Transcript William Monsen - Independent Energy Producers

California Energy Markets:
Where We Have Been & Where We Are
Independent Energy Producers Association
Annual Meeting
September 20, 2012
William A. Monsen
MRW & Associates, LLC
Oakland, California
[email protected]
Overview of Presentation
Hypothesis
 Technological Changes
 Policy Changes
 Resulting Market Changes
 Wild Cards

2
Hypothesis
Over the past 10-15 years, we have seen
huge technological and policy changes
 These changes caused major changes in
the electric and natural gas markets in
California
 Market changes then induced additional
technological and policy changes

3
Technological Changes

Generation Technology

Combustion turbines and combined cycles


Solar & Wind


Decreased costs, particularly with photovoltaics
Natural Gas Extraction Technology


4
Improved efficiency and operating characteristics
Drilling technology
Hydraulic fracturing
Key Policy Changes

Wholesale Market Structure


CAISO and PX
QF and IPP programs
Resource Planning Approach
 Environmental Concerns




5
Limit fossil fuel use through RPS and Energy
Efficiency
Reduce GHG emissions
Control thermal emissions from OTC plants
Changes in Wholesale Market
Structure
In late 1990s, merchant generators would
replace QFs as the main generation
competitors for the IOUs
 Rise and fall of the California Power
Exchange (PX) day-ahead and hour-ahead
market
 CAISO introduces MRTU Upgrade in 2009



6
Introduced nodal pricing
Integrated forward market and day-ahead
market
Change in QF Policy
QF procurement policy defined
SRAC pricing linked to market
Utilities relieved of must-buy obligation (large QFs)



160
Market Index Formula
140
120
$/MWh
100
80
60
40
7
PG&E QF Price
NP15 Price
Sep-11
May-11
Jan-11
Sep-10
May-10
Jan-10
Sep-09
May-09
Jan-09
Sep-08
May-08
Jan-08
Sep-07
May-07
Jan-07
Sep-06
May-06
Jan-06
Sep-05
May-05
Jan-05
Sep-04
May-04
Jan-04
Sep-03
May-03
Jan-03
Sep-02
May-02
0
Jan-02
20
Resource Planning

After the Energy Crisis, shift from market-based
resource development to a more centralized
planning process



SB 1389 in 2002 requires the CEC to adopt a
biennial Integrated Energy Policy Report (IEPR)
SB 1078 in 2002 establishes 20% RPS



Originally 20% by 2017, then amended in 2006 to 20%
by 2010, followed in 2011 by an increase to 33% by 2020
Targets to be met through annual renewable RFOs
2003 interagency Energy Action Plan sets new
priorities

8
Result is longer-term PPAs and utility-owned generation
Establishes “Loading Order”
Renewable Cost Containment

Supplemental Energy Payments (SEPs)



Above Market Funds (AMF)





9
Established by SB 1078 in 2002
CEC funds available to generators to cover costs
above the Market Price Referent
In 2007 SB 1036 replaced SEPs with AMF program
Electric corporation now responsible for cost
recovery of above-market transactions
Maintained total cap on available funds
Utility AMFs exhausted by the end of 2009
New cost-containment approach being
developed pursuant to SB1X-2
Energy Efficiency Policy



Energy Action Plan established energy efficiency
as the first priority in California’s loading order
AB 32 emphasized energy efficiency savings
CPUC has been active in this area



10
D.07-09-043 authorized the RRIM, an reward/penalty
system to encourage utility energy efficiency savings
Long-Term Energy Efficiency Strategic Plan adopted in
September 2008, setting goals for maximizing efficiency
savings through 2020 and beyond
Current CPUC rulemaking proceeding (R.09-11-014) is
examining post-2012 energy efficiency policies,
programs, and evaluation approaches
GHG Regulation

California Global Warming Solutions Act of
2006 (AB 32)


Set goals for GHG emissions reduction by 2020
Directed California Air Resources Board to
oversee implementation
Rise and Fall of Western Climate Initiative
 California Trudges On




11
Cap and Trade regulation
First Seller Approach
First Auction to take place this November for
compliance in 2013
Current Plans for Once-through
Cooling Units


CAISO identified a need of ~2,400 MW of replacement OTC
generation in the Western LA Basin with similar flexibility
characteristics as existing units (more capacity if less flexible or
farther from coast)
Huntington Beach re-started in response to SONGS outage; ultimate
outcome for both SONGS and Huntington Beach uncertain
14,000
Cumula ve Capacity (MW)
12,000
10,000
8,000
6,000
4,000
2,000
0
2012
12
2013
Re red
2014
2015
Repowered
2016
2017
Other Measures
2018
Uncertain
2019
2020
Markets React to Technology and
Policy Changes

Changes in resource mix




Fuel prices



13
Lots of development with greater fuel and size
diversity
Need for integrating resources
New transmission projects
Lower gas prices push down cost of fossil
generation
Creates benchmark competition for renewables
Power prices
California In-State Generation Mix
2000
14
Source: CEC Energy Almanac
2011
Source of Imported Electricity

Imported electricity has become less
carbon intensive
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Direct Coal Imports
15
Source: CEC Energy Almanac
Other Imports
New Constraint on Planning Process
Need for renewable integration has
created demand for flexible generation
 Planning reserve margin concept is
evolving
 Additional flexibility requirements may
pre-empt planning reserve margin
 Risk is shifting from a generation outage
risk to a grid outage risk

16
A Decade of Transmission Policy




17
Transmission development not a major issue prior
to the energy crisis; now part of daily dialogue
2003 Energy Action Plan identifies upgrading and
expanding transmission and distribution
infrastructure as one of its critical actions
SB 1565 in 2004 requires CEC to adopt a Strategic
Transmission Investment Plan in its biennial IEPR
Several new planning schemes have sprung up in
last decade: RETI, Federal transmission corridors,
California Transmission Planning Group (CTPG)
Post-Energy Crisis Historical Gas and
Electricity Prices
200
16
Hurricane Katrina
180
Heat-Related
Electricity Price Spikes
14
160
2008 Recession
12
10
120
100
8
80
6
60
4
40
2
NP15 Power Price
Source: Megawatt Daily and Platt’s Gas Daily.
18
Malin Gas Price
Jan-12
Sep-11
May-11
Jan-11
Sep-10
Jan-10
May-10
Sep-09
May-09
Jan-09
Sep-08
May-08
Jan-08
Sep-07
May-07
Jan-07
Sep-06
May-06
Jan-06
Sep-05
Jan-05
May-05
Sep-04
May-04
Jan-04
Sep-03
Jan-03
May-03
Sep-02
May-02
0
Jan-02
20
0
$/MMBtu
$/MWh
140
Recession and RPS Affect Wholesale
Electric Market

Lower loads and more must-run resources
increase reserve margins and drive down market
heat rates
16,000
Market Heat Rate Btu/kWh
14,000
12,000
10,000
8,000
6,000
4,000
2,000
-
02
02
03
03
04
04
05
05
06
06
07
07
08
08
09
09
10
10
n- Jul- an- Jul- an- Jul- an- Jul- an- Jul- an- Jul- an- Jul- an- Jul- an- Jula
J
J
J
J
J
J
J
J
J
19
Adjusting to The New Market Realities
(a.k.a. Dealing with Collateral Damage)
To meet aggressive RPS targets,
regulators expand range of procurement
options
 Greater concerns about rates increases
focus on renewable cost containment
 Offtakers expect option to order economic
curtail generation from new renewables
 Starting to see impacts of GHG legislation
in forward prices

20
Policymakers Pursue Range of
Renewable Projects to Meet RPS
Game is no longer only about large project
solicitations
 New market options create opportunities
for renewable projects of all sizes




21
Renewable Auction Mechanism (1-20 MW)
Feed-in Tariffs (less than 3 MW)
Net Metering (less than 1 MW)
Some Wild Cards Still Lurking

Nuclear future




Energy efficiency and demand response


22
Current licenses expire in 2022 and 2024
Prior assumption that plants would be relicensed and operate for at least another 20 yrs
SONGS 2&3 steam generators and Diablo
seismic studies
How to integrate “uncommitted resources” into
planning process
Development of formal capacity market
Questions? Comments?
MRW & Associates, LLC
Oakland, California
[email protected]
Supporting Materials
24
Demand Forecasts
25
Demand Forecasting: Expect Bumps in the
Road
Source: CEC Demand Forecasts 2000, 2007 and 2012
26
Current Demand Forecast
Source: CEC Demand Forecast 2012
27
Generation Technology and Cost
28
Combustion Turbines and Combined
Cycles
2000
CCGT
CT
6,800
9,100
600
360
Purpose
Baseload
Peaking
Flexibility
Poor-Fair
Good-Excellent
6,470
8,550
957
801
Purpose
Intermediate
Peaking
Flexibility
Fair-Excellent
Good-Excellent
Heat Rate (Btu/kWh)
Overnight Capital Costs ($/kW)
2009
Heat Rate (Btu/kWh)
Overnight Capital Costs ($/kW)
Sources: “Market Clearing Prices Under Alternative Resources Scenarios,” CEC Staff Report,
February 2000; Klein, Joel. 2009. Comparative Costs of California central Station Electricity
Generation Technologies, California Energy Commission, CEC-200-2009-017-SD. January 2010
29
Capacity-Weighted Average
Installed Cost (2010$/WDC )
Behind-the-Meter Solar PV Cost
$12
Global Module Price Index
Implied Non-Module Cost (plus module cost lag)
Total Installed Cost (Behind-the-Meter PV)
$10
$8
$6
$4
$2
$0
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
Installation Year
Notes: "Implied Non-Module Cost (plus module cost lag)" is calculated as the reported Total Installed Cost minus
Navigant Consulting's Global Module Price Index.
Figure 8. Average Installed Cost, Module Price Index, and Implied Non-Module Costs over Time for
Behind-the-Meter PV
Source: Barbose, Galen et al. Lawrence Berkeley National Laboratory. Tracking the Sun IV:
An Historical Summary of the Installed Cost of Photovoltaics in the United States from 1998
Figure
8 also presents
to 2010.
September
2011 the “implied” non-module costs paid by PV system owners – which
30
may
include such items as inverters, mounting hardware, labor, permitting and fees, shipping, overhead,
taxes, and installer profit. Implied non-module costs are calculated simply as the difference
between the average total installed cost and the wholesale module price index in the same year;
not attempted a comprehensive survey, NREL40, for example, specifies an installed cost of $3.8/W
for prototypical fixed-tilt crystalline systems, $4.1/W for fixed-tilt thin-film systems, and $4.4/W
for single-axis crystalline systems, all at an assumed size of 188 MW and installed in the second
half of 2010. SEIA/GTM41 cite an average cost of $3.9/W for utility-sector systems of unspecified
size and configuration and installed in the first quarter of 2011. Finally, RW Beck42 estimates the
average cost of a fixed-tilt crystalline utility PV system installed in late 2010 at $3.8/W for a 188
MW system and $4.2/W for a 10 MW system.
Utility-Scale Solar PV Cost
Installed Cost (2010$/WDC )
$10
Utility-Sector PV
$8
$6
$4
$2
$0
2004
n=2
8.0 MW
2005
n=0
0.0 MW
2006
n=0
0.0 MW
2007
n=2
22.4 MW
2008
n=3
18.0 MW
2009
n=4
56.2 MW
2010
n=20
180.0 MW
Installation Year
Notes: The figure includes a number of relatively small wholesale distributed PV projects as well as several “one-off”
projects. In addition, the reported installed cost of projects completed in any given year may reflect module and other
component pricing at the time of project contracting, which may have occurred one or two years prior to installation.
For these reasons and others (see Text Box 1), the data may not provide an accurate depiction of the current cost of
typical utility PV projects and may not correspond to recent cost benchmarks for utility PV.
Figure 29. Installed Cost over Time for Utility-Sector PV
31
Source: Barbose, Galen et al. Lawrence Berkeley National Laboratory. Tracking the Sun IV:
An Historical Summary of the Installed Cost of Photovoltaics in the United States from 1998
to 2010. September 2011
The Installed Cost of Utility-Sector Projects Depends on Project Size and System
Resource Classes (without PTC/MACRS)
Based on current pricing and assumptions: 100m rotor diameter is found to be
Levelized Cost of Wind Energy without
economically attractive in comparison to 2012-2013 ‘Standard Technology’ where
can be
deployed; a wind sheer higher than 1/7 is found to be needed for the 100m
Incentives
tower to be least cost in comparison to the 80m option (with the 100m rotor)
th
Levelized Cost of Energy ($/MWh) No Incentives
$160
$140
1
$120
2
2009‐10: Standard Technology
$100
$80
$60
2002‐03: Standard Technology
Current, 2012‐13: Low Wind‐speed (100m Tower)
$40
Current, 2012‐13: Standard Technology
Current, 2012‐13: Low Wind‐speed (80m Tower)
$20
$0
5.5
6.0
Class 2
6.5
7.0
7.5
Class 3 Class 4 Class 5
50m Wind‐speed (m/s) 8.0
8.5
Class 6
(air density = 1.225 kg/m3)
Source: Wiser, Ryan et al. Lawrence Berkeley National
28Laboratory and National Renewable
Energy Laboratory. Recent Developments in the Levelized Cost of Energy from U.S. Wind
Power Projects. February 2012
32
EIA Estimated Levelized Cost of
Energy (without incentives)
Source: EIA AEO (July 12,2012)
33
Market Share and Development
34
California In-State Generation Mix
Renewables
Natural Gas
Nuclear
Hydroelectric
In-State Coal
2000
11%
49%
20%
19%
1%
2001
12%
57%
17%
12%
2%
2002
13%
50%
18%
17%
2%
2003
12%
49%
18%
19%
2%
2004
12%
53%
15%
17%
2%
2005
12%
48%
18%
20%
2%
2006
11%
50%
15%
22%
2%
2007
12%
57%
17%
13%
2%
2008
12%
59%
16%
12%
2%
2009
13%
56%
15%
14%
2%
2010
12%
53%
16%
17%
2%
2011
14%
45%
18%
21%
2%
Source: CEC Energy Almanac
35
California In-State Generation Mix
2000
36
Source: CEC Energy Almanac
2011
Electricity Imports

Imports’ share of total generation has
been steady since the Energy Crisis
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Imports
37
Source: CEC Energy Almanac
California Genera on
Source of Imported Electricity

Imported electricity has become less
carbon intensive
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Direct Coal Imports
38
Source: CEC Energy Almanac
Other Imports
New Conventional Plant Development
(CEC Jurisdictional)
4,500
4,000
Capacity (MW)
3,500
3,000
2,500
2,000
1,500
1,000
500
0
2001
2002
2003
2004
Independent Power Producers
Source: CEC Project Database
39
2005
2006
2007
Investor-Owned U lity
2008
2009
2010
Publicly-Owned U lity
2011
2012
Combined Heat and Power Forecasted
Market Penetration
Base
Medium
High
40
Source: ICF International, Combined Heat and Power: Policy Analysis 2011-2030 Market
Assessment, Prepared for the California Energy Commission, June 2012
Statewide Renewable Development (All
generators, including IOUs and POUs)
Source: CEC Energy Almanac
41
Transmission
42
Major RPS-related Transmission
Projects
Project
Tehachapi 1-3
Tehachapi 4-11
Sunrise
Status
Completed
Approved
Completed
Renewable
Potential (MW)
4,500
1,700
Online
2009
2015
2012
Devers-Palo Verde No. 2
Approved
West of Devers
No Permit
Eldorado-Ivanpah
Approved
1,400
2013
On Hold
1,750
2017/18
Path 42
Approved
1,400
2014
Green Path North
Cancelled
N/A
N/A
Lugo-Pisgah
43
4,700
2013
2017
Impact of GHG on Market Pricing
44
Greenhouse Gas Costs In Forward
Power Prices
Source: Dumoulin-Smith, Julien. UBS. “Energy Investment: What’s Driving Fossil
Resources?” Presentation to the Climate Trust in Portland OR, July 2012. p. 10.
45
Greenhouse Gas Costs in Implied
Market Heat Rate
SP15 Implied Market Heat Rate
11,600
11,400
11,200
11,000
10,800
10,600
10,400
Q4 2012
2013
2014
Sources: Platts Forward Electricity Price Curve and NYMEX Natural Gas Futures
Prices
46
2014
Demand-Side Resources
47
Uncommitted Energy Efficiency

High expectations, but what do we do with it?
Forecasted Mid-Case Incremental
Uncommitted Energy Efficiency Savings
16,000
3,500
14,000
3,000
12,000
2,500
10,000
MW
GWh
2,000
8,000
1,500
6,000
1,000
4,000
500
2,000
-
2011
2012
2013
2014
2015
2016
Energy (GWh)
48
2017
2018
2019
2020
2021
2022
Demand (MW)
Source: California Energy Commission. Estimates of Incremental Uncommitted Energy
Savings Relative to the California Energy Demand Forecast 2012-2022
How Real Have Energy Efficiency
Savings Been?
2006-2008
PG&E
SCE
SDG&E
SCG
Total
2,826
3,135
638
-
6,599
613
672
122
-
1407
45
-
10
57
112
5,251
3,898
850
-
9,999
845
690
47
-
1,682
66
-
7
67
140
1,766
1,963
364
-
4,093
320
384
72
-
776
22
-
3
32
57
CPUC Goals
Energy (GWh)
Peak (MW)
Natural Gas (MMth)
Reported
Energy (GWh)
Peak (MW)
Natural Gas (MMth)
Evaluated
Energy (GWh)
Peak (MW)
Natural Gas (MMth)
49
Source: Lewis, Kae, Che McFarlin, Cynthia Rogers, Doug Kemmer. 2011. Achieving Cost-Effective
Energy Efficiency for California 2011-2020. California Energy Commission, Electricity Supply
Analysis Division. CEC-200-2011-007-SD. Appendix B, pp. B-2 – B-3