB

350, will require advance planning. To be clear, it is unlikely that the CAISO will decide that

additional public policy projects are needed in the 2017-2018 Transmission Planning Process.

However, the 2017-2018 inputs will be used to: (1) establish the framework through which the

CAISO evaluates whether additional investments are needed in the future; and (2) finalize the

location of least cost resources, such that this information can be fed into the 2018-2019

Transmission Planning Process planning cycle, where decisions regarding additional

transmission investments will be made. The long lead time necessary for transmission

development requires that the Agencies consider a range of policy goals to determine the most

cost effective resource mix necessary to meet those goals. This will necessitate modeling a range

of scenarios, similar to what has been done in previous Long Term Procurement Plan (“LTPP”)

Assumptions and Scenarios documents. Anything less would run the risk of the sub-

optimization of resources, with California ratepayers bearing unnecessary costs that they

otherwise would not have borne.

The Agencies have argued that additional studies are needed to model scenarios that

contemplate anything beyond a 33% RPS goal. In addition, the Agencies point to the 50% RPS

Special Study completed by the CAISO as part of the 2015-2016 Transmission Planning Process.

The Agencies note that in this Study, the CAISO concluded that no additional transmission may

be needed to achieve the state’s RPS policy goal, but the limited scope of the 50% RPS Special

Study is such that it does not provide a reasonable basis for a decision to delay further planning.

The 2015-2016 Transmission Planning Process exclusively assumed energy-only

deliverability requirements and did not include such factors as the economic cost of curtailment,

deliverability of incremental renewable resources needed to maintain reliability and the ability of

4

neighboring markets to absorb solar over-supply. All of these factors when taken together may

argue for an increase in transmission infrastructure investment. These variables could have a

significant impact on the optimal resource portfolio that California should pursue. A decision

not to model multiple scenarios could result in significantly suboptimal planning decisions and

increased costs to ratepayers.

In response to the Agencies’ argument that additional studies are needed to justify

modeling scenarios that would contemplate procurement beyond a 33% RPS goal, it should be

noted that the SB 350 Studies were comprehensive in nature. These studies, which determined

that there were benefits to California ratepayers from regionalization, analyzed scenarios

involving 50% RPS goal. These studies and analyses were extensively discussed and vetted with

California stakeholders. The data included in these analyses are not speculative. It is therefore

plausible to assert that these studies provide sufficient basis for the Agencies to consider multiple

scenarios related to public policy goals and considerations in their long term planning process.

These scenarios can then be updated as the Agencies receive more current information.

III. CONCLUSION

TransCanyon appreciates the opportunity to provide these comments and looks forward

to continued participation in this process.


Jason Smith

President TransCanyon, LLC Tel: (602) 250-2668 Email: [email protected]

5

Shelly-Ann Maye Regulatory Manager TransCanyon, LLC Tel: (515) 281-2206 Email: [email protected]

February 3, 2017

1







Requirements.



COMMENTS OF THE UTILITY CONSUMERS’ ACTION NETWORK (UCAN) ON

2017-2018 TRANSMISSION PLANNING PROCESS SCENARIO AND ASSUMPTIONS

Donald Kelly, Executive Director

David Croyle, Energy Economist

Jane Krikorian, J.D. Public Advocate

Utility Consumers’ Action Network

3405 Kenyon St, Suite 401

San Diego, CA 92110

(619) 696-6966

[email protected]

February 3, 2017


2







Requirements.



COMMENTS OF THE UTILITY CONSUMERS’ ACTION NETWORK (UCAN) ON

2017-2018 TRANSMISSION PLANNING PROCESS SCENARIO AND ASSUMPTIONS

I. INTRODUCTION

Pursuant to a January 18, 2017 ruling (“Ruling”) of the Administrative Law Judge

requesting comments on the staff’s proposed assumptions and scenario (“Reliability Scenario”)

for use in the California Independent System Operator’s (“CAISO”) transmission planning

process (“TPP”) Utility Consumers’ Action Network (“UCAN”) respectfully provides these

comments on the Ruling.

II. GENERAL COMMENTS ON TRANSITION FROM LTPP TO IRP

The ALJ Ruling of January 18, 2017 invites parties to focus their comments on the

transmission planning process (TPP): “Comments in response to this ruling should focus

primarily on the appropriateness of the attachment for use in the CAISO 2017-2018 TPP

process.” (Ruling, p. 1) While UCAN does focus on the TPP in its comments, we offer a few

general comments regarding the transition from LTPP to Integrated Resource Planning (IRP) and

the associated assumptions that are included and excluded for 2017.

“In previous years, the Assumptions and Scenarios have been released as part of the

CPUC’s Long-Term Procurement Plan (LTPP) proceeding. This year’s document, the

Draft 2017 Assumptions and Scenario, memorializes common assumptions to be used for

3

long-term electricity system planning in the state of California. Traditionally, these

assumptions were released in the LTPP Assumptions and Scenarios document. The Draft

2017 Assumptions and Scenario is now being published within this proceeding, which

incorporates LTPP and acts as the successor proceeding to R.13-12-010. (Ruling, pp.2-

3)

It is anticipated that future Assumptions and Scenarios for use in long-term planning will

be generated by the IRP process within this proceeding and endorsed by the Commission

for future use in planning.“ (Ruling, pp. 2-3)

The Long Term Planning Process (LTPP) is a bi-annual process. Nevertheless, the

timing of the latest LTPP is inconvenient. First, as the ALJ Ruling acknowledges “This A&S 1

document acts as a bridge between the previous LTPP process and the successor IRP process.”

(Attachment, p. 8) But the LTPP timing is also complicated by several significant regulatory and

legislative changes, e.g., the transition of residential customers to default TOU rates, Senate Bill

350 legislation that mandates increases in the Renewable Portfolio Standard (RPS) from 33 to 50

percent and Greenhouse Gas (GHG) emissions to 40 percent reduction by the year 2030. These

changes in regulation and legislation are significant and not addressed in the CEC’s 2016 load

forecast assumption to be used in the LTPP Assumptions & Scenarios document. Consequently,

33 percent is assumed for the RPS.

“Previous versions of the LTPP Assumptions & Scenarios document contained

information intended for use in policy-driven analyses in the CAISO’s TPP process.

Policy-driven analysis historically focused on identifying any transmission infrastructure

needed to support the state’s RPS program. By mutual agreement between the

Commission, CAISO, and CEC staff, no RPS-related policy-driven analyses to identify

new infrastructure needs beyond what is necessary for a 33 percent RPS scenario are

being provided by the Commission for consideration in long-term planning and for use

by the CAISO for its 2017-18 TPP.” (Ruling, pp. 3-4)

1 Assumptions and Scenarios

4

The rationale for excluding the implications of these regulatory and legislative changes is

reasonable but not completely satisfactory given the timing of the LTPP. The impact on the load

forecast of these recent changes would be considered too speculative until results of current

research is available.

“Various studies are underway that could inform planning beyond the 33 percent RPS

goal. Thus, various pathways may eventually be identified that lead to a beyond-33

percent RPS goal. To include a portfolio for increased renewables for long-term

planning would be to presuppose the conclusions of the studies underway, particularly as

it related to potential infrastructure authorizations needed to meet future goals.”

(Attachment, p. 32)

Furthermore, transportation electrification is included but may not reflect the level of

electric vehicle penetration assumed in the 2016 CEC forecast. (Assumptions, p. 11) The

Governor’s Plan to increase EVs in California to one million EVs by 2020 and 1.5 million by

2025 is currently being addressed in the transportation electrification proceedings. Again, the

activities and studies since the 2016 CEC forecast was developed remain speculative until

research is completed. Once there is sufficient progress on these regulatory and legislative

fronts, e.g., experience on the new TOU rates and progress toward meeting the SB 350 RPS and

GHG reductions, these assumptions can be revised for the next LTPP (or more precisely, the

next IRS).

However, since we know changes although speculative, are coming, UCAN is concerned

about understanding the impact on transmission capacity needed to bring solar and wind

resources over long distances to the load centers or the impact of significant growth in behind-

the-meter (BTM) solar energy on the grid without at least testing these implications through

sensitivity analysis. The year 2030 is not far off and much can happen in the next two years

before the next LTPP/IRP. The default TOU rate changes and SB350 mandates are likely to

have significant impacts on transmission infrastructure and the Commission needs to be mindful

of those impacts.

The ALJ ruling states:

5

“Unlike previous LTPP cycles, the Draft 2017 Assumptions and Scenario document does

not propose multiple scenarios for study … Included in the Draft 2017 Assumptions and

Scenario is a single scenario, the Reliability Scenario.” (Ruling, p. 3)

UCAN observes that despite a single scenario, the scenario should be subject to a

sensitivity analysis on the most critical assumptions. The Ruling does make the following

changes to the A&S document:

“The Draft 2017 Assumptions and Scenario document includes the following changes

from the previous version:

The addition of a common set of load type definitions to facilitate modeling discussions

across agencies;

No projection for the doubling of Additional Achievable Energy Efficiency (AAEE) due to

Senate Bill 350 (De León, 2015), since the setting of that goal is currently underway at

the CEC;

Regardless of interconnection domain, all storage resources are to be modeled as

dispatchable and providing Resource Adequacy capacity;

The assumption that there will be no renewable retirements within the planning

timeframe; and

Updated assumptions for combined heat and power, dispatchable storage, demand

response, and renewable resources.” (Ruling, p. 4)

III. RESPONSE TO QUESTION AND SPECIFIC ISSUES OF CONCERN

The ALJ ruling then notes that:

“Parties are invited to comment on any and all aspects of the attachment and are also

requested to respond to the following specific question in their comments on this ruling:

1. Are the updates to the demand-side and supply-side assumptions reasonable and

6

accurate? Please specify any assumptions that should be revised and provide a detailed

justification supporting the recommended revisions.” (Ruling, pp. 4-5)

UCAN is unable to respond to the single question on the reasonableness and accuracy of

the demand-side and supply-side assumptions. However, per the ALJ’s ruling inviting comments

on all aspects of planning document, UCAN does offer the following comments on specific

issues of concern.

The usefulness of the LTPP bridge to IRP raises concerns given the substantial activities

in the areas of new rate structures, ambitious but mandated RPS and GHG goals and

transportation electrification, e.g., supporting the Governor’s target of 1.0 million EVs by 2020

and 1.5 million EVs by 2025. It is unclear whether and how these significant changes will affect

the need for transmission capacity by 2030. Ignoring what may be speculative now may appear

to be sound, but can result in a less useful plan. Is a potential delay of the LTPP (particularly the

Transmission Plan) until expectations are less speculative preferred to a transmission plan that

may have to be ignored or significantly modified as default TOU rates are introduced to the

residential class, RPS rises toward 50 percent and EV purchases increase?

UCAN believes that the best way to build a bridge between the historical LTPP process

and the new IRP process requires some consideration of the infrastructure path to 2030. After

all, a “bridge” involves infrastructure. Nevertheless, we can neither assume what is only

speculation nor ignore the direction that the ongoing activities will most likely take. Sensitivity

analysis of the lone scenario makes sense if it can provide some knowledge of both doing what

will not be needed and not doing what will be needed.

This bears repeating and amplification. If we are uncertain about the future in certain

respects, we need to estimate the consequences of both (1) making transmission investments and

discovering the transmission investments were not needed, and (2) not making the transmission

investments, only to discover the transmission investments were needed. This is not unlike the

difference between Type I and Type II error in statistics. Both types of errors have associated

costs and these errors should be minimized to the extent possible. Sensitivity analysis can help

estimate the cost of making both types of errors.

Oddly enough, in the discussion of Energy Efficiency, the ALJ ruling suggests high and

low energy savings assumptions where the low savings assumption reflects the energy efficiency

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most certain to occur whereas the high savings assumption includes all energy efficiency

potential, including aspirational goals. This seems incongruous with the approach to recent

regulatory and legislative activities, including residential rate reform and SB350 mandates. The

A&S document should be reviewed to identify inconsistencies in the assumption logic with

respect to certain vs. uncertain expectations. Specifically, what the cost is of at least a two-year

delay in adding critical transmission investments.

The planning horizon extends out 20 years, to 2037, beyond the 2030 target for the RPS

increases and GHG reductions by 2030:

“Similar to the historical LTPP planning period, the 2017 Draft A&S for long-term

planning forecasts 20 years out in order to study the impact of major infrastructure

decisions under consideration.” (Attachment, p. 9)

The next LTPP/IRP in two years will extend to 2039; therefore, the out years in the current

LTPP/IRP are less meaningful compared to the critical near-term impacts on the grid and

transmission capacity for reliability purposes expected over the next two years which are ignored

in the 2017-2018 LTPP/IRP.

IV. CONCLUSION

California is presently undergoing massive changes to how investor owned utilities

(IOUs) deliver and price electricity. Presently, the IOUs are seeking to enact policy mandates of

regulators and legislators to, among other things, transform residential rates, increase the RPS

from 33 to 50 percent by 2030, reduce GHG emissions to 40 percent from 1990 levels by 2030,

as well as to expand the transportation electrification infrastructure. The transmission capacity

investment implications of these changes need to be considered in the 2017-2018 and/or the

2019-2020 LTPP/IRP process.

Dated: January 20, 2017 Respectfully submitted,

David Croyle

8

Jane Krikorian

Donald Kelly

______/s/________________

Donald Kelly

Executive Director

Utility Consumers’ Action Network

3405 Kenyon St, Suite 401

San Diego, CA 92110

(619) 696-6966

[email protected]


1



Order Instituting Rulemaking to Develop

an Electricity Integrated Resource Planning



Requirements.

R.16-02-007

(Filed Feb. 11, 2016)

COMMENTS FROM THE UNION OF CONCERNED SCIENTISTS ON ASSUMPTIONS

AND ONE SCENARIO FOR USE IN LONG TERM PLANNING IN 2017

Michael Cohen

Western States Power Systems Engineer

Union of Concerned Scientists

500 12th Street, Suite 340

Oakland, CA 94607

(510) 809-1572


Laura Wisland

Senior Energy Analyst

Union of Concerned Scientists

500 12th Street, Suite 340

Oakland, CA 94607

(510) 809-1565


February 3, 2017

2

COMMENTS FROM THE UNION OF CONCERNED SCIENTISTS ON ASSUMPTIONS

AND ONE SCENARIO FOR USE IN LONG TERM PLANNING IN 2017

Pursuant to the January 18, 2017 Administrative Law Judge (“ALJ”) ruling requesting comments

on Draft 2017 Assumptions and Scenario for use 2017 Long-Term Planning (“Draft

Assumptions”), the Union of Concerned Scientists (“UCS”) submits these opening comments.

I. UCS Agrees with the Commission’s Draft Assumptions for Energy Storage

UCS supports the forward-thinking approach that the Draft Assumptions take with regards to the

operation of energy storage. In particular, UCS is pleased to see that storage will be modeled as

dispatchable and providing Resource Adequacy regardless of the domain of interconnection, i.e.,

including customer-sited storage. The expectation that communication and aggregation logistics

necessary to enable customer-sited storage to serve grid needs will be in place within the

planning horizon of the CAISO’s TPP (and IRP) is a reasonable one, and the Draft Assumptions

correctly capture the expected benefits of California’s statutory storage procurement targets.

II. UCS Supports Removing the Regional Generation Constraint and Urges the

Commission to Allow Renewables to Meet the New Frequency Response Constraint

In R.13-12-010, UCS, along with Sierra Club California, submitted expert testimony which

contained analytical evidence demonstrating that a 25% regional generation requirement, as

defined by the CAISO at that time, would exacerbate renewable energy curtailment in a 40%

RPS scenario.1 In subsequent comment opportunities in R.13-12-010, UCS urged the

Commission and the CAISO to clearly define frequency response as a reliability need in the 1 See Nelson, J. Prepared opening testimony of Dr. Jimmy Nelson on behalf of the Union of Concerned Scientists and Sierra Club, including Errata. R.13-12-010. 09/24/2014

3

model, and allow both synchronous and asynchronous/inverter-based resources (batteries, solar,

wind, flexible demand, etc.) to provide that need.2 Therefore, in these Draft Assumptions, UCS

supports the elimination of the old regional generation constraint and the inclusion of a finer-grained

frequency response requirement, which reflects California’s actual system needs. However,

UCS requests that the Draft Assumptions also incorporate CAISO’s recent work demonstrating

that a utility-scale solar plant can provide grid services at least as effectively as competitive

fossil technologies.3 This study suggests that renewables (or at least utility-scale solar power)

should be on the list of resources that can provide the required frequency response headroom,

alongside storage and natural gas generation.

III. The Draft Assumptions Do Not Reflect Planned Investments in Energy Efficiency

and Demand Response, Which Could Lead to an Overestimate of Local Capacity

Needs in the 2018-2019 IRP.

UCS is concerned that the Draft Assumptions do not reflect statutory requirements to make

additional investments in energy efficiency and demand response. Moreover, by not

incorporating future investments in these preferred resources into the Draft Assumptions, UCS is

concerned that the Commission will bias the results of future IRP proceedings.

Specifically, these Draft Assumptions will impact the CAISO’s 2017-2018 TPP. In addition,

UCS understands from Staff’s September 26, 2016 workshop that CAISO TPP results will be

2 Comments of UCS and Sierra Club on Proposed Revisions to LTPP Modeling Methodology, R.13-02-010., 12/4/15., pp.12-14. 3 Loutan, Clyde et al., “Using Renewables to Operate a Low-Carbon Grid: Demonstration of Advanced Reliability Services from a Utility-Scale Solar PV Plant”, Jan 2017, https://www.caiso.com/Documents/UsingRenewablesToOperateLow-CarbonGrid.pdf

4

used to inform “local needs” in subsequent IRP cycles,4 and that the 2017-2018 TPP, will be

used to inform the 2018-2019 IRP proceeding.5

UCS is mainly concerned about the Commission’s proposed assumptions for energy

efficiency and demand response, which could overestimate findings of local needs, which in turn

could result in unnecessary procurement in the 2018-2019 IRP cycle. CAISO is likely to find

higher local capacity needs in the TPP if it uses the assumptions for energy efficiency and

demand response suggested in the current Draft Assumptions because these assumptions do not

reflect the future investments in energy efficiency and demand response that were codified into

law by SB 350 and AB 2454. UCS expects that modeling for future IRP proceedings will

otherwise use these more ambitious targets, since the goal of the IRP process is to create a

system plan that meets California’s greenhouse gas planning targets and other statutory

requirements. If the 2017-2018 TPP identifies local needs that would not exist if assumptions

aligned with the rest of the 2018-2019 IRP were used, then at best there will be confusion in the

IRP process and at worst, unnecessary or misplaced procurement will be authorized.

For this reason, UCS believes it is critical that the Commission provide CAISO with

assumptions for the 2017-2018 TPP that align as much as possible with the expected

assumptions in the 2018-2019 IRP. UCS fully recognizes that there are significant uncertainties

in these assumptions today and that any estimate will necessarily be imperfect, but believes that

grappling with this uncertainty and making reasonable estimates of future investments in energy

efficiency and demand response in the 2017-2018 TPP will lead to better-aligned outcomes than

ignoring what we expect to happen in the next ten years and side-stepping the issue.

4 “Developing an Analytical Framework for CPUC’s IRP Process” slides from September 26, 2016 workshop, slide 15, box 2. This slide deck can be found within the combined decks posted at: http://www.cpuc.ca.gov/WorkArea/DownloadAsset.aspx?id=6442451009 5 Ibid., slide 31.

5

For energy efficiency, UCS strongly recommends that the Draft Assumptions include the

Commission’s best estimate of the impact of the energy efficiency doubling requirement in SB

350. Given that the California Energy Commission (“CEC”) is still setting the exact targets

associated with this requirement, UCS recommends that the Commission use the values from the

California Air Resources Board (“CARB”) draft scoping plan as the best available estimates in

the meantime.6 UCS has also previously recommended, in informal comments in R.16-02-007,

that CARB or CEC estimates be used in the current 2016-2017 IRP.7

For demand response, UCS recommends the Commission provide assumptions that are

consistent with the 2015 California Demand Response Potential Study conducted by the

Lawrence Berkeley National Laboratory (“LBNL Study”). The current approach in the Draft

Assumptions is to use the 2016 IOU’s Load Impact Reports as the basis for supply-side demand

response resources in 2026.8 UCS is concerned that this will underestimate the local capacity

value that demand resource will be providing in 2026. In fact, the Commission appears to

acknowledge that this assumption may underestimate future DR in the Draft Assumptions: “It

could turn out that by 2026, capacity from existing programs will be ‘retired’ and ‘replaced’ by

significant growth in DRAM capacity.”9

The LBNL Study suggests that “California could achieve approximately 6 GW of DR by

2025 at a levelized cost of less than $200/kW-year. These 6 GW are described in our [LBNL’s]

‘medium DR’ scenario, which we believe is achievable with continued progress in policy,

6 Available at: https://www.arb.ca.gov/cc/scopingplan/scopingplan.htm 7 Informal Comments of the Union of Concerned Scientists Regarding Questions for Parties Following the December 16, 2016 Workshop, submitted January 13, 2017, p. 7 8 Draft Assumptions, p.26. 9 Draft Assumptions, p. 27.

6

markets, and technology.”10 “Of the 6 GW DR resources forecasted in the medium scenario, we

expect 4 GW of dispatchable-supply DR…”11

AB 2454 requires the Commission to consider the findings of the LBNL Study when

assessing the level of cost-effective, reliable, and feasible DR that the IOU’s propose to procure

annually. And yet, the Draft Assumptions provide no explanation of why its proposed supply-

side assumptions on demand response are less than 2 GW, when the “medium” LBNL scenario

projects more than double that amount. UCS suggests that the Draft Assumptions assume 4 GW

of supply-side demand response.


Laura Wisland Senior Energy Analyst Union of Concerned Scientists 500 12th Street, Suite 340 Oakland, CA 94607 (510) 809-1565 Email: [email protected] Michael Cohen Western States Power Systems Engineer Union of Concerned Scientists 500 12th Street, Suite 340 Oakland, CA 94607 (510) 809-1572 Email: [email protected]

February 3, 2017

10 Alstone, P. et. al; 2015 California Demand Response Potential Study, Lawrence Berkeley National Laboratory, pp.8-9. Available at: http://www.cpuc.ca.gov/General.aspx?id=10622; emphasis added 11 LBNL Study, p.6.