Economic Efficiency andNon-Market Failure:An analysis of the Renewable PortfolioStandard for Colorado’s Energy Market

Ric O’ConnellUniversity of Colorado, Boulder

A paper for Economics 4545

Professor Edward Morey

December 16, 2003

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Abstract

This paper provides an analysis of Colorado’s proposed Renewable Portfolio Standard(RPS) on economic efficiency grounds. This paper will attempt to show that an RPS forColorado is economically efficient in that it solves non-market failures in Colorado’selectricity market. Recent rises in natural gas prices, and adoptions by many states of RPSs,have made RPSs attractive policy options for states. This paper will compare the price ofnatural gas fired electricity with wind-powered electricity, given that there is a federal taxcredit for wind. This paper posits that the economies of scale in wind power createefficiencies that would not exist without the mandates of an RPS. While an exhaustiveanalysis of policy options is not undertaken, market-based approaches to increasing renewablepenetration are rejected as insufficient.

1. Introduction

This paper will attempt to determine if the proposed Renewable Portfolio Standard(RPS) for Colorado is an economically efficient policy. An RPS mandates that a percentageof electricity generation come from “renewable” sources, over thirteen states have recentlyimplemented RPS legislation, and the recently defeated federal energy bill contemplated anational RPS. Colorado will attempt to pass RPS legislation again in the spring of 2004, buttwo recent failures leave this effort in doubt. In this paper, I will argue that the current energy“mix” is inefficient from an economic perspective, and that state government intervention isjustified to fix this inefficiency in the energy market. While environmental externalityarguments can be made in Colorado’s energy market, they are not the complete economicpicture in regards to renewables and energy generation. The federal Production Tax Credit(PTC) for wind attempts to address the externalities of fossil fuel energy, yet it has not beensuccessful in solving issues at the state level. The current inefficiency can be attributed tonon-market failures in the regulated energy market in Colorado, not just the classicexternalities argument. Increasing the percentage of renewables is efficient because it wouldcreate economies of scale, lowering the price of renewables. Increasing use of renewablesalso reduces the demand for natural gas, and hence the price. Renewable advocates had oftenfelt that recent natural gas volatility would strengthen the economic argument for renewables,recently published reports on natural gas price volatility and consumer surplus fromrenewables verify this theory.

What is an RPS?

A Renewable Portfolio Standard (RPS) is legislation that mandates a utility topurchase electricity from approved renewable generating sources. Renewable energy isdefined as energy that comes from renewable sources; common examples are wind power,solar electric power, and biomass (burning crops or landfill methane for electricity).“Approved source” differs in many states – some allow hydroelectric to be considered, othersdo not, some allow biomass, while still others narrowly define renewable as solar electric only(Arizona, for example). States implement RPS’s normally through their Public Utilities

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Commission (PUC), though states do not need a regulated electric market to implement andRPS. In the case of Texas, which has one of the most successful RPS’s, the legislation thatderegulated the utility industry included an RPS provision.

States implement RPS’s for a number of reasons. The most popular are:

• Reduce the cost of renewables through economies of scale by increasing renewables’market share

• Reduce externalities of fossil fuel generated electricity, mainly air pollution but alsocarbon (CO2) emissions and thermal effluent.

• Reduce price volatility of electricity (i.e. sensitivity to fuel price volatility)• Increase fuel diversity• Increase acceptance of renewables in the marketplace• Strong constituent support for renewables

One of the most difficult policy decisions with an RPS is how to set the percentage ofrenewable generation. States vary from 1 (AZ) to 20 percent (CA). The national RPS wasproposed at 10 percent.

RPS’s are normally structured to increase the percentage of renewable generation overa period of several years. For example, Colorado’s proposed RPS is 10 percent by 2010. Thisstructuring means RPS’s are applied to new generating capability, not existing generatingcapability. In other words, projected generation growth at 1.8 percent a year (EIA 2003) inColorado between now and 2010 will account for over 10 percent of total generatingcapability. This leads us to postulate that any economic analysis of renewables must becompared to what we assume would be installed as new generating capacity, without an RPS.

Opposition to Renewable Portfolio Standards is based almost entirely on costarguments. Most opponents see renewable energy as more expensive, and an RPS as raisingtheir electricity bills. This is especially true for large industrial power users and rural electricco-ops that purchase generating capacity. The other argument is mainly ideological; itpostulates that renewables should compete in the marketplace with fossil fuels, and that thereis no case for intervention in the electricity generating market.

History of the RPS in Colorado

Legislators and proponents attempted to pass an RPS in Colorado in both 2002 and2003. The proposed RPS was a 10 percent RPS by 2010 with a price cap, which effectivelylet the Utility (Xcel Energy) out of the RPS if the price of renewable energy rose above athreshold. The RPS also only applied to Xcel, the large regulated Investor Owned Utility(IOU) in Colorado. Rural co-ops were not required to purchase renewable energy, thoughsince many purchase from Xcel, they are concerned their prices would rise as a result of astatewide RPS. Not all municipal utilities are against an RPS, however, Fort Collin’sMunicipal Utility has set its own RPS of 2 percent by 2004 and 15 percent by 2017 (FortCollins 2003)

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A major shift in the electricity market in Colorado came two years ago, when theColorado PUC, with major support from renewable proponents, forced Xcel to implement awind project in Lamar, Colorado. Xcel unsuccessfully argued that natural gas fired electricitywas cheaper than wind, while the PUC found that wind was actually less expensive than gas.Since the ruling, Xcel has since testified before congress that the Lamar project will saveColorado ratepayers $4.6 million each year (Andrews et al 2003).

2. The Electricity Generation market: A primer

Electricity is mainly produced at centralized power plants and then is distributed viapower lines to residential, commercial, and industrial users. These power plants mainly burncoal or natural gas, with nuclear and hydropower the other main forms of generation. SeeFigure 1 for more detail.

Electricity has the unique (and problematic) capability of not being able to be stored.This means electricity supply and demand must match exactly, at all times. There is no“inventory” or way of storing electricity for later use. This breaks the electricity market intotwo types: baseload and peaking. Baseload electricity is energy that is generated all the time,at predictable levels. Peaking energy is generated at production facilities that are operated tosupply energy to cover the peaks in demand – typically summer afternoons are the peak time.This distinction also carries over to fuel types: Coal is used in baseload plants, while naturalgas is used in both a baseload and peaking capacity.

This means there are two ways of measuring electricity generation: power and energy.Power is the peak capacity of the electrical generation system – the theoretical power that thesystem could generate if everything was turned on at once. Power is measured in Watts, or1,000 Watts – a Megawatt (MW). Energy is the actual energy delivered while the plant wason – it is measured in kilowatt-hours (kWh), which is the unit that shows up on your bill. Akilowatt-hour is the energy required to run ten 100-watt light bulbs for an hour.

Energy Sources: US and Colorado

While the US has a complex mix of energy sources, Colorado’s is much simpler. SeeFigure 1 for a list of all the sources of US electricity production (note that solar and wind areso small as not to be visible on the chart).

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US Electricity generation by source 1973-2002

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The percent of natural gas used for generating electricity has steadily increased in thelast decade (Figure 2). According to the Energy Information Administration (an arm of theDepartment of Energy), natural gas combined-cycle and combustion turbine power plantsaccounted for 96% 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 new generatingcapacity projected to come on line through 2025, increasing the nationwide market share ofgas-fired generation from 17% in 2001 to 29% in 2025 (EIA 2003).

For Colorado, the energy mix is mainly coal, with some natural gas (See Figure 3 andFigure 4). Note that Figure 3 shows the generation in Colorado (energy) while Figure 4shows the capacity (power). Natural gas is 22.7% of CO’s generating ‘capability” and 20% ofactual generation. Natural gas generation grew an astounding 33.9% from 1992-2001 inColorado (EIA 2003).

Coal76.7%

Petroleum0.4%

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Figure 3 - Colorado's electricity generation by Source, 2001 (EIA)

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Coal56.3%

Natural Gas22.7%

Petroleum1.7%

Petroleum/Gas Combined5.1%

Hydroelectric13.5%

Other Renewables0.7%

Figure 4 - Colorado's electricity capacity by source, 2001 (EIA)

Natural Gas vs. Coal

Economic efficiency suggests that electric utilities should minimize costs anddiversify their fuel selection to reduce risk. Capital intensive technologies, such ascoal and hydroelectric power, are economically efficient for meeting base-loaddemand, whereas natural gas is more economically efficient for peak demand use.

Jerry Taylor, Cato Institute (Taylor and VanDoren 2002)

Natural gas and coal are the two main fuels used in Colorado, and natural gas ismainly used as both a peaking and baseload fuel, while coal is exclusively a baseload fuel.This is due to the difference in capital and operating costs – Coal plants are extremely capitalintensive, with most of the costs in coal generated electricity going to capital and operations.Coal has capital costs of over $1,300 per kWh (for new coal plants) with very low fuel costs.Natural gas, on the other hand, has much lower capital costs, about a third of coal’s cost. Fuelcosts are the driving factor for natural gas generation: 50% of levelized natural costs and 90%of operating costs are fuel costs (EIA 2003).

The other driving factor behind the move to natural gas as an electricity generatingfuel is the high costs of new coal plants, which is partly driven by federal clean air regulation.Existing coal plants have less pollution control equipment installed that a new coal plant

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would require, and therefore produce electricity at a much lower cost than a new coal plantwould. This regulation, plus advances in combined-cycle natural gas generation, has led tonearly all new electricity generation in Colorado (and the US) to be from natural gas. Themost recent coal fired plant in Colorado was built in the early 1980s (Colorado PUC 2003).

Natural Gas Pricing and Electricity prices

Marginal electricity prices in Colorado are tied to natural gas prices, as natural gasmakes up most of the peak load. Electricity prices are regulated for residential consumers, bututilities are able to pass on fuel costs separately from regulated prices (this is a point we willreturn to later). Electricity prices are even more tied to fuel costs in a deregulated market, asprices tend to be dictated by the highest marginal cost of production (Bolinger et al. 2003).This paper cannot explore all the intricacies of natural gas or electricity pricing, but we canmake some generalizations. First, natural gas prices are trending upwards nationwide and inColorado. Natural gas is supply constrained, and peak natural gas production was in 1973(EIA). Regionally, natural gas pricing is dependent on supply and demand, and a recentpipeline from Colorado to California increased prices as now Colorado gas is available inCalifornia, which has higher prices (Xcel 2003). As natural gas prices become morenationalized, the highest price market will set gas prices. See Figure 5 for national natural gasprices, with a projected trend. Natural gas prices, volatility, and projections will be discussedin depth in the next section.

US Monthly Natural Gas Prices1990-Present, with projection to 2008

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1 The trend line in this figure is polynomial, with an order of 2, and was generated by theauthor, not the EIA.

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3. Cost analysis

There are several arguments for implementing an RPS in Colorado; they includereducing emissions of harmful pollutants, reducing carbon emissions, increasing ruraldevelopment (wind turbines are generally installed on rural land), and other environmentalbenefits. This paper will focus on a single reason to implement an RPS: reducing cost forconsumers. This may seem counterfactual, as most arguments against implementing an RPSare due to cost considerations. Recent natural gas prices, however, and a more comprehensiveeconomic approach may cause us to conclude otherwise.

Electricity prices are generally quoted as “levelized” prices – these are per kWh pricesthat take into account amortized capital costs, operations and maintenance, and fuel prices.Natural gas fired electricity levelized prices are difficult to predict, because fuel costs are 50percent of the total price2. Levelized coal prices are more driven by capital costs (and coalprices are relatively stable), and renewable generation is almost all capital costs. This makesrenewable prices more stable: some wind developers are now selling long-term contracts at2.6 cents a kWh, cheaper than any other form of generation (Bird 2003)3.

An important factor in renewable prices is that they are normally sold in long-termcontracts at fixed prices. Because renewable energy is almost all capital costs, renewableproducers can fix costs and sell long-term contracts (typically 10 years) at specific kWh rates.This makes the price of renewable energy more stable than its competitors. Natural gas firedelectricity is also sold at long-term contracts, but these are typically indexed to natural gasfuel prices, allowing prices to move as fuel prices change (Bolinger et al. 2003)4.

Analysis of Natural Gas prices

Any economic analysis of an RPS must compare the price on renewable generationwith what it would displace, which is natural gas fired generation (Macauley et al 2002).Combined cycle natural gas is the preeminent technology for new electricity generation inColorado and the US. Future prices of natural gas are difficult to predict, for example, Xcelrevised its natural gas price forecast three times during its hearings with the Colorado PUCover the Lamar wind project (Lehr et al 2001).

Natural gas prices are seasonally driven. Unlike coal, which is almost entirely usedfor electricity generation, natural gas is used for residential heating, electricity generation, andindustrial purposes. Electricity generation accounts for roughly 25% of natural gas use, but 2 For each $1/MMBtu increase in gas prices, the levelized cost of generation from state-of-the-art combined cycle units increases by 0.68¢/kWh (Bolinger et al 2003)3 This price assumes the Production Tax Credit for wind is in place, this is discussed later.4 There are some natural gas electricity contracts that are flat-rate, but they are the exception,not the rule, and are become more rare as natural gas prices have become more volatile(Caldara 2003)

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this varies dramatically with the season. Natural gas use peaks in the winter months, whereall the residential use is, while natural gas for electricity generation peaks in the summermonths (see Figure 6).

Total natural Gas consumption, Natural Gas for electricity, Percentage. 2001-present. EIA

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Price Volatility

Natural gas is the third most volatile commodity, after electricity (which is partlydriven by natural gas volatility) and sugar, which was due to a single price spike in 2000/2001(see Figure 7). Looking at Figure 5, one might think that natural gas volatility comes from thetwo huge spikes in January 2001 and February 2003, but a closer looks reveals price spikes inother years (e.g. 1996) of close to 100%. An extreme example of natural gas price volatilityis California, which is especially reliant on natural gas fired electricity. The natural gas pricespike of 2001 was partly responsible the state’s energy crisis which resulted in the bankruptcyof the state’s largest utility, a massive state budget deficit, and the recall of a newly electedgovernor.

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Figure 7 – Price volatility over the last decade of selected commodities (EIA)

Not only is natural gas volatile, it is increasing in volatility. Figure 8 shows thehistorical volatility of natural gas since 1990, the annual moving average has increased toclose to 60% in recent years.

Figure 8 - Historical Volatility of Natural Gas Futures Prices (Bolinger et al 2003)

Contracts vs. Projections

The volatility of natural gas makes long-term projections difficult, and when makingsprice comparisons with renewable energy, it becomes crucial that these projections arecorrect. Because the prices of renewable energy can be sold at fixed long term contracts, it ishard to compare these fixed price contracts with variable natural gas fired electricity prices.To make these comparisons, utilities and power purchasers relied on natural gas priceprojections from the EIA in their “Annual Energy Outlook” as well as industry priceprojections.

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Recent work done at Lawrence Berkeley National Labs (LBNL) on price volatility innatural gas markets argues that these projections consistently under price natural gascompared to long-term gas contracts, and that futures markets should be used whencomparing prices of renewable energy to natural-gas fired electricity. (Bolinger et al 2003)Futures markets provide locked-in costs for natural gas, and as financial instruments, build theprice volatility into the price of the contracts. Projections of natural gas prices, however, donot build in any risks of volatility, and tend to diverge greatly between EIA projections andindustry projections. EIA’s Annual Energy Outlook (AEO) for 2003 shows natural gas pricesdropping sharply, and then climbing slowly.This is despite the huge increase in naturalgas consumption for electricity production,and general natural gas growth in theresidential market. Figure 9 shows the EIAprojection of natural gas prices - note thechange in projections from the 2002 AEO tothe 2003 outlook. Figure 10 shows theAEO’s projected demand for natural gas to2025.

Figure 10 - AEO 2003 Fuel consumption history and projections (EIA)

If we use futures market pricing and not projections when comparing costs of renewableenergy to its main competitor, combined-cycle natural gas, we find that the cost analysis ofcombined-cycle changes from standard projections. There is a linear relationship betweennatural gas prices and the cost of natural gas fired electricity, as 50% of levelized costs arefuel costs (EIA 2003). For instance, at $3.50 MMBtu (an average rate over the last few years)electricity is about 3.36 cents kWh, while at the current price of $6.38 the price is close to 5cents a kWh.

Figure 9 - Natural Gas price projection to 2025 (EIA)

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Renewable Cost analysis

Because renewables are not a single technology, it is hard to compare renewables as awhole to combined-cycle natural gas. Some renewables, such as large-scale hydropower, arein the price range of 2 cents a kWh, but these resources have all been exploited. Solar electricis on the high end, at 15-20 cents a kWh, yet it rarely competes with natural gas, as it is notinstalled utility-scale for powering the electrical grid. When most people do cost analysis ofrenewables, wind is usually chosen as the renewable representative – as it has the mostattractive cost. Wind is utility-scale; modern wind farms use mega-watt or larger turbines,and install multiple turbines per site. The recent Lamar, Colorado, site is a 162 MW project.Texas has installed close to 2,000 MW of wind capacity in the last decade. Current windpricing is in the range of 2.5-3.5 cents per kWh, depending on the quality of the resource (i.e.how good the wind is in the area). This price range includes the 1.8 cent federal PTC, whichhas been in place since the 1992 Energy Policy Act, and we assume this credit for costcomparisons with natural gas.

One of the main problems with pricing wind is that wind is unlike fossil fuel generatedpower. Fossil fuels are “dispatchable” – they can be turned on and off to follow the load.Wind farms produce power when the wind is blowing, not when electricity generators need it.This intermittency makes it difficult to compare a kWh of wind-generated power with a kWhof gas-fired power, as generators favor the gas-fired power. These “ancillary” costs of windpower are part of a current debate over how to price a kWh from an intermittent source suchas wind power. Other nations, however, seem to have mainly solved this problem. Denmarkreceives 15 percent of its energy from wind power, and many European nations are using upto 10 percent wind energy (Namovicz 2003).

4. The Case for Market Intervention

While a discussion of pricing is important, it does not lead us directly to the questionof why we should support mandating renewable energy generation. The question is clearly:If renewable energy is cost effective, competitive with natural gas, and price stable – whywould the market not pick it?

This argument is consistently put forth by critics of renewable energy, who point toXcel’s “Windsource” program as an example of market-driven renewable energy. In thatprogram, customers can sign up for wind energy at an additional 2.5 cents per kilowatt-hour.This program has two 30 MW wind farms in northeastern Colorado, and has signed up closeto 30,000 customers (Xcel 2003).

Traditional justifications for renewable energy relied heavily on externalities, or theeffects of power generation that is not reflected in the price. The private cost of producing(and consuming) electricity does not equal the social cost, because it fails to take into accountexternalities associated with electricity generation. Common energy externalities arepollution, carbon emissions, environmental damage from mining and drilling, and thermal

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discharges (heated water discharged to the environment). It was argued that if theseexternalities were internalized in the cost of fossil-fuel energy, it would be cost-competitivewith renewable generation. However, it could be argued that most of these pollutionexternalities have already been internalized through the Clean Air Act (though older coalplants are still managing to avoid regulation). In addition, carbon emissions are difficult toprice, and thermal effluent is a small externality (as well as being difficult to price).

There is not general agreement on pricing for these externalities5. Although the cleanair act does not regulate CO2 and Mercury6, the pricing of CO2 emissions is difficult (if notimpossible) and only coal plants emit mercury, not gas-fired generators.

I will argue that the reasons for intervention in the Colorado electricity market do notrely on externality arguments, and that renewable power is already cost-effective compared togas-fired generation. The reasons for intervention in the Colorado market are listed below:

• Poor natural gas projections means economic comparisons with renewables areskewed toward natural gas.

• There is already considerable intervention in the electricity market, there is no free“market” in Colorado for electricity.

• The regulated utility, Xcel, has shown it is willing to ignore price signals• Without intervention, the amount of renewables in the market would be at an

inefficient level

The first point was discussed in detail in the previous chapter, and the rest are coveredbelow.

Electricity: not a market

An RPS is an intervention in the electricity market in Colorado – it mandates the mainIOU (Xcel Energy) to purchase a certain percentage of renewable electricity. Economistsdon’t like intervention in a market without a reason; it has historically caused more harm thangood. If the market was producing an inefficient amount of a good (in this case renewableenergy) then it could be deemed a “market failure” and the government (or some other non-market entity) would intervene. In the case of electricity generation in Colorado, there is nota complete market because the Colorado Public Utilities Commission (PUC) regulateselectricity generation. The PUC sets the rates and regulates all aspect of the electricityindustry in Colorado (down to what Xcel can charge for a specific kind of pickup truck)7. Inthis sense, the electricity market in Colorado is not a free market – price signals are sentincorrectly (or not sent at all) to users and generators of electricity alike.

5 Minnesota’s PUC has established clear pricing structure for air pollution externalities suchas CO, SO2, NOx and CO2 (Minnesota PUC 2002)6 The EPA is currently implementing regulation for mercury from coal plants7 See the rate schedule, Colorado PUC website: www.dora.state.co.us/puc/

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Lamar case: Utilities don’t make good choices

An excellent example of a non-market failure in Colorado’s electricity market is theLamar case. In early 2001, Xcel presented its plan for new generating capacity to theColorado PUC. It did not include a bid by Enron Wind for a 162MW wind plant in Lamar,Colorado. The PUC and several renewable advocates questioned this omission at PUChearings and eventually the PUC forced Xcel to include the wind plant in its final bid. Duringthe hearing, Xcel revised its natural gas price projections three times8.

In Minnesota, the PUC requires all comparisons of new generating capacity tocompare renewables to fixed-price fossil fuel based generation using long-term contracts.This ensures that the comparisons are based on equal footing. Xcel is headquartered inMinnesota, and is the regulated utility in that state as well as Colorado. It is instructive tonote that the same company, operating under a different regulatory regime, behaves verydifferently.

Xcel was biased towards natural gas in the Lamar case for two reasons: poor priceprojections and institutional resistance to wind power. Xcel cited several high estimates for“ancillary” costs of wind power, due to its intermittent nature (Lehr et al 2001). The PUCrejected these costs as incorrect estimates. Xcel, like most IOU’s, are conservativeinstitutions that do not get rewarded in the marketplace for risk-taking. Xcel in this case isbiased against wind because it would have forced change in its operations.

From its initial resistance to wind, Xcel is now touting the benefits of the Lamar windfarm. In testimony before the Federal Energy Regulatory Commission (FERC) this summer,an Xcel executive testified that Lamar would save Colorado ratepayers $4.6 million per year(Andrews et al 2003).

Fuel price adjustment – the lack of incentive

What could also be termed a non-market failure, regulated utilities lack the incentiveto save consumers money through lower electricity costs. Once rates are set by the PUC,utilities can pass along any excess costs by using a “fuel cost adjustment” when prices rise.This allows utilities to continue to install natural gas plants, which they are comfortable andfamiliar with, and consumers will hedge against any future price rises. This perverseincentive was very obvious in the Lamar case, when Xcel chose not to include wind in itspreferred portfolio.

8 The sources of these projections as well as the actual numbers were claimed to beconfidential by Xcel, and were not released. (Lehr et al 2001)

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Why an RPS?

When arguing that non-market failures have produced an inefficient percentage ofrenewable energy in Colorado, an obvious response would be to deregulate or restructure themarket. If wind power competes favorably with natural gas, but is not being chosen due topoor regulation, restructuring and not more regulation might address the inefficiency. It isbeyond the scope of this paper to address the merits of deregulating Colorado’s electricitymarket, and the recent events in California have made deregulation a politically unlikelyoption. We will assume that deregulation is not an option, which leaves further interventionin the market to correct the non-market failure. Windsource, a market product for windenergy, could be considered a market solution for the inefficient amount of renewables. Theshortcomings of Windsource and market solutions are discussed below.

Another argument against an RPS in Colorado would be that as a “command andcontrol” standard, an RPS is inefficient. A more efficient solution would be taxes: either taxcredits for renewables or a tax on pollutants. The problem with taxes is that wind already hasa federal tax credit, established in the 1992 Energy Policy Act, and extended through 20039.This tax credit is one of the main reasons wind is now cost competitive with fossil fuelgenerated electricity. Taxes on carbon or other pollutants are attractive on efficiencygrounds, but just as deregulation, are not currently politically feasible.

What about Markets?

Opponents of government intervention would point to Xcel’s Windsource program asthe way for renewables to penetrate the generation market. Windsource currently provides 60MW of power to the grid in Colorado, or about .7 percent of Colorado’s total generatingcapability (Xcel 2003). In terms of actual kWh generated, wind makes up only .2 percent ofthe total state’s energy (EIA 2003). Windsource is also sold to consumers at a premiumabove traditional energy rates. For residential customers, it is sold in $2.50 blocks of 100kWh, or for .25 cents a kWh premium (Xcel 2003). Compared to the residential rate of 7cents a kWh, this is a 36 percent markup. Here is Xcel’s position on Windsource pricing ontheir web site:

“Because wind energy costs a bit more than electricity from conventional sources likecoal or natural gas, each block costs an additional $2.50 above regular electricityrates” (Xcel 2003)

This is a curious assertion, because Xcel recently testified that the wind farm at Lamar wouldactually save Colorado ratepayers $4.6 million per year (Andrews et al 2003). If Xcel isasserting that wind will save ratepayers money, why does it charge ratepayers a premium forWindsource? 9 The Production Tax Credit (PTC) for wind was included in the latest energy bill, which didnot pass the senate in November 2003. It is generally thought it will be extended in newlegislation, but this is uncertain.

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The problem with market-driven means of achieving renewable market penetration isthat markets do not seem to incorporate renewables at a fast enough pace. The benefits fromrenewables are mainly public goods – price stability, cleaner air, CO2 emissions, etc. Mostconsumers will not choose to pay the 36% markup for renewable energy, and the market willunder invest in this public good. This is because consumers know if they pay for renewables,other consumers will “free ride” on their purchases. This seems to be the case - theWindsource program has 30,000 customers (Xcel 2003), which is a mere .7% of the states’population (US Census 2000). This small percentage is not due to a failure of the program,because Windsource is the most popular program of its kind, Xcel claims it has the mostcustomers of any wind-purchase program (Xcel 2003).

Another problem with market-driven approaches is that the market for energy does notseem to match people’s stated preferences. National polling over the past twenty years hasconsistently revealed a high public preference for renewable energy. A Gallup Poll conductedon November 8-11, 2001 found that 91 percent of Americans favor investing in alternativesources of energy (CRES 2002). A recent poll in Colorado showed 82 percent support forrenewable generation (Environment Colorado 2003), far higher than the .7% of peopleactually purchasing wind power. We could put down these differences between supportersand purchasers as simply variations in stated and revealed preferences, but the difference hereseems too large for this simple account.

In this case, it seems that Windsource (or other market-driven renewable strategies)cannot provide the efficient amount of renewables. This can only be asserted if we feel theefficient amount of renewables is more than the .2% currently in place via the Windsourceprogram. The first argument for this is that when the Lamar project comes on line, it willincrease the percentage of renewables from .2% to .8%. The Lamar project was chosen asleast-cost generation by the PUC, not as part of the Windsource program. Cost savings will bepassed on to all of Xcel’s customers, and the positive economic (and environmental) effectswill be felt by all of Xcel’s customers.

5. The Case for an RPS

If utility generators value fuel diversity, price stability, and low cost, then we are ledto believe that a greater percentage of renewables should be included in the fuel mix forColorado generators. Our analysis of the recent history in Colorado shows that the currentregime is not adopting renewables at an efficient rate: either through market-based strategieslike Windsource, or through the normal Integrated Resource Planning process via the PUC.Options other than an RPS for increasing the percentage of renewables, such as a carbon taxor deregulation, are politically unlikely. This leaves us with the RPS as the best policy optionfor increasing the penetration of renewables in the Colorado energy market. While it isimpossible to know if an RPS is the “best” policy option, it seems to be politically viable, andhas a positive (though short) track record in other states.

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What is the efficient percentage?

Given that an RPS is the chosen policy tool, it leaves the question of exactly whatpercentage of renewable generation should be mandated? We can assert that utilities valuefuel diversity and price stability, but that does not help us with determining an exactpercentage. The current percentage of renewable generation in Colorado is less than 1percent, 5 if you include hydropower (EIA 2003). There is very little hydropower resourceleft to exploit in Colorado, suffice to say that most renewable growth will come from wind,with a small contribution from biomass and solar electric.

Simply choosing a percentage of renewable generation is difficult, as Resources forthe Future states: “we are not omniscient.” (Macauley et al 2002) Recent studies show thatwind tends to become more costly, and be more difficult to integrate into the grid, when itreaches fifteen percent of the total capacity (Namovicz 2003)(Parsons et al 2003).

More is better

The strongest argument for increasing Colorado’s percentage of renewable energy to10 percent is that only with a large market share does the consumer surplus of renewablesbecome noticeable. This is due to three key factors:

• Decreasing natural gas prices and volatility due to reduced demand• Decrease in prices of renewables due to economies of scale• Decrease in prices of overall energy due to lower cost renewables

Mandating a large percentage of renewables allows the market share of this generatingcapacity to affect the natural gas market, which can then dampen volatility and hold priceslower (Bolinger et al 2003). This benefits consumers doubly: they receive lower energy costsfrom renewables, and their gas-fired electricity and heat is also lower than withoutrenewables. Lower prices due to economies of scale of renewables have been documented inmany places, but to put it simply: renewables are capital intensive; therefore economies ofscale will reduce costs. This is opposed to natural gas, which has seen increased costs due todemand.

Resources for the Future10 did a recent study on renewables to find the consumersurplus from adopting renewables compared to combined-cycle natural gas. They used theexternalities of carbon dioxide (CO2) and thermal effluent, and did several scenarios. Theyfound the consumer surplus for wind was higher in every scenario, including those with noexternality accounting, and that faster adoption rates led to higher consumer surpluses.

10 A natural resources economic think-tank. See http://www.rff.org/

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6. Conclusion

The economics of renewable energy in Colorado, specifically wind power, arefavorable. Costs of wind power have fallen to levels where they are cost-competitive withnatural-gas fired electricity, especially when compared with forward price contracts instead ofprice projections. The current market is failing with respect to renewables, with an inefficientamount of renewables being adopted by the regulated utility. This market failure is mainlycaused by non-market failures with regard to the regulated utility in Colorado. An RPS of tenpercent seems to be a worthy policy option for correcting this non-market failure, given thealternatives are not politically viable.

A note of caution

This paper focuses on Colorado, and not other state’s efforts to implement RenewablePortfolio Standards. The analysis here relies heavily on wind, which is the most cost-effective renewable available today. Other states do not have Colorado’s abundant windresource. Colorado has a regulated energy market, states with a deregulated market may nothave the same non-market failures listed here.

Concepts Covered

Externalities, Price Elasticity, market failure, non-market failure, public goods, “free riders”,efficiency, consumer surplus, stated vs. revealed preferences.

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References

Andrews, Steve, Rick Gilliam, Howard Geller “Ending the Natural Gas Crisis: The CriticalRole of Efficiency and Renewables” 2003 Western Resource Advocates, White Paperhttp://www.swenergy.org/news/white_paper_natural_gas.pdf

Bird, Lori. NREL market anaylsist. Personal Communication, November 2003

Bolinger, Mark, Ryan Wiser, and William Golove. “Accounting for Fuel Price Risk: UsingForward Natural Gas Prices Instead of Gas Price Forecasts to Compare Renewable to NaturalGas-Fired Generation” Orlando Lawrence Berkeley Labs. August 2003. www.lbl.gov

Caldara, Paul. Generation and Distribution Manager, CU Boulder. Personal communication,December 2003.

Colorado PUC. Website. Accessed 2003. www.dora.state.co.us/puc/

CRES “Renewable Portfolio Standard Backgrounder”, 2002 http://www.cres-energy.org/documents/RPS%20Backgrounder_MW-2-04-02.pdf

EIA “Annual Energy Outlook” US Department of Energy, Energy InformationAdministration 2003. www.eia.gov

Environment Colorado press release, “Coloradans Strongly Support Renewable Energy: 82Percent Prefer Renewables” Feb 17th 2003,http://www.environmentcolorado.org/envcoenergy.asp?id2=9285

Fort Collins Electric Energy Supply Policy. March 25, 2003.http://www.fcgov.com/utilities/energypolicy.php

Lehr, R.L., J. Nielsen, S. Andrews, M. Milligan “Colorado Public Utility Commission's XcelWind Decision” NREL conference paper. September 2001

Lovins, Amory and Hunter Lovins “An analysis of the California Energy Crisis” 2002.Rocky Mountain Institute. www.rmi.org

Macauley, Molly K., Jhih-Shyang Shih, Emily Aronow, David Austin, Tom Bath, and JoelDarmstadter “Measuring the Contribution to the Economy of Investments in RenewableEnergy: Estimates of Future Consumer Gains” February 2002. Resources for the Future.www.rff.org

Minnesota PUC, “Externality pricing” 2002 www.puc.state.mn.us

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Namovicz, Chris “Update to the NEMS Wind Model” EIA presentation, March 18th 2003,http://www.eia.doe.gov/oiaf/aeo/conf/pdf/namovicz2.pdf

Parsons, B., M. Milligan, B. Zavadil, D. Brooks, B. Kirby, K. Dragoon, J. Caldwell “GridImpacts of Wind Power: A Summary of Recent Studies in the United States” June 2003.NREL Conference Paper. www.nrel.gov

Taylor, Jerry and Peter VanDoren “Evaluating the Case for Renewable Energy: IsGovernment Support Warranted?” Cato Policy Analysis No. 442, January 10, 2002.www.cato.org

Xcel energy, website. Accessed 2003. www.xcelenergy.com