Western Climate Initiative Comments
Economic Modeling Results
February 22, 2010
These comments are submitted on behalf of WEST Associates, a coalition of 16 western
electric utilities with ratepayers in the partner states of the Western Climate Initiative
(WCI). WEST Associates ("WEST") is concerned about understanding the specific
ENERGY 2020 model functioning and its outputs related to the electricity sector.
Currently the WCI presentation of the economic modeling results is sufficiently opaque
that WEST members are unable to trace the causes and interactions of the model which
produce the generalized economic results currently available in the WCI's September 23,
2008 "Appendix B: Economic Modeling Results."
Up to half of the total GHG emissions reductions required by 2020 under the WCI cap
come from the Power Sector (50% to 39% depending on the policy case), yet the WCI
does not provide transparent and detailed accounting of the costs to the power sector to
achieve those results. WEST members require a specific, detailed understanding of how
the ENERGY 2020 model generates its economic impact results. This is because it is
critical that regulated utilities supply their electric utility commissions with data
prudently justifying environmental mitigation costs. As utilities provide input to
regulators designing emission reduction programs, without transparent cost information,
utilities cannot provide regulators with prudent feedback on program design elements.
Specifically, WEST is providing comments and raising question about the economic
modeling results in the following areas of the September 23, 2008 Appendix B results:
How are the Complementary Policies Derived & Implemented?
Based on the three policy cases, as high as from two-thirds to all of the cap's Power
Sector reductions can be attributed to implementation of "Complementary Policies" (i.e.,
Energy Efficiency Programs).1 The WCI does not provide transparent detail explaining
implementation of Energy Efficiency Programs for the Power Sector to achieve those
results. Clearly energy efficiency programs of this magnitude will likely have net costs
to electricity customers. Yet, the costs of these programs are not mapped to electricity
rates or Power Sector costs provided in Appendix B. For each policy case, the WCI
should break out separately the costs of GHG emissions reduction effects in the year
2020 that result from the Complementary Programs assumptions and results.
Electric Power Sector Costs Left Out of Total Accounting
Definitely more than half -- 68% to 100% assuming decrements in load displace gas generation at a heat rate of
9.8MMBtu/MWh, as summarized in the table below based on Appendix B data and WEST Associates assumptions on
marginal heat rate for displaced gas generation due to energy efficiency. Moreover, WCI results show coal generation
also going down which could imply the % reductions attributable to the complementary programs is even higher.
desiganted HR Broad-wOff Broad-NoOff Narrow-wOff
Est. Marg. Heat Rate for Gas 9,784 9,784 9,784 (Btu/KWh)
Marg. CO2 Intensity 0.53 0.53 0.53 (Btu/KWh)
Estimated Complementary tons 45.4 45.4 48.8 (tons - millions)
Cap-&-Trade tons 0.0 16.9 23.3 (tons - millions)
Total reduction 45.4 62.3 72.1 (tons - millions)
% Complementary 100% 73% 68%
% Cap-&-Trade 0% 27% 32%
In Appendix B, Table B-19 does not show the cost impacts to the Electric Power Sector.
WEST is concerned that several cost components are either left out or are inappropriately
accounted for. For example, Table B-16 shows that residential and commercial electric
rates remain basically flat (or a slight reduction) by 2020 for the broad policy options.
Only the Narrow policy option shows an increase in those rates. Yet as a corollary, Table
B-14 shows a 24% increase (over the Reference Case) in generation capacity for all three
policy cases with coal, hydro and nuclear capacity remaining flat, and wind capacity
showing about a 6-7% decrease. Clearly this shows a significant capital cost investment
for natural gas generating capacity. Yet the capital cost recovery in electricity rates is
apparently completely ignored in terms of assessing the true cost impact of the WCI cap
and trade program. Furthermore, the cost to fuel combustion based electricity generators
resulting from acquiring GHG emissions allowances for compliance appears to be
completely left out of the economic modeling cost assessment. During the November 7,
2008 WCI Economic Modeling conference call/webinar, Michael Gibbs (CA) stated, in
effect, that the ENERGY 2020 reported electricity prices do not include the allowance
costs. Those costs were assumed to be utility "pass through" costs, as was stated, "much
like a fuel cost." This is disingenuous. Indeed, electricity ratepayers will actually see
those "pass through" costs for allowances directly accounted for and included in their
cents per kilowatt-hour rate costs. And, this cost effect is traceable back to a singular
causation for such costs -- namely, the direct effect of the WCI's cap and trade program.
Not including allowance costs could be interpreted as a commitment to providing a full
and free allocation of GHG allowances to ratepayers -- contrary to the WCI's other
indications to design the Cap and Trade Program in a manner that would auction GHG
allowances to covered sources for meeting their compliance obligations.
Furthermore, WEST notes that by 2020, the average capacity factors for natural gas
generation declines from 21 % in the Reference Case down to 13 % in the Narrow with
Offsets policy case. With the ~ 24% increase in natural gas generation capacity above
the Reference Case, and in light of the projected drop in natural gas generation capacity
factors, begs the question about what type of gas fired generation capacity is assumed to
be added and what will that capacity cost. With lower capacity factors, is the WCI
assuming that natural gas capacity additions will be primarily combustion turbine
peaking capacity? Or will the gas capacity be combined cycle combustion turbine
facilities? Depending on the assumption preference for simple cycle peaking versus
combined cycle capacity additions can have a significant cost difference. Nevertheless, if
the WCI is assuming all additions of combined cycle combustion turbine (CCCT)
capacity the projected increase in natural gas capacity costs would likely be ~ $19 billion
in capital costs. Clearly this magnitude of capital cost and its recovery in electricity rates
has not been accounted for and reported in the Economic Modeling results. Finally,
WEST Associates requests to see the Economic Model's cost impacts and allowance
values as distributed by state or partner.
Accordingly, WEST urges and demands that the WCI fairly report, represent, and detail
the full cost impacts to electricity ratepayers in reporting the WCI's Economic Modeling
results. WEST appreciates comments made by Mr. Gibbs and others on the EMT stating
that the true costs to the electric Power Sector would be detailed and provided by the
December 3, 2008 Economic Modeling Conference In San Francisco, CA.
How Does the Electricity Sector Cut its GHG Emissions?
Table B-12 shows WCI assumed a 70 MMTCO2E level of emissions for the Non-WCI
Power Sector, and a reduction of 37 to a 45 MMTCO2E from that Non-WCI Power
Sector. Specifically, how were those reductions determined, particularly in the light of
the WCI's planned use of First Jurisdictional Deliverer procedures to account for Non-
WCI power sector GHG emissions? Equally important for WEST Members is to
understand the functioning and results of the ENERGY 2020 modeling of the proposed
WCI cap and trade program and how the WCI's use of the model actually cuts power
sector emissions within the WCI cap. Currently WEST members cannot trace how the
model has made these calculations. Can we see electric sector fuel use by fuel type? Can
we see what type of natural gas generating capacity is added, and when, by generator
type (i.e., CT peakers vs. CCCT combined cycle unit capacities)?
Methodological Issues Regarding Banking and Offsets
The Appendix B, "Figure B-1: Assumed Offset Supply Curve" shows a basic allowance
price assumption versus the Cap and Trade Program Design percent of allowable offsets.
With the program design's intent to limit the supply of offsets to <50% of the annual cap,
the curve shows an upper limit price of $20 per ton. The basis of the shape of this curve
is obscure. WEST's observation is that the arbitrary shape of this curve floods the market
at the $16 to $22 per ton range. Clearly, the Economic Modeling Team's assumption
about the shape of this curve will have a significant impact on the Economic Model
results and cost impacts. Please provide the WEST members and the public with a
clearly rationalized basis for this curve. Additionally, it would be useful to show a curve
range (a range of offset supply and demand prices). Such a range of offset prices should
be included in additional ENERGY 2020 modeling scenarios.
Also, in Appendix B, "Figure B-2: Banking Curves," WEST notes again that the
derivation of this trough curve appears to be arbitrary. Flows (banking vs. usage rates) of
banked offsets have similarly large impacts on the Economic Modeling results. The data
depicted in Figure B-2 seems to set forth an entirely arbitrary set of assumptions about
economic behavior by stipulating that banking would occur around $10 per ton and
withdrawals would occur around $20 per ton. These nominal amounts appear to be used
literally in the functioning of the model's calculations. This ad hoc nomogram appears to
violate good economic analysis methodologies and reasonable attempts at best
understanding economic behavior.2 Again it is important that WCI present a rationale
For example the table below illustrates an anomaly in the functioning of the model when the ad hoc nomogram is
applied literally. As a result the model produces illogical results showing rather robust banking and use of offsets at an
$18 price differential (2015 to 2020); but no banking and use of offsets at a $52 price differential over the same time
range. [Footnote continued, bottom of next page].
basis for and presentation of a range of banking price and offsets use price thresholds.
The Economic Modeling Team should also include a range of banking price and offsets
use price thresholds by including additional ENERGY 2020 modeled scenarios for the
WCI cap and trade program.
WCI Should Enhance the ENERGY 2020 Modeling Sensitivity Scenario Analysis
In addition to evaluating additional offsets and banking price and economic behavior
scenario ranges discussed above, there are other important variables that should also be
tested by scenario modeling. For example, the Energy Efficiency, and other policy
programs in the Complementary Policies should be evaluated in terms of varied
implementation effectiveness ranges. Given the magnitude of WCI's assumed GHG
reductions resulting from Complementary Policies, it is critical that the Economic
Modeling of the CAP and Trade program not fixate on a singular assumed level of
Complementary Program effectiveness. Also, the Non-WCI level of assumed electric
power imports (and GHG emissions) should undergo a sensitivity analysis. Finally, the
WCI should consider modeling scenarios with varied assumptions about Renewable
Performance Standard achievement rates, along with the various partners' (e.g.,
Heavy use of banking
w. $18 spread
Bank Flow 21.2 -31.8 (tons - millions)
Allowance Price $6 $24 $/ton
Bank Flow 0 -0.2 (tons - millions)
Allowance Price $19 $71 $/ton 7
No banking despite $52
California) plans for increasing RPS requirements in future years (by 2020, or thereafter
for that matter, because of the escalating implementation curve effect on RPS
performance by year 2020 that could result from, say, a 2025 or 2030 increased RPS to
33% as proposed in California). Such future regulatory changes in electric energy would
have significant impacts on assessing economic impacts from the proposed WCI cap and
Nevertheless, WEST Associates believes the biggest issue is the Complementary
Program. The WCI GHG emissions cap is set at 85% of 2005 emissions, and that cap
sets the basis for the number of allowances that will be distributed and/or auctioned. The
ENERGY 2020 economic analysis is measuring how costly it will be to meet this cap, but
the starting point is critical due to the rising cost of marginal abatement (the more one
abates the more expensive it becomes to abate further – due to the “do the cheapest first”
rule). If the Complementary Program leads to just a 50% reduction of the required
abatement expected (and modeled) from the Complementary Program (vis-à-vis the
Reference Case), then the abatement challenge for those subject to the cap and trade
policy is doubled, and the resulting allowance price will be much higher. Blending the
effects of the Complementary Program with the different cap and trade policy
formulations hides the effect of the starting point. WEST believes that stakeholders need
to see results from a Complementary Policy-Only Case in all the level of detail presented
for the cap and trade policy cases, plus the added detail on the electric sector we’ve asked
The Figures and discussion below illustrate this point.
Emission Trajectory Assumptions and Abatement Required
Cap & Trade Emissions (tons - millions)
2006 2010 2015 2020
BAU w. Complementary tons WCI Cap (Allowances Created) C&T Abatement Needed to Meet Cap
Figure 1 above shows the cap & trade (C&T) abatement needed to meet the cap, equal to
the difference between the cap (colored aqua) and the emissions starting point (yellow),
namely the Reference Case with the Complementary tons taken out (WEST has only
estimated this, as WCI hides this quantity).
Figure 2 below adds the Reference Case. The Draft Design Recommendations do not say
who is responsible for achieving the Complementary Program results, but the Cap
doesn’t change and so ultimately the regulated entities will be responsible. Will they be
indemnified if the Complementary Program is ineffectual? Does it happen for free? The
Draft Design Recommendations make an allusion to paying for it with allowance
revenues that implies those receiving allowance revenues would be responsible.
However to expect the regulated entities to pay for it with allowance revenues would
require giving them allowances above and beyond the cap which WEST does not believe
is what WCI intends. This discussion does raise concerns about the whether the WCI
design of these features in the Cap and Trade Program is being developed in a
straightforward and authentic manner.
Emission Trajectory Assumptions and Abatement Required
Cap & Trade Emissions (tons - millions)
2006 2010 2015 2020
Reference Case tons BAU w. Complementary tons
WCI Cap (Allowances Created) Total C&T + Complementary Abatement
C&T Abatement Needed to Meet Cap
In conclusion, WEST Associates believes it is essential that the WCI provide open,
transparent and detailed input-output data and information on its ENERGY 2020
modeling for the WCI Cap & Trade Program. WEST acknowledges the statements made
by the WCI Economic Modeling Team during the November 7, 2008 Economic
Modeling Conference Call indicating that in response to questions raised during that call,
and anticipated comments and questions to be submitted by stakeholders, additional data
and economic modeling information will be made available by the December 3, 2008
Economic Modeling Workshop in San Francisco, CA. We look forward to continued
participation in this important public process.
Should you have any questions, please do not hesitate to contact David Steele at (520)
Thank you for your consideration.