20031215Advocates of the West.pdf

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December 15 , 2003 !C; FUGUe
UTILITIES cm-iMISSIONJean Jewell, Commission Secretary
Idaho Public Utilities Commission
472 W. Washington St.
Boise, ill 83702-5983
Re: Comments on IPC-03-12 (Bennett Mountain Power Plant proposal)
Dear Ms. Jewell:
Advocates for the West requests that the Commission consider these comments on Idaho
Power s request to rate base construction costs of a new 162 MW simple-cycle gas fired
power plant (the Bennett Mountain Plant). Advocates for the West is a nonprofit
conservation law and advocacy center, which supports renewable energy resources and
energy efficiency improvements. The undersigned staff attorney for Advocates for the
West is a member ofIdaho Power s 2004 Integrated Resource Plan Advisory Group.
Unnecessary Division of General Rate Case and Power Plant Case
From the ratepayer s perspective, there is no basis for the Company to seek significant
additions to its rate-based costs through two separate concurrent proceedings before the
Commission: the general rate case (IPC-03-13), and this matter. Excepting the
Company s stated need for its contractor to receive a notice to proceed on or before
December 31 2003 , there seems to be no logical barrier to the Commission considering
all requested additions in costs to the 'rate base concurrent with (or even consolidated
into) the general rate case. Indeed, the December 31 deadline appears to be a soft one
and therefore deserving of little consideration by the Commission. See e.
g.
Testimony of
Greg Said p. 19 at 1. 21-23 ("
..
. Mountain View Power has indicated it needs to receive
a notice to proceed on or before December 31 , 2003.
The parties to the general rate case have agreed to a scheduling order that would allow for
implementation of new tariffs by June 1 2004. A five month delay under these unique
circumstances is entirely reasonable.
Consistency With 2002 IRP Does Not Assure Prudency
We look forward to a day when IRP's can be useful in actual resource acquisition
proceedings. Idaho Power s 2002 IRP, however, should not be looked to as providing
any basis of reasonableness for this particular acquisition.
The Company s 2002 IRP was roundly criticized by a diverse range of parties, many of
which (including Commission Staff) urged rejection of the Plan. While the Commission
ultimately accepted the 2002 IRP (in part recognizing that the 2004 IRP development
P.O. Box 1612, Boise, 1083701 208-342-7024 Fax: [phone] www.AdvocatesWest.org
process was about to commence), a review of the findings in Order No. 29189 are
illustrative:
-- "
The Commission finds that to satisfy the present and future requirements of
this Commission and to provide reasonable notice to interested parties the
Integrated Resource Plan document prepared by Idaho Power must change.
-- "
We. . . agree that for a plan to be integrated it must include not only supply
options available to the Company but a considered and reasoned discussion of
available demand options.
-- "
We remind the Company that under the Certificate it holds it must
demonstrate that it manages, operates and provides services under least cost
principles that require both efficiency and economy. Believing many DSM
programs involving conservation, efficiency improvements and/or load
shaping may sometimes by the least cost resource, we expect the Company
will have seriously exhausted and signed up all available cost-effective DSM
prior to building a utility owned supply-side resource or going out for a
request for proposals for third party or contract supply-side resources.
Alternatively, the Company should be prepared to demonstrate the prudence of its
operational decisions.
Order No. 29189 at 20-21 (emphasis added).
Weare hopeful that the 2004 IRP will reflect a significant improvement over the 2002
Plan. At this point, however, the 2002 Plan should not be used as any basis for a
determination ofprudency for this Application. Moreover, as set forth below, the
Company certainly has not adhered to the Commission s admonition to "have seriously
exhausted and signed up all available cost-effective DSM prior to building a utility
owned supply-side resource or going out for a request for proposals for third party or
contract supply-side resources.
Alternative Resources Have Not Been Fully Explored
The Commission should demand Idaho Power better explain its exclusion of other
alternatives to meet peak load demands, aside from the proposed power plant. We are
confident one other alternative should receive primary attention: peak load management.
Indeed, for over a year the Company has been in the process of developing (through a
contractor) a study of peak load management options. Although we understand it may be
complete soon, the study still is not even complete; much less have all cost-effective peak
load management or reduction resources been fully exhausted. The current residential
air-conditioning cycling programs holds some significant promise, but is expected to
include only 500 customers by summer 2004.
Comments -- 2
The Testimony of Greg Said, filed by the Company in support of its application, touts a
renewed irrigation efficiency program as potentially reducing peak load. We strongly
support investments in efficiency improvements for the irrigation community, but the
existing program is modestly funded and not designed to target peak load reductions with
particularity.
Therefore, we specifically request that the Commission stay this case pending release of
Idaho Power s peak load management study and implementation of cost effective
programs for peak management.
Idaho Power also should have requested bids for other resources, including wind power.
The Company expects first year operating and fuel costs for the Bennett Mountain plant
to be 5.7 cents/ kWh (based upon $4.52/MMBtu gas). Currently, wind power costs about
3 cents/kWh (or about 4 to 4.5 cents without the federal production tax credit) - and these
costs are stable over the plant's lifetime.
Wind is a cost-competitive resource alongside natural gas, even for targeting peak load
needs. The Colorado Public Utility Commission has ruled "on purely economic grounds
that the acquisition of wind plant resource was preferable to a request by Xcel Energy to
employ a gas-fired plant at $3.50/MCF gas. See CPUC Decision No. COl-295 , at p. 34;
see also, Lehr, R. et at. Colorado Public Utility Commission s Xcel Wind Decision
NREL/CP-500-30551 (2001).
We agree that wind should be subject to a capacity value determination e. the value of
wind power to serve peak loads. In ordering Xcel Energy to enter into good faith
negotiations for a wind plant the Colorado PUC allowed the utility to determine this
capacity value.
The Commission should not approve a major addition to the rate base absent a careful
exploration of alternatives, including DSM and wind.
Ratepayers Must Not Bear the Full Risk of Increasing Gas Prices
We request the Commission consider implementing certain measures to mitigate the
potential risks to customers from predicted increases in natural gas prices. While
construction costs of the Bennett Mountain Plant may be low relative to other generation
resources, operating costs will be tied directly to the whims ofthe natural gas market. A
recent paper published by the Lawrence-Berkeley National Lab confirmed that "(tJhe cost
of natural gas can account for more than half the levelized cost of energy from a new
combined cycle gas turbine, and more than 90% of its operating costs.
See Bolinger, Wiser, and Golove
, "
Accounting for Fuel Price Risk: Using Forward Natural Gas Prices
Instead of Gas Price Forecasts to Compare Renewable to Natural Gas-Fired Generation" (Lawrence
Berkeley Lab, August 2003) at p. ix (full report is available at .:::http://www-
library.lbl.gov/docs/LBNL/535/87/PDF/LBNL-53587.pdt::-). The Executive Summary of this report is
attached to these comments.
Comments -- 3
The National Petroleum Council issued a report to the U.S. Department of Energy in
September 2003, which predicted future increases in natural gas prices absent significant
new drilling or efficiency improvements. See Balancing Natural Gas Policy - Fueling
the Demands of a Growing Economy" (Sept. 25 2003) ("NPC Report,,
The NPC report predicts that even with significant changes in national energy policy
(including efficiency improvements, funding for of an Alaskan gas pipeline, and
increased drilling in the lower 48 states), prices may escalate to close to $6 per MMBtu
by 2005, and continue to range upward toward $7 per MMBtu. Current prices are in the
range of $4.50 to $5.00 per MMBtu. Given that the gas industry itself drafted the report
we believe these conclusions are probably quite conservative. Of course, the future cost
of gas is unknowable, and any assumptions of such costs at this point would be
speculative.
Other factors beyond the scope of the NRC Report will likely push gas-fired power plant
operating costs higher still. For example, the electric industry itself is recognizing and
evaluating costs related to future carbon emission regulation. The cost-effectiveness
analysis in PacifiCorp s 2002 Integrated Resource Plan assumed that carbon dioxide
emissions will cost about $8 per ton over a fossil fuel plant's lifetime.
We believe it is vital these operating cost risks are considered and mitigated. The most
obvious means of reducing such risks is to lower the ratio of Bennett Mountain fuel costs
recoverable by the Company through the Power Cost Adjustment mechanism below the
typical 90%. The ratio of fuel costs recoverable through the PCA could be on a sliding
scale that would place less responsibility for fuel costs on ratepayers as gas prices
increase above a certain price per MMBtu.
A Fully Hedged Gas Price Should Be Imputed To Plant Costs
If the Commission elects not mitigate risks from increasing gas prices via an adjustment
to the PCA mechanism, then the actual construction costs of the plant should include
costs of a full hedge to stabilize future fuel costs for this plant.
As Bolinger et at. discuss, such hedging could take a variety of forms from investment in
renewable energy resources (most of which have zero fuel costs) and efficiency
measures, to gas storage systems and long-term supply contracts, to financial instruments.
Some of these measures could allow Idaho Power and its customers to financially benefit
from gas price decreases as well.
The actual cost of hedging natural gas to create a fixed fuel cost is unknown. Bolinger
at. derived a hedge value of renewable energy resources of between $OA-8/MMBtu
(0.3 and 0.6~/kWh). Bolinger et at. at xi-xiii. Rather than recommending applying these
results to all situations, the authors propose as one solution that generators "internalize
2 The full NPC report is available at
.:::http: / /www.fossil.energy.gov ./pro grams/ oil gas/pub lica tions/npc/O 3 gas stud y / index.html::.
Comments -- 4
any cost of hedging (or alternatively, take on fuel price risk) and offer a long-term fixed-
price electricity contract, much like renewable energy typically provides.Id. at xv.
Conclusion
We request that the Commission deny Idaho Power s request to rate base construction
costs of the Bennett Mountain Plant, or at minimum implement the consumer protections
requested herein.
cc:
Bart Kline, Idaho Power
John Prescott, Idaho Power
Comments -- 5
LBNL-53587
ERNEST ORLANDO LAWRENCE
BERKELEY NATIONAL LABORATORY
Accounting for Fuel Price Risk:
Using Forward Natural Gas Prices
Instead of Gas Price Forecasts to
Compare Renewable to Natural Gas-
Fired Generation
Mark Bolinger, Ryan Wiser, and William Golove
Lawrence Berkeley National Laboratory
1 Cyclotron Rd., MS 90-4000
Berkeley, California 94720
Environmental Energy
Technologies Division
August 2003
Download from: http://eetd.lbl.gov/EA/EMP/
The work described in this study was funded by the Assistant Secretary of
Energy Efficiency and Renewable Energy of the u.S. Department of Energy
under Contract No. DE-ACO3- 76SFOO098.
Executive Summary
Introduction
Against the backdrop of increasingly volatile natural gas prices, renewable energy resources
which by their nature are immune to natural gas fuel price risk, provide a real economic benefit.
Unlike many contracts for natural gas-fired generation, renewable generation is typically sold
under fixed-price contracts. Assuming that electricity consumers value long-term price stability,
a utility or other retail electricity supplier that is looking to expand its resource portfolio (or a
policymaker interested in evaluating different resource options) should therefore compare the
cost of fixed-price renewable generation to the hedged or guaranteed cost of new natural gas-
fired generation, rather than to projected costs based on uncertain gas price forecasts. To do
otherwise would be to compare apples to oranges: by their nature, renewable resources carry no
natural gas fuel price risk, and if the market values that attribute, then the most appropriate
comparison is to the hedged cost of natural gas-fired generation.
Nonetheless, utilities and others often compare the costs of renewable to gas-fired generation
using as their fuel price input long-term gas. price forecasts that are inherently uncertain, rather
than long-term natural gas forward prices that can actually be locked in. This practice raises the
critical question of how these two price streams compare. If they are similar, then one might
conclude that forecast-based modeling and planning exercises are in fact approximating
apples-to-apples comparison, and no further consideration is necessary. If, however, natural gas
forward prices systematically differ from price forecasts, then the use of such forecasts in
planning and modeling exercises will yield results that are biased in favor of either renewable (if
forwards.c: forecasts) or natural gas-fired generation (ifforwards? forecasts).
In this report we compare the cost of hedging natural gas price risk through traditional gas-based
hedging instruments (e., futures, swaps, and fixed-price physical supply contracts) to
contemporaneous forecasts of spot natural gas prices, with the purpose of identifying any
systematic differences between the two. Although our data set is quite limited, we find that over
the past three years, forward gas prices for durations of 2-10 years have been considerably higher
than most natural gas spot price forecasts, including the reference case forecasts developed by
the Energy Information Administration (EIA)? This difference is striking, and implies that
1 To the extent that it displaces gas-fired generation, development of new renewable generation may also reduce
future gas prices to all sectors of the economy. Furthennore, long-tenn fixed-price renewable energy contracts may
involve less credit risk than long-tenn fixed-price natural gas contracts (i.
, "
conventional" hedges, such as gas
forwards and swaps) of similar duration. Thus, separate from the "hedge value" of renewable energy discussed in
this report, long-tenn fixed-price renewable energy contracts may provide incremental value over natural gas
forward and swap contracts in the fonn of lower gas prices and reduced credit risk. These potential benefits - which
are not included in our analysis - may become increasingly important over longer contract tenns of 15-25 years.2 It deserves mention that reviewers of a draft of this report from the ElA have characterized their efforts as
projecting natural gas costs rather than forecasting natural gas prices. In other words, the EIA reference case
assumes that weather and inventory patterns, as well as regulations - all of which can greatly impact market prices -
remain "nonnal" (by historical standards) throughout the forecast period. In this sense, the ElA reference case
forecast" does not necessarily represent the expected or most likely future market price, and perhaps not even a
market price at all. This subtle distinction is discussed in the full report; here we simply note that we use EIA
resource planning and modeling exercises based on these forecasts over the past three years have
yielded results that are biased in favor of gas-fired generation (again, presuming that long-tenn
price stability is desirable). As discussed later, these findings have important ramifications for
resource planners, energy modelers, and policymakers.
Natural Gas Prices Are Highly Variable
For better or worse, natural gas has become the fuel of choice for new power plants being built
across the United States. According to the EIA (2003), natural gas combined-cycle and
combustion turbine power plants accounted for 96% (138 OW out of 144 OW total) of the total
generating capacity added in the u.s. between 1999 and 2002. Looking ahead, gas-fired
technology is expected to account for 80% of the 428 OW of new generating capacity projected
to come on line through 2025 increasing the nationwide market share of gas-fired generation
from 17% in 2001 to 29% in 2025 (EIA 2003).
With increasing competition for natural gas supplies, it is likely that gas prices will be as or more
volatile than they have been in the past. Figure 1 shows first-nearby natural gas futures prices on
a daily basis going back to the inception of trading on the New York Mercantile Exchange
(NYMEX) in April 1990. While the "twin peaks" of December 2000 and February 2003 clearly
dominate the graph and make the rest of the price history look comparatively tame, the reader
should keep in mind that many of the "lesser" price spikes during the early 1990s represent
doublings or more in price.
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Figure ES-l. NYMEX Natural Gas Futures Prices (First-Nearby Contract)
As implied by Figure ES-, not only have gas prices increased in recent years, but so has gas
price volatility. Figure ES-2 shows the annualized 90-day standard deviation of daily percentage
reference case gas price forecasts because they are publicly available, have been widely vetted, and are commonly
used by the EIA and others as a "base case" price scenario in policy evaluations and modeling exercises. As a
control, we also look at other non-ErA gas price forecasts that may not suffer from this ambiguity.
Vlll
changes in gas futures prices, along with its one-year (i., 252-day) moving average to smooth
out seasonality. Though highly seasonal in nature, the general increase in volatility, particularly
since 1996, is clear. Near-record-high volatility, combined with price levels that are more than
double the historical average, mean that in absolute terms, an unprecedented number of dollars
are now at risk.
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Figure ES-2. Historical Volatility of Natural Gas Futures Prices (Continuous 1st Nearby)
This is particularly noteworthy considering that gas price volatility, which has attracted a great
deal of recent attention, is a major contributor to wholesale electricity price volatility. The cost
of natural gas can account for more than half the levelized cost of energy from a new combined
cycle gas turbine, and more than 90% of its operating costs (EIA 2001). Moreover, gas-fired
plants are often the marginal units that set the market-clearing price for all generators in a
competitive wholesale market, allowing natural gas price volatility to directly flow through to
wholesale electricity price volatility.
Unless they are hedged, gas price increases can therefore directly impact competitive wholesale
electricity prices, particularly if gas-fired units are on the margin. And with the market share of
gas-fired generation projected to nearly double by 2025, the impact of gas price volatility on
wholesale electricity price volatility is likely to increase as well. Clearly, the vadability of gas
prices poses a major risk to both buyers and sellers of gas-fired generation.
Traditional Natural Gas Hedging Instruments Can Be Used to Mitigate Risk
Renewable energy resources such as wind, geothermal, biomass, solar, and hydro power are
often sold on a fixed-price basis, providing a hedge against volatile natural gas prices.
Nonetheless, it is also true that natural gas price risk can be hedged through traditional gas-based
hedging instruments. In order to achieve a fuel price risk profile similar to that of fixed-price
renewable generation, either the buyer (under spot, indexed, and tolling electricity contracts) or
seller (under fixed-price electricity contracts) of gas-fired generation must hedge away natural
gas price risk.
Accordingly, to hedge natural gas price risk, a retail electricity supplier can either invest in
renewable generation (which is immune to gas price risk), choose among a number of gas-based
financial and physical hedging instruments, or purchase fixed-price gas-fired electricity (in which
case the generator may wish to hedge using gas-based financial or physical instruments)?
Financial gas-based hedges include futures (or, more generically, forwards), swaps, options on
futures, or some combination or derivation thereof (e., collars). Physical hedges include long-
tenn fixed-price gas supply contracts and natural gas storage.
As shown below in Figure ES-, each of these hedging instruments falls into one of two
categories: those creating a flat payout pattern that is immune to price movements in either
direction (gas futures, swaps, and fixed-price physical supply, as well as fixed-price renewable
generation), and those creating a contingent payout pattern that protects against adverse price
movements while allowing participation in favorable price movements (gas options and storage).
In other words, all of the hedging instruments under consideration can protect gas consumers
against a gas price increase, but only options and storage allow the consumer to benefit from a
gas price decrease as well.
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Figure ES-3. Payout Patterns for Various Hedging Instruments (hedge plus underlying)
To fairly evaluate fixed-price renewable and variable-price gas contracts on an apples-to-apples
basis (presuming that long-term price stability is valued), we must look to those instruments that
provide a hedged payout pattern similar to that of renewables - i., flat and symmetrical
immune to both gas price increases and decreases. As shown in Figure ES-, such instruments
3 Similarly, investments in energy efficiency (e., through demand-side management), or even coal or nuclear
power (with fuel costs that are quite stable compared to natural gas), may provide an equivalent natural gas price
hedge. Though not explicitly targeted as such, much of the discussion in this paper is also applicable to these other
energy, or demand reduction, resources.
include gas futures, swaps, and fixed-price physical supply contracts, but not options or storage.
The prices that can be locked in through these instruments are therefore the appropriate fuel price
input to modeling and planning studies that compare - either explicitly or implicitly - renewable
to gas-fired generation (again, presuming that long-term price stability is valued).
Forward Gas Prices Have Traded at a Premium to EfA Reference Case Price Forecasts
As has been noted, however, utilities and others conducting such studies tend to rely primarily on
uncertain long-term forecasts of spot natural gas prices, rather than on prices that can be locked
in through futures, swap, or fixed-price physical supply contracts (i.
, "
forward prices ). This
practice raises a critical question: how do the prices contained in uncertain long-term gas price
forecasts compare to actual forward prices that can be locked in? If forward prices
systematically differ from long-term price forecasts (e., if there is a cost to hedging, or if the
forecasts are out of tune with market expectations), then the use of such forecasts in resource
acquisition, planning, and modeling exercises will yield results that are biased (again, assuming
that long-term price stability is desirable) in favor of either renewable (if forwards ~ forecasts) or
natural gas-fired generation (if forwards )- forecasts).
The data necessary to conduct this analysis are deceptively simple: a forward gas price and a gas
price forecast, ideally generated at the same time. While long-term gas price forecasts are
relatively easy to come by (e., the EIA forecasts are publicly available and updated every year),
long-term forward prices - and in particular those of sufficient duration to be of interest, given
the 15-25 years of relative price stability offered by most contracts for renewable generation -
present a greater challenge. Despite our best efforts to obtain a larger sample, our analysis is
limited to comparisons from the past three Novembers (November 2000-November 2002), and
for terms not exceeding 10 years. Specifically, our limited sample of forward contracts and price
forecasts includes:
, 5-, and 10-year natural gas swaps offered by Enron in November 2000 and 2001
compared to reference case natural gas price forecasts from the Energy Information
Administration s (EIA) Annual Energy Outlook 2001 and 2002 respectively;
the six-year NYMEX natural gas futures strip from November 2002, compared to the
reference case gas price forecast contained in Annual Energy Outlook 2003 and;
a seven-year physical gas supply contract between Williams and the California
Department of Water Resources signed in November 2002, again compared to the
reference case gas price forecast contained in Annual Energy Outlook 2003.
Each of these comparisons reveals that forward natural gas prices have traded above EIA
reference case price forecasts during this three-year period, sometimes significantly so. Figure
ES-4 consolidates the resulting premiums (in terms of $/MMBtu and ~/kWh, assuming a heat
rate of7 000 Btu/kWh) from each of these comparisons into a single graph.
As shown, the magnitude of the empirically derived premiums (i., relative to EIA reference
case forecasts) varies from year to year, contract to contract, and by contract term, ranging from
$OA-$O.8/MMBtu ($O.6/MMBtu on average), or 0.6~/kWh (OA~/kWh on average).4 One
cannot easily extrapolate these findings beyond the last three Novembers, or to contract tenns
longer than those examined. Nonetheless, it is at least apparent that utilities and others who have
conducted resource planning and modeling studies based on EIA reference case gas price
forecasts over the past three years have produced "biased" results (i., presuming that long-tenn
price stability is valued) that favor variable-price gas-fired over fixed-price renewable
generation, potentially to the tune of ~O.6~/kWh on a levelized basis.
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Figure ES-4. Composite Premiums in $/MMBtu and ~/kWh (assuming 7 000 Btu/kWh)
Many Other Gas Price Forecasts Have Been Even More "Biased" Over the Last Three Years
Given that they are publicly available, highly documented, and widely reviewed and used (even
by utilities) in modeling exercises and resource planning processes throughout the country, EIA
reference case gas price forecasts are a reasonable starting point for our purposes. The EIA's
forecasts, however, are by no means the only long-term gas price forecasts available to market
participants. Among others, PIRA Energy Group, DRl-WEFA, and Energy and Environmental
Analysis (EEA) all provide proprietary long-term gas price forecasts to utilities and others.
Obviously, unless these other forecasts are in close agreement with EIA reference case forecasts
the spread between them and forward gas prices will be different from that measured against EIA
reference case forecasts. In order to assess how the premiums presented in Figure ES-4 would
change had we compared forward prices to some forecast other than the EIA's , we looked at a
number of different long-term gas price forecasts, sourced from the EIA's own forecast
comparisons (contained in each year Annual Energy Outlook), as well as from various utility
integrated resource plans. With few exceptions, the EIA reference case forecast has generally
4 We emphasize that these premiums are benchmarked against EIA reference case gas price forecasts, and that the
magnitude - and perhaps even the sign - of the premiums will change if our sample of forward prices is compared to
price forecasts that differ from the EIA reference case.
been higher - and often substantially so - than most other forecasts that have been used by
utilities and others trying to predict gas prices over the last three years.
These findings suggest that the premiums observed relative to the EIA reference case forecasts
would be even larger when comparing forward prices to some of the other commonly used gas
price forecasts. For example, had we compared the November 2001 10-year natural gas swap to
the gas price forecast contained in Idaho Power s resource plan, we would have observed a 10-
year levelized premium of $1.29/MMBtu - i.nearly twice as large as the $0.68/MMBtu
benchmarked against the EIA reference case forecast. This translates to a 0.9~/kWh difference at
an aggressive heat rate of 7 000 Btu/kWh; had Idaho Power opted to use forward market data
rather than forecast data, comparisons between renewable and gas-fired generation may have
looked significantly different. With most other forecast comparisons yielding similar results
(though not as large in magnitude), it is clear that utilities and others that have used these other
(i., non-ErA) forecasts to compare fixed-price renewable to variable-price gas-fired generation
over the past three years have obtained results that are even more biased" in favor of gas-fired
generation than those resulting from EIA-based reference case comparisons (again, presuming
that long-term price stability is desirable).
Possible Explanations for the Empirical Premiums Between Forwards and Forecasts
How can one explain the existence of price premiums as high as $0.8/MMBtu over 10 years
relative to EIA reference case gas price forecasts, or even higher relative to other gas price
forecasts? At least three different explanations could either partially or wholly account for such
sizable differences between natural gas forwards and forecasts:
1) Hedging is not costless. If this is true, then one might expect forward natural gas prices to
trade at a premium relative to industry-standard forecasts of future spot natural gas prices
with the premium representing the incremental cost of hedging. Such incremental costs
could reflect the presence of a risk premium, caused either by negative net hedging pressure
(i., gas consumers hedging more than gas producers) or systematic risk in natural gas
prices as measured by the Capital Asset Pricing Model (CAPM). Alternatively, the
incremental cost of hedging could reflect high transaction costs manifested in wide bid-offer
spreads that ensure that the long (short) hedger always pays (receives) more (less) than the
true" (e., mid-market) price. Under this explanation (that hedging is not costless), the
premiums presented in Figure ES-4 might be considered the "hedge value" of renewable
generation; i., renewable generation provides price stability without incurring these
incremental" hedging costs.
2) The forecasts are out of tune with market expectations. Under this explanation, the gas
price forecasts (not just the EIA's reference case, but instead virtually all of the forecasts we
have examined) themselves are at issue, and are biased downwards relative to the market's
expectations of future gas prices at least over the last three years. If this is true, then our
empirical observations of premiums may not necessarily indicate that there is an incremental
cost of hedging per se. In other words, forward prices may in fact be unbiased estimators of
future spot prices, and the premiums we have observed may simply be due to the use
X111
forecasts that have been seriously out of tune with market expectations over the last three
years. This, of course, calls into question the use of these forecasts for any purpose over the
last three years, and strongly suggests replacing forecast prices with forward prices where
available.
3) Other data issues are driving the premium. Two other data problems might also be of
some concern. First, the forward prices we sampled might be distorted upwards (e., due to
thin markets and/or price manipulation), which could artificially create or inflate a premium
over price forecasts. Second, if we sampled forward prices earlier or later in time than when
the forecasts were generated, then the observed premiums could simply be the result of a
fundamental change in market expectations in the interim.
Each of these three potential explanations for the existence of empirical premiums is
theoretically plausible, yet perhaps not fully satisfactory on its own; it is perhaps more likely that
two or more of these (and maybe other) explanations working in combination are driving our
empirical findings of a premium.
Regardless of the explanation for (or interpretation of) our empirical findings, however, the basic
implications of our study remain the same: one should not blindly rely on gas price forecasts
when comparing fixed-price renewable to variable-price gas-fired generation contracts. If there
is a cost to hedging - whether related to net hedging pressure, CAPM, transaction costs, or some
combination of the three - gas price forecasts do not capture and account for it. Alternatively, if
the forecasts are at risk of being biased or out of tune with the market, then one certainly would
not want to use them as the basis for investment decisions or resource comparisons if a better
source of data (i., forwards) existed. Accordingly, assuming that long-term price stability is
valued, in both cases the most comprehensive way to compare resource options would be to use
forward natural gas price data as opposed to natural gas price forecasts. Over the last three
years, at least, it appears as if the use of forward gas prices would have significantly shifted the
balance away from natural gas and toward renewable energy, relative to forecast-based
comparIsons.
Implications for Resource Planners, Analysts, and Policymakers
These findings have important implications for utility resource planners, energy modelers and
analysts, and policymakers:
Utility Resource Planners
While our examination of utility integrated resource plans revealed that many utilities do in fact
incorporate actual forward market prices (i., the price at which they could lock in gas prices)
into their gas price forecasts, they typically do so for only the first few years of what are
commonly 20-year forecasts. Since the value of price stability does not disappear after a few
years, further action may be warranted.
Assuming that long-term price stability is valued, what steps can a utility or, more generally,
anyone comparing fixed-price renewable to variable-price natural gas generation, take to move
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towards an apples-to-apples comparison? Because of the challenges in extrapolating our
findings to other forecasts , hedge durations, and time periods, we do not recommend blindly
adding $OA-$0.8/MMBtu, or 0.6~/kWh, to any forecast, for any duration. We emphasize
that these premiums were derived relative to ErA reference case gas price forecasts over a
limited three-year period that mayor may not represent "normal" market conditions, and for
contract terms ranging from 2-10 years. Any attempt to directly apply these particular premiums
outside of these parameters may be questionable, especially if better data is available at the time.
Because of the difficulty in extrapolating our results to different circumstances, below we
develop process recommendations for resource planners. At least three approaches are possible:
1) Use and extend the forward curve for natural gas: As noted earlier, utilities have already
begun to incorporate gas forward prices into their gas-price forecasts. This is a good start, but
many of these utilities only rely on a year or two of forward price data. Subject to data
availability, utilities (or others making resource comparisons) could extend the period over
which their resource plans (or comparisons) rely on actual forward market gas prices rather
than uncertain price forecasts. Given the availability of NYMEX futures price data
extending the use of forward prices to at least 6 years would seem like a first step. Beyond 6
years, forward price data may be harder to come by. Where forward price data from actual
contracts are not publicly available, utilities and others may have access to (or be in a
position to solicit) data that are not in the public domain; broker quotes may also suffice as a
way of extending the use of forward data to 10 or even 20 years.
2) Place the onus on the generator: Natural gas-fired generators may be willing to internalize
any cost of hedging (or alternatively, take on fuel price risk) and offer a long-term fixed-price
electricity contract, much like renewable energy typically provides. While fixed-price
renewable energy may still have some incremental "hedge value" (from placing downward
pressure on gas prices, and potentially mitigating credit risk), a fixed-price gas-fired
electricity contract is otherwise comparable to fixed-price renewable energy, thereby
obviating the need for a utility or regulator to collect forward gas price data for the purpose
of substituting into a forecast. Along these lines, utilities could follow the example of Xcel
Energy in Minnesota, which - as directed by the Minnesota PUC - has worked with
stakeholders to develop a method for unbiased treatment of renewable generation in its bid
evaluation process. Specifically, in all-source solicitations, Xcel requires "that bidders who
submit fuel-indexed or tolled fuel pricing in a proposal must also submit an otherwise
identical proposal that contains fixed fuel pricing for at least 10 years." (Xcel Energy 2001)
Though obtained during the solicitation rather than the planning phase, this information
along with other provisions, enables Xcel to more closely approximate a true apples-to-
apples comparison between renewable and other forms of generation.
3) Adjust the forecast: Finally, as a last resort, if forward market prices are not available over
the entire planning horizon, and soliciting comparable fixed-price electricity bids from gas-
fired generators is not realistic, utilities may wish to adjust forecasted gas prices upwards to
account for the fact that forward prices have, potentially for reasons discussed above, traded
above price forecasts over the past three years. While the analysis in this report suggests that
an adjustment ranging from $OA-$0.8/MMBtu (0.6~/kWh at a heat rate of 7 000
Btu/kWh) is a reasonable starting point, we emphasize that these premiums were calculated
with respect to EIA reference case price forecasts over the past three years, for terms ranging
from 2-10 years. If using a different base gas price forecast, a higher or lower adjustment
may be warranted. Likewise, this historically derived premium may well vary in the future
and may vary with contract terms above 2-10 years. For these reasons, the two previous
approaches are preferable to this one. That said, if the two previous approaches are not
possible, this approach may still be better than simply relying on forecast data, which - at
least over the last three years - has been shown to be significantly below forward prices.
Energy Modelers and Analysts
It remains to be seen which, if any, of the explanations for empirical premiums discussed in
Chapter 6 are "correct " and the implications for energy modelers and analysts vary based on the
explanation under consideration. If there truly is a cost to hedging natural gas price risk with
traditional instruments, and renewable energy can mitigate fuel price risk at a cost that is lower
than that incurred through those traditional hedging instruments (and the market recognizes this),
then the supply of renewable generation may increase at faster rate than that estimated by current
national energy forecasts, leaving forecasts of renewable generation biased downwards.
instead the premiums observed in Chapter 4 are attributable to gas price forecasts that are biased
downwards or are otherwise inconsistent with market expectations of future spot prices, then
energy modelers will no doubt want to investigate the cause of the discrepancy between their
forecasts of natural gas prices and the market's expectations of those same prices. In either case
if long-term price stability is valued, energy analysts should ideally compare the cost of
renewable generation against the cost of gas-fired generation using forward gas prices as the
relevant fuel cost.
Policymakers
While the root cause of the empirical premiums we have observed in this paper remains unclear
the fact that renewable generation provides long-term price stability is beyond reproach. As
long-term price stability is undoubtedly valued to some degree by end-use customers, the "hedge
value" of renewable generation should help to justify continued and new policy support for
renewables. For example, if future work confirms the hedge value of renewable energy,
policymakers should begin to explore practical mechanisms (such as those discussed above) to
incorporate that value into decision-making processes, thereby enabling renewable energy to
capture the value of the price stability benefit it provides to the market.
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