1. The California 2030 Low-Carbon Grid Study (LCGS)
Phase I Results Summary
September 2, 2014

2. LCGS Overview Premise:
The California electric grid should be reassessed through the framework of low carbon at low cost, rather than a higher renewables portfolio standard (RPS), to achieve affordable greenhouse gas (GHG) reductions.
A 2030 low carbon grid represents a critical strategy for success in meeting California’s GHG targets.
Tools:
Detailed modeling of California and Western Electricity Coordinating Council (WECC) electrical systems
Economic analysis of overall system cost
Results:
The LCGS analyzed California’s grid with a carbon focus, flexible load, regional cooperation, efficient use of natural gas, and diverse renewable generation
With this portfolio, the California electric sector can reduce greenhouse gas (GHG) emissions by more than 50% below 2012 levels in 2030:
With minimal rate impact
Without compromising reliability
With minimal curtailment of renewable energy
With a stable gas fleet that is dispatched with minimum cycling
This study is not:
Providing policy recommendations
Searching for a fully-optimized portfolio
A power-flow analysis looking at inertia, fault tolerance, or voltage support
PLEXOS is a production cost model, which identifies the lowest-cost dispatch for a portfolio in a given year. More information in the appendix of this presentation.

3. Low Carbon, Reliable Grid
The LCGS Approach
The LCGS, with a diverse portfolio of energy generation and resource flexibility, demonstrates the feasibility of deep, low cost emissions reductions in California.
Diverse
Renewables
Regional
Cooperation
Efficient
Natural Gas
Carbon
Focus
Flexible
Load
Low Cost,
Low Carbon, Reliable Grid

4. LCGS Study Design Study Components Participants Phase I, August 2014
Two emissions-reductions cases for 2030, with one baseline case for comparison
One “low-mitigation” sensitivity, to demonstrate the effectiveness of flexibility measures
Estimate of revenue requirement
Phase II, January 2015
Additional scenarios and sensitivities, vetted by independent Technical Review Committee
Revenue requirement analysis by JBS Energy Inc.
Check dispatch for compliance with regional reliability obligations.1
Final report
Participants
Modeling: National Renewable Energy Laboratory (NREL)
Supporting analysis: General Electric Systems (GE) (Phase II)
Revenue Requirement Analysis: JBS Energy Inc. (Phase II)
Peer Review: Independent Technical Review Committee
Funding/Steering Committee: Over twenty-five companies, organizations, and foundations
1Compliance with WECC Frequency Response Obligation (RFO) and NERC Standard BAL -003, Frequency Response and Bias

5. LCGS Phase I: Methodology
Determined 2030 GHG reductions needed to be on track for 2050 targets, using assumptions­1 from CPUC, CARB, CEC, & WECC about load forecasts, energy efficiency, customer-sited solar, electric vehicles, etc. The reductions needed were 50% below 2012 GHG levels.
Identified LCGS Cases:
Baseline Case: Assumes existing policies stay in place and are maintained through 2030, but implements no additional low-carbon measures.
Target Case: Based on these assumptions, a “net short” of low-carbon energy need was identified to meet the 2030 load forecasts and carbon reduction goals, in conjunction with flexibility measures.
Accelerated Case: A second, larger “net short” was identified to demonstrate that the LCGS approach can scale up toward the deeper GHG reductions needed by 2050.
Developed resource portfolios for each respective case, which were run in NREL’s PLEXOS production cost model.
Analyzed investments and savings associated with implementing the Target Case instead of the Baseline Case to identify net ratepayer costs and the cost of the carbon reductions.
Target: constructed by estimating the amount of zero-carbon energy additions required to achieve the emissions target
Accelerated: achieves deeper reductions than the Target Case, showing that the portfolio can “scale up”
Baseline: continues current policies but assumes no carbon reduction policy additions after 2020, for comparison with Target and Accelerated Cases
Determined 2030 GHG reductions necessary to be on track for 2050, according to data and assumptions from CPUC, CARB, CEC, and WECC;
Pie Charts
Does not include “generation” from DR and storage
Pie charts include out-of-state (OOS) renewables and all in-state generation
All scenarios meet at least a 15% planning reserve margin considering net qualifying capacity (NQC
1 For a full list of assumptions and model designs, see LCGS Work Paper 1: Assumptions, available at

6. LCGS 2030 Target on Emissions Reduction Path to 2050
The LCGS target of 47 MMT (50% below 2012 levels) was chosen for This sets California on the California Air Resources Board’s (CARB) constant percentage reductions trajectory1 from 2020 to 2050.
Background
California has progressive GHG policies in place:
Emissions target of 1990 levels by 2020
33% Renewable Energy Portfolio Standard by 2020
Emissions target of 80% below 1990 levels by 2050
But there is a need for information about how the grid can de-carbonize beyond 2020, and for a clear trajectory toward 2050 targets.
The LCGS fills that need as a robust, technical perspective on how the electric sector can achieve significant GHG emissions reductions by 2030, as a milestone toward California meeting its 2050 targets.
Grey line represents trajectory needed to achieve 2050 goals.
Green line is where California will be in a “business-as-usual” case.
The LCGS is unique in its focus on emissions reduction
The report will be neutral on policy recommendations—intended as an informational tool
The need for a 2030 mid-term target has been highlighted by:
California Public Utilities Commission (CPUC),
California Air Resources Board (CARB)
California Energy Commission (CEC)
Western Electric Coordinating Council (WECC)
Also shown: actual 2012 emissions from California’s electric sector, AB 32 emissions target in 2020, executive order S-3-05 emissions target in 2050.
1See California Air Resources Board’s First Update to the Climate Change Scoping Plan, p. 33.
2This plot assumes that the electric sector produces 20% of statewide emissions.

7. LCGS Phase I: Portfolio Cases
110 TWh zero-carbon energy;
Some energy efficiency, demand response, and storage;
Load: 341 TWh
177 TWh zero-carbon energy;
Accelerated levels of energy efficiency and demand response;
More storage than Baseline Case;
Load: 321 TWh
205 TWh zero-carbon energy;
Accelerated levels of energy efficiency and demand response;
More storage than Target Case;
Load: 321 TWh

8. Phase I: Results Summary
1. Carbon Reductions
2. Rate Impact
Target Case: More than 50% reduction from CO2 emissions.
Accelerated Case: Greater reductions than Target Case. Demonstrates that the existing grid can scale up for deeper reductions beyond 2030.
New Development: ~$58 Billion investment in infrastructure serves as an economic stimulus (~80% in California).
Cost Savings: New infrastructure and program costs are balanced by savings from reduced fuel purchases, more efficient use of grid resources, avoided emissions costs.
Marginal Impact: Using the LCGS approach, utility revenue requirements needed to implement a low-carbon grid vs. a business as usual strategy are minimal.
Slide 10
Slides 11-14
3. Import Flows
4. Natural Gas/Grid Operations
Trading Patterns: Import patterns and regional flows are not drastically different from Significant net exports in some hours. Annual import quantity is roughly one half of today.
Fuel Type: Regional trading is mostly renewable, rather than carbon-intensive fossil energy.
Ancillary Services: Short term system flexibility and regulation is served primarily by imports, exports, demand response, dispatchable hydro, and energy storage including pumped hydro and concentrating solar; frees up natural gas to serve primarily as block-loaded intermediate generation.
Efficient Dispatch: Because natural gas is needed less often as a flexible resource, gas facilities start and stop less frequently, and operate more often at full capacity. This increases fuel efficiency and decreases operational cost.
Slides
Slides 18-28

9. Results: 1. Carbon Reductions
LCGS 2030 Cases on Emissions Reduction Path to 2050
Emissions reductions in Target and Accelerated Cases exceed LCGS target of 50% reductions below 2012 levels by 2030.
Background
California has progressive GHG policies in place:
Emissions target of 1990 levels by 2020
33% Renewable Energy Portfolio Standard by 2020
Emissions target of 80% below 1990 levels by 2050
But there is a need for information about how the grid can de-carbonize beyond 2020, and for a clear trajectory toward 2050 targets.
The LCGS fills that need as a robust, technical perspective on how the electric sector can achieve significant GHG emissions reductions by 2030, as a milestone toward California meeting its 2050 targets.
Grey line represents trajectory needed to achieve 2050 goals.
Green line is where California will be in a “business-as-usual” case.
The LCGS is unique in its focus on emissions reduction
The report will be neutral on policy recommendations—intended as an informational tool
The need for a 2030 mid-term target has been highlighted by:
California Public Utilities Commission (CPUC),
California Air Resources Board (CARB)
California Energy Commission (CEC)
Western Electric Coordinating Council (WECC)

10. Results: 1. Carbon Reductions
Emissions in Each Case (all values in MMT in 2030)
Baseline
Target
Accelerated
CO2 from gas generation in CA
67.2
43.7
39.5
CO2 from unspecified imports1
11.8
3.0
0.2
Total CO2 from gas generation and imports
79.0
46.7
39.7
CO2 credited to exports2
-0.6
-7.2
-12.9
Net CO2 including export credits
78.4
26.8
% reductions below levels3
18%
58%
72%
Emissions from imports have generally historically made up at least half of California’s total emissions
The Target and Accelerated Cases yield dramatic carbon reductions because:
Coal imports are essentially eliminated (including economy energy)
Most California imports are zero-carbon energy
Efficient grid dispatch enables significant integration of renewable energy without curtailment of zero carbon resources and replacement by fossil energy
Natural gas is efficiently “block-loaded” rather than run frequently at partial capacity, because short-term ancillary services are provided by low-carbon resources, demand response and energy storage
NREL slide 37
To reduce emissions, it is important understand where they come from and why they are where they are today:
Sources of emissions: 1) coal, 2) gas imports, 3) ancillary services provided by gas, 4) block-loaded gas, 5) CHP
In order to reduce emissions, address each of these:
1) All coal except a very little amount in "unspecified imports" is long gone by 2030.
This assumption, based on announced retirements. is built into the model.
2) Gas imports: For real carbon reductions, these have to be near zero.
The target and accelerated cases show low amounts of gas imports.
3) Short-term ancillary services provided by gas (regulation and intra hour load following): relying on gas for these services causes them to operate in an inefficient “quasi-baseload” mode. This means that they operate at part load (near the midpoint between Pmin and Pmax) in order to provide upward and downward flexibility. The combination of operating at part load and the upward and downward ramps required to provide ancillary services means that these plants operate with poor heat rates and crowd out zero-carbon baseload resources.
The model used less gas for ancillary services in the target and accelerated cases. Most of the ancillary services and flexibility reserves came from storage, hydro, and CSP with TES.
4) Gas block loading: This is the best use of gas, with the possible exception of operating reserves. This leads to high operating efficiency and low O&M costs.
When the model used gas plants, they were block loaded, which suppressed emissions from California gas plants.
5) CHP: we have a reasonable handle on the “big” CHP settlement in Phase I, but missed the small plants and will explore sensitivities around this in Phase II.
***Table adapted from slide XX of NREL deck
1“Unspecified imports” are system power that is not California-owned or under long-term contract from specific facilities
2Exports include: California generation used to serve out of state load and California-contracted zero-carbon specified imports that are used to serve out of state load
32012 actual emissions were 95.1 MMT

11. Revenue Requirements for the Year 20301
Results: 2. Rate Impact
Revenue Requirements for the Year 20301
Target Case Costs
+ $5,300 Million
Target Case Savings
- $5,500 Million
Reduction in Revenue Required
Savings per Megawatt Hour (MWh)
Percent of 2012 rates
- $200 Million
- $0.6/MWh
- 0.4%
Forecasted prices:
Natural gas $6.18/MMBtu (EIA reference case)
Carbon $31.41/MMTCO2 (CEC low case)
Capacity $40/kw-yr
Weighted Average Cost of Capital (WACC) 7%
Selecting a diverse portfolio of energy generation and flexibility resources helps reduce net revenue requirement.
Cost savings from reduced fossil fuel use and avoided emissions costs balance out the cost to implement a low-carbon grid.
Lower gas use leads to lower consumer price risk.
The GHG target sets the amount of gas that can be burned, which determines the net short of required zero or low carbon additions. Picking the portfolio using a “best fit at least cost” criteria makes a dramatic difference from today’s trends, which are based almost exclusively on “least cost” with no real consideration for portfolio fit.
Once the portfolio is set, the cost depends on gas price, carbon price, and weighted average cost of capital (WACC). Using middle of the road, conventional wisdom, average forecasts for these variables in 2030, the rate impact is essentially zero.
**Is this too close to advocacy?
†See slide 14 for details

12. Investment portfolio, 2020 – 2030: supply-side
Results: 2. Rate Impact
Investment portfolio, 2020 – 2030: supply-side
Portfolio Element
2020 zero-carbon portfolio1
Incremental additions,
Baseline Case
Target Case
Capacity, MW
Capex, $million
Biomass
1,348 -
269
1,220
Geothermal
2,744
1,500
9,260
Wholesale solar PV
9,950
4,110
10,400
5,445
14,470
Solar Thermal
1,400
1,670
8,680
Wind
9,480
17,540
CC Gas
600
740
Storage
4,800
1752
700
2,375
4,270
Transmission
250
2,600
Total
12,090
57,940
Default 2025 capital costs for wind and solar PV are 10-15% higher than observed 2013 costs
1Based on 2012 LTPP. This includes contracted renewables both in and out of state.
2Represents small-scale storage built after 2020 (same in both cases).

13. Investment portfolio, 2020 – 2030: demand-side
Results: 2. Rate Impact
Investment portfolio, 2020 – 2030: demand-side
Portfolio Element
2020 portfolio
Incremental additions,
Difference in levelized utility program costs (in 2030)
Baseline Case
Target Case
Capacity, MW
Customer Sited PV
6,090
2,800
8,500
Energy Efficiency
4,3501
4,350
8,950
$155 million
Demand Response
2,1762
2,624
7,424
$25 million3
1Average of “mid” and “high mid” CEC efficiency forecasts for 2020
2CPUC 2014 LTPP planning assumption (for the year 2024)
3Placeholder for Phase I, will analyze in Phase II

14. Results: 2. Rate Impact
Phase I Estimated 2030 Revenue Requirement Impact Revenue requirement and savings associated with the Target Case, calculated relative to the Baseline Case.
2030 Revenue Requirement (million $)
Levelized Capex1
4,391
Fixed O&M
690
EE Program Charges
155
DR Program Charges 25
Capacity payments to DR providers2
192
Capacity payments to gas fleet2
(124)
Total
5,329
2030 Production Cost Savings (million $)
Fuel3
4,235
Variable O&M/start & shutdown3
371
CO2 emissions credits3
946
5,551
1Levelized capital charge calculated using capital expenditure from slide 12 and converted to levelized capital charge using WECC spreadsheet tool with 7% WACC.
2Capacity payments calculated by: taking the difference between DR use or peak gas dispatch between the Target and Baseline Cases and multiplying $40/kw-yr RA payment
3Production cost savings are outputs of NREL’s production cost model

15. California Net Imports
Results: 3. Import Flows
California Net Imports
2013 Actual1 1
Adding renewables and energy efficiency reduces imports slightly
Much of the imported gas in the Baseline case is replaced with imported renewables in the Target and Accelerated cases
Flows between regions in CA and throughout the Western Interconnection change significantly on only a few interfaces
Across many interfaces, flows that were from coal/gas generation are replaced with out-of-state renewables
Flows out of IID increase significantly due to geothermal development.
CA has net exports to NV, NM exports to AZ in Target and Accelerated Cases.
Import patterns show little variability between Cases.
Regional flows are not dramatically different from 2013.
2030 imports are approximately 50% of 2013 imports
Most imports and WECC trading in Target and Accelerated cases are zero-carbon energy, rather than coal and natural gas.
12013 total imports from Today's Outlook page on CAISO website; POU imports estimated

16. California Net Imports
Results: 3. Import Flows
California Net Imports
Case
Baseline
Target
Accelerated
CA annual net imports
(TWh)
53.2
41.4
38.3
Exports
-0.04
-0.6
-0.8
Total imports
42.0
39.1
Contracted imports
(Palo Verde + OOS RE for CA)
8.6 (Palo) +
18.6 (RPS)
8.6 +
42.4
59.1
Contracted imports that are
used inside CA
25.8
35.0
38.7
Contracted imports which are not imported to CA
1.4
16.0
29.0
Unspecified imports (Not counting specified imports used outside CA)
27.4
7.0
0.4
NREL SLIDE 36
Contracted imports are imports that come from a specific source outside CA (e.g., Palo Verde AZ nuclear plant, Wyoming wind, New Mexico wind)

17. Annual Net Interchange Between Regions
Results: 3. Import Flows
Annual Net Interchange Between Regions *
Flows throughout the Western Interconnection change significantly on only a few interfaces
Note starred flows
Across many interfaces, flows that were from coal/gas generation are replaced with out-of-state renewables
NREL SLIDE 39

18. California Gas Fleet Utilization – All Cases
Results: 4. Natural Gas/Grid Operations
California Gas Fleet Utilization – All Cases 1
From NREL 31
12013 CAISO gas usage from Today's Outlook page on CAISO website; POU gas usage estimated

19. California Gas Fleet Utilization – Target Case Only
Results: 4. Natural Gas/Grid Operations
California Gas Fleet Utilization – Target Case Only
Breakdown of three types of gas generation in 2030
Hours when in-state must-take gas (CHP) generation is below ~2500 MW is some combination of CHP “curtailment” or maintenance and forced outages
From NREL 31

20. Sources of Load Following Reserves
Results: 4. Natural Gas/Grid Operations
Sources of Load Following Reserves
Sources of Regulation
Sources of Contingency Reserves
Storage includes: pumped hydro, compressed air energy storage (CAES), and small storage under CPUC mandate
Zero-carbon sources provide most load following reserves and ancillary services, instead of the natural gas fleet
Flexibility reserve is intended to be online resources that respond to forecast error of load, wind and solar

21. Results: 4. Natural Gas/Grid Operations
Dispatch stacks (example)
Example: how to read dispatch stacks
Top graph shows supply-side dispatch and the shifted load
Difference between dispatch stack and load line represents imports and/or exports
Bottom graph shows load, demand-side flexibility, and storage charging
Difference between blue and black lines is load shifting/demand response. Grey shaded region is storage charging or pumping
NREL SLIDE 25
CC: combined cycle; CT: combustion turbine; CHP: combined heat and power

22. Results: 4. Natural Gas/Grid Operations
Dispatch stacks (Baseline)
Supply-side flexibility comes from CCs, CTs, and imports/exports
Overall load shape changes due to arbitraging storage devices, demand response, and partially schedulable charging of electric vehicles
NREL SLIDE 26

23. Results: 4. Natural Gas/Grid Operations
Dispatch stacks (Target)
Imports are reduced (compared to Baseline Case); CCs are dispatched more often in spring and winter; CCs are nearly baseload in summer
Load shifting becomes more aggressive and summer peak is reduced and moved earlier in the day to coincide with solar generation
NREL SLIDE 27

24. Results: 4. Natural Gas/Grid Operations
Dispatch stacks (Accelerated)
Similar to Target Case with less imports and gas generation
Additional storage allows for more aggressive load shifting during mid-day (high solar) hours
Demand response acts similar to Target Case
NREL SLIDE 28

25. Gas fleet utilization – summer typical five-day dispatch
Results: 4. Natural Gas/Grid Operations
Gas fleet utilization – summer typical five-day dispatch
High utilization of committed gas fleet
The CC fleet does not do a lot of daily cycling during the summer
NREL SLIDE 32
Solid line shows committed capacity of each generator type
Shaded region shows actual dispatched energy by generator type

26. Gas fleet utilization – spring typical five-day dispatch
Results: 4. Natural Gas/Grid Operations
Gas fleet utilization – spring typical five-day dispatch
High utilization of committed gas fleet
CC fleet sees daily cycling in Target and Accelerated Cases
NREL SLIDE 33

27. California Gas Generator Operation
Results: 4. Natural Gas/Grid Operations
California Gas Generator Operation
Baseline
Target
Accelerated
Average hours online per start
CA Gas CCs 85 52 57
CA Gas CTs
7.3
5.7
5.6
CHP-QF
222
174
161
Average heat rate (Btu/kWh)
7,700
7,500
7,400
9,800
9,500
9,600
Average fleet heat rate remains relatively constant, because while fleet capacity factor goes down, the committed fleet capacity factor remains high (see following slide)
This indicates that gas units are turning off, rather than turning down (especially low efficiency units)
Gas CCs are on for 2-4 days on average for each time they are started
Gas CTs are on for 5-10 hours each time they are started
NREL SLIDE 29

28. California Gas Generator Operation
Results: 4. Natural Gas/Grid Operations
California Gas Generator Operation
Baseline
Target
Accelerated
Fleet capacity factor (%)
CA Gas CCs
66.8
39.0
33.5
CA Gas CTs
22.2
10.8
10.4
CHP-QF
84.1
82.1
81.7
Committed fleet capacity factor (%)
(Average capacity factor of each unit only counting hours when the unit is online)
94.9
92.0
92.7
90.6
89.8
96.0
94.1
93.7
NREL SLIDE 30
Committed fleet capacity factor is high for all cases, indicating that gas units are turning off, rather than turning down
2013 committed capacity factor of CA CCs was ~80% and CTs was ~72% (based on EPA Continuous Emission Monitor data analysis done by the authors)

29. Conclusions Phase I Results
The LCGS analyzed California’s grid with a carbon focus, flexible load, regional cooperation, efficient use of natural gas, and diverse renewable generation
With this portfolio, the California electric sector can reduce GHG emissions by more than 50% below 2012 levels in 2030:
With minimal rate impact
Without compromising reliability
With minimal curtailment of renewable energy
With a stable gas fleet that is dispatched with minimum cycling
Significance
The Target Case modeled in this study illustrate a feasible, reliable, affordable and practical trajectory toward meeting California’s 2050 GHG goals.
The 2030 LCGS demonstrates that California can:
Achieve ambitious emissions reductions;
Lead the Western U.S. toward a sustainable, low-carbon electric sector;
Deploy unprecedented energy efficiency and efficient use of natural gas;
De-carbonize transportation by supporting significant use of electric vehicles;
Spur state-wide economic development from renewable energy, transmission, and energy storage projects.

30. Questions? More information: LowCarbonGrid2030.org Contact: