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Building Operating Management

Sorting Out Green Power Choices

PPAs, RECs, VERs: Here’s a look at what you — and the environment — get for your money

By Lindsay Audin Facilities Management   Article Use Policy

In an effort to reduce greenhouse gas (GHG) emissions and give their organizations some green credibility, many facility executives are incorporating on-site renewable or high-efficiency sources of power into their operations. Federal income tax credits (available until the end of 2008) and state and utility-sponsored rebates, grants or low-interest loans are lowering the net cost for such on-site systems.

Many facility executive are also purchasing renewable energy credits (RECs) or carbon offsets (also called Verified Emission Reductions, or VERs) that pay others to produce renewable energy elsewhere. Together, these processes help to minimize an organization’s carbon footprint.

Financial incentives and novel contractual arrangements are opening new doors to such options, but finding the right paths may still be a challenge. With the major presidential candidates supporting some form of carbon regulation, many organizations are getting up-to-speed on these renewable energy opportunities to avoid being caught short after the November election.

While improving an organization’s environmental posture is now seen in most boardrooms as a plus, some are realizing that on-site power systems may also help stabilize the future cost of their power. The cost of a customer-owned green power system is limited to the initial capital outlay and ongoing maintenance, and is thus immune to volatile energy pricing. If a third party owns the on-site green power system, the price of its power may be discounted off that of the utility under a long-term contract, typically called a power purchase agreement (PPA). In such cases, little or no upfront customer investment is involved and bottom-line savings appear from Day One.

What’s a PPA?

The term “PPA” applies to a contractual arrangement wherein a customer buys power from a non-utility supplier. Utilities have PPAs with their wholesale power suppliers, and customers buying power from non-utility suppliers do so through PPAs with retail power marketers. Customers may also have a PPA with a supplier providing power to their facilities from a supplier-owned generator at the customer’s site.

PPAs for both renewable and small-scale cogeneration plants grew rapidly after the California power debacle in 2000-01, with generous funding from both that state and several others. While power from cogeneration units is not usually considered “green,” unless its energy source is renewable, such as landfill gas, such systems provide power more efficiently by making use of waste heat that is normally discarded during power production. As a result, they may reduce greenhouse gas emissions compared to utility-based power.

Many types of facilities are using PPAs, including factories, industrial parks, institutions, big box stores, government buildings and apartment buildings. With the growth of the LEED rating system, which offers points for renewable energy and higher energy efficiency, the commercial real estate community has also become engaged.

From the customer standpoint, the major selling point of such contracts is that the very high first cost of clean on-site generation, PV panels, for example, is avoided, along with the internal financing hassles that often block facility-related projects. From the supplier view, once project financing has been obtained, a variety of cash flows and benefits may be tapped, including:

  • One-time utility or state grants or rebates
  • Federal (and maybe state) tax credits
  • Sale of emissions credits
  • Revenue from sale of power to customer and utility
  • Accelerated depreciation.

In some cases, the supplier is renting a customer’s roof space and producing power provided to the customer but sold to the utility. The customer pays the utility the usual amount but receives rent or a discount from the supplier, who in turn gets paid by the utility for that power at a higher price than it could charge the customer — in some cases, as high as $.48/kWh. The utility is allowed to spread that extra cost among all ratepayers under a regulatory requirement to buy a certain percentage of the power from renewable sources.

Avoiding PPA Pitfalls

While such arrangements hold great promise to increase the market share of renewables, a variety of issues require attention before environmentally responsible power begins to flow. Some problems may be avoided by having an independent consultant or engineer review both the project and its contract before anything is signed. Because all PPAs are not created equal, facility executives should entertain multiple bids to ensure they are getting a good deal. Some financial matters, like sharing of grants or rebates, may be negotiable.

Still, there are other issues for facility executives to consider. Here are some concerns expressed by those who are considering a PPA:

  • Equipment operations and expectations: Power supply may be intermittent, so savings may vary or be less than expected. Such systems operate in parallel with utility power so the lights will stay on, but cash flow may “flicker.”
  • Project development and execution: Much more may be involved than merely signing a contract. For example, roof repairs or other upgrades may be needed, which are not part of the deal.
  • Impacts on the facility and its energy rates: Depending on the type of system, changes to some facility operations may become problematic. Utility rates for power still purchased from the local power company may also change. A California school district recently suspended its efforts to install solar power panels after its electric bills rose. The problem was related to how the local utility calculated rates for large energy users installing such equipment, and an inexperienced contractor who apparently did not understand the tariff.
  • Interaction with other power contracts: Where retail electricity is deregulated, some PPAs require that the on-site power supplier be given a say in how the customer buys the rest of its power so that it cannot benefit in ways that control or reduce the on-site supplier’s revenue. Some customers balked at the idea of signing a 20-year contract.
  • Calculation of rent or savings: While $100,000 in annual rent or a 10 percent discount may initially sound good, the devil may be in the contractual details. A $100,000 fixed annual rent in Year 1 (at present inflation rates) probably won’t be worth $35,000 (in today’s dollars) in Year 20. A 10 percent discount may not produce 10 percent savings. The price of power under the PPA may be discounted from a bundled utility electric rate that includes peak demand. The assumption is that the on-site power will reduce utility demand charges, but that may not be the case — for example, with a combined heat and power plant that runs sporadically. If that situation occurs, the facility pays the demand charge to the utility in addition to the contractually specified amount, which includes the demand charge, to the on-site power supplier.
  • Termination conditions: If a system fails and must be removed, or the customer sells the building. Such issues should be clearly spelled out in the contract.
  • Financial backing: More than 30 companies have offered PPAs for on-site power, but many have already gone out of business. Insurance and bonding may involve major up-front payments for larger systems, and some smaller suppliers have lacked the financial strength to secure such up-front capital, causing projects to falter.
  • Credit rating: A customer’s credit and bill payment track record must be good enough to make a lender confident that the customer can handle a 20-year power contract. Even owning the building may not be enough to satisfy lenders in some cases.
  • Changing technology: While PV power has been around for decades, some aspects of it as applied to buildings are still developing. Some panels and ancillary systems, such as microinverters, either lack the UL label or a track record long enough to pass a lender’s muster. That makes issues of warranty and guarantee iffy. A state-of-the-art design may not elicit a lender’s money on the table.
  • Project timing: If things don’t move forward quickly, incentives or tax credits could expire and financing be lost.

The bottom line is that before signing, the deal should be reviewed by a consultant or engineer with experience in handling power contracts and vetting of power suppliers.

RECs and Offsets

Using renewable energy to mitigate one’s GHG emissions need not involve on-site power production. Firms who lease space or don’t want to invest in hardware, may instead buy RECs — also called ‘green tags’ — or carbon offsets. RECs cover the cost of displacing power generated by fossil fuels with solar, wind, or other renewable power sources. Offsets pay for net reductions in GHG through a variety of methods.

As with the purchase of retail power, all generated electricity goes into the pool. It is therefore not possible to claim that the kWh generated by a distant wind turbine is actually flowing to the busbar of the firm that purchased it. The end result of buying a REC, however, is that green power is indeed being injected into the pool so that less fossil fuel power is needed to meet the pool-wide load.

While purchasing RECs or offsets will not yield immediate savings, purchasing such credits at today’s prices may provide a hedge against higher REC pricing down the road. If new regulations require that others, such as utilities or governmental facilities, begin purchasing them, competition is likely to raise their price, a phenomenon already occurring in some areas.

Until GHG reductions become mandatory, RECs and offsets should be seen as voluntary investments in projects that reduce GHG. A variety of firms and organizations act as intermediaries between such projects and customers wishing to support them.

Facilities seeking to become carbon neutral may purchase RECs to balance their use of fossil-fueled electricity, and enough offsets to negate their on-site use of fossil fuels — gasoline used in employee commuting, for example. The process starts by performing a GHG inventory to determine the quantity of offsets needed to achieve neutrality. Software or online calculators are available to convert all forms of GHG emissions into their equivalent tons of carbon.

REC and Offset Pricing

RECs are priced in dollars per megawatt-hour and reflect the added environmental value of renewable power over fossil-fueled power (e.g., 2 cents per kWh). When buying green power, they reflect the differential in cost compared to fossil-based power. Offsets are priced in dollars per metric ton (2,205 pounds) of avoided carbon dioxide. Unlike a REC, a carbon offset need not represent production of useful renewable energy. Some offsets work by exchanging one GHG for another: burning methane that would normally leak from a landfill still generates carbon dioxide, but the methane that would have otherwise entered the atmosphere is 20 times more potent, so the overall carbon impact is reduced by about 95 percent.

Pricing of both RECs and offsets is market-based. It has recently become more volatile. Unlike much of the rest of the developed world, the U.S. has no national requirement for businesses to cut carbon emissions. Because purchases are voluntary, pricing is relatively low. Offsets have recently been sold in the U.S. for $5 to $7 per ton. Pricing in Canada, a signatory to the Kyoto Protocol, has been over US$25 a ton.

To avoid volatility, and perhaps buy while the market is low, some firms seeking to become carbon neutral are making long-term purchases. Doing so may avoid price jumps if a federal carbon reduction law is enacted. Consider: For comparison purposes, an offset price of $25 per metric ton is roughly equivalent to an increase in fuel oil pricing of about $.30 a gallon.

Another reason behind price volatility is the entry of uncertified offsets that may be offered at startlingly low prices. Questions have been raised about the reality of their claimed GHG reductions. Some RECs have also been criticized as merely improving the profitability of existing renewable systems like wind farms instead of increasing their capacity and output.

Where RECs are regulated, in states in which utilities are required to buy them, for example, their “additionality” — ability to increase total renewable energy output — is supposed to be verified. Because renewable power systems are growing rapidly, however, some RECs purchased today may not result in generation of new green power for up to 18 months. Failure to eventually do so would involve breach of contract and possible financial damages against the power developer.

For More Information

The Green Power Market Development Group, a project of the non-profit World Resources Institute, helps firms purchase green power through guidance documents that include sample RFPs and contracts. DOE’s Green Power Network is also helpful. EPA’s Green Power Partnership is a good start for those seeking both the basics of buying green power and recognition for doing so.

The Chicago Climate Exchange, supports trading (buying and selling) of RECs and offsets as commodities.

For finding out how to determine if an offset program is credible, check out Clean Air–Cool Planet's, Consumers Guide to Carbon Offsets (pdf).

Independent certification programs exist for RECs and offsets. Green-e covers RECs, while the top international gauge for carbon offsets is The Gold Standard. Don’t be surprised to find the pricing a bit higher for such well-rated renewables.

Lindsay Audin, CEM, LEED AP, is president of EnergyWiz, an energy consulting firm based in Croton, N.Y. He is a contributing editor for Building Operating Management.


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