Purpa has seen alterations over the years but its two key elements remain: a must-take provision forces utilities to connect projects, and an avoided-cost rate calculates prices by determining what utilities would otherwise pay to build a hypothetical power plant.
All alternative-energy projects other than co-generation plants had to be under 80MW to receive Purpa qualifying facility (QF) status from the Federal Energy Regulatory Commission (Ferc). Beyond those parameters, the implementation of Purpa - including the calculation of rates - has landed mostly in the hands of state regulators.
Much has changed in 35 years. Electricity deregulation, which began to take hold following the Energy Policy Act of 1992, eventually left roughly two-thirds of the country with competitive markets and competitive prices - making Purpa's avoided-cost calculations largely irrelevant. Renewable energy standards in 30 states force utilities to buy significant amounts of alternative power, often rendering Purpa redundant. Furthermore, utilities in competitive markets since 2005, can opt out of the must-take provision for facilities that are above 20MW (except co-generation plants), and nearly 40 have done so nationwide.
However, in some parts of the country - particularly the Pacific Northwest - Purpa wind markets still thrive. But several issues being investigated by courts and regulators in key states could affect its relevance there.
Two protracted battles - one in Idaho over curtailment of qualifying wind projects and another in Texas about the must-take provision - could end up being decided by federal courts and set national precedents. Verdicts in favour of wind generators would provide surety for Purpa developers about fixed rates as legally enforceable obligations regardless of intermittency concerns.
Other issues, involving avoided-cost formulas, control of renewable energy credits (RECs), contract lengths and damages for QFs that fall behind their production schedules, are likely to be decided by individual states. The litany of contested issues highlights an underlying tension between utilities and Purpa developers.
"Utilities don't like competition," says Peter Richardson, a managing member at Richardson & O'Leary law firm, which represents Purpa developers. "When utilities buy power from a QF, it's a flow-through expense - they don't get to mark it up and they don't get a return on it."
Utilities see Purpa in a different light. "From our perspective, the overarching goal is to protect our customers from further harm in terms of the price they pay for their electricity," says Brad Bowlin, a spokesman for Idaho Power. The utility firm has absorbed 537MW of Purpa wind within four years, and argues that it has been overloaded with intermittent power for which it is often forced to overpay.
Unsurprisingly, the pathway to success for Purpa wind projects includes one major hurdle that bedevils the US wind sector at large: without a significant spike in natural gas prices, which frame the typical proxy plant used in avoided-cost formulas, Purpa wind schemes are unlikely to break even unless the lucrative federal production tax credit (PTC) is extended beyond the end of the year. Although the PTC's future brightened following last month's US elections - wind-friendly Democrats retained control of the White House and the Senate - the programme's future is not guaranteed.
Regardless, the levelised - or average cost per MWh over the lifetime of the plant - 20-year avoided-cost Purpa rate in Oregon approaches $55/MWh, according to Adam Bless, a senior utility analyst at the Oregon Public Utilities Commission, which monitors utilities. That price, Bless says, is representative of regional rates because the cost of gas and gas turbines does not vary significantly throughout the area. Adding a PTC value of $0.022/kWh brings another $22/MWh, meaning the basic price for those able to qualify for financing is roughly $77/MWh. RECs, despite their nominal value - and assuming developers keep control - tack on a marginal amount.
A typical Pacific Northwest wind project, meanwhile, needs about $80/MWh to survive. "That paints a pretty common scenario," Richardson says. "You have to have all your ducks lined up to make things work."
Glenn Ikemoto, a California-based developer doing business as Energy Vision, has built hundreds of megawatts of qualifying wind projects in the Pacific Northwest since 2004. The path to Purpa success, he says, runs counter to the basic strategy used by large-scale wind developers, who find the best resources, make strategic land acquisitions and develop megaprojects - then approach utilities to negotiate the best price possible.
"We can't compete in a situation with much larger organisations that invest hundreds of thousands of dollars to prepare a project for bid," Ikemoto says. "It's also very, very difficult for us to have a project idea and walk into a utility to negotiate a deal."
But Ikemoto, a longtime wind-industry executive, believes Purpa's 35-year-old pillars - the must-take provision and the avoided-cost rate - still mitigate risk and help secure financing to build profitable projects for those able to develop areas overlooked by the major players. "We are given a price and we have to go find projects that can meet that price," Ikemoto says. "The big developers ask: 'Do we have the best project?' But with Purpa the question is: 'Do we have a good-enough project?'"
Ikemoto agrees that Purpa projects are unworkable without the PTC or a suitable alternative. "It's imperative and essential," he says. "Absent the PTC, I think it's virtually impossible to have an economic Purpa project."
Attorney Arron Jepson learned the hard way. After leaving a thriving law practice in 2005 he and a partner spent six years developing a Purpa project in Idaho. They leased land, started the permitting process and aimed to beat the deadline for the government's cash-grant programme - a stimulus-era alternative to the PTC that paid 30% of costs if construction began before 2012. The project ran out of time.
"We ended up going through an extended permitting appeal process that wound up in district court," Jepson says. "There are all kinds of things that affect a small Purpa development which can extend you out for months and months."
Jepson believes the project would have been profitable if it earned $80/MWh - unreachable without help from the federal programme. He estimates the process cost him roughly $1.5 million worth of time and money as an attorney. "I put a lot into it and got nothing for it," he says. "Now I'm back to rebuilding a law practice."
Jepson's experience underscores the dilemma of Purpa - it only works when regulators allow it to work. States with a weak regulatory commission and strong utilities that don't want to purchase Purpa projects are likely to set avoided-cost rates so low as to kill the market. And, like all other forms of US energy, wind still needs government help to thrive.
"Purpa is not going to be a silver bullet," says Jan Hamrin, president of the non-profit Center for Resource Solutions. "People have been trying to get rid of the law for years by arguing that it's not relevant anymore. But although everything depends on where you're located, it's still better to have Purpa than not to have it."
MORE THAN 50GW TO DATE - HOW PURPA HAS SUPPORTED SMALL WIND PROJECTS
The world of 1978 that ushered in the Public Utilities Regulatory Policy Act (Purpa) was similar to the landscape of today in several ways. President Jimmy Carter, a Democrat, faced a weak economy, volatile energy prices and a sour political climate.
But the world was also different. Electric utilities were monopolies that produced, sold and transmitted power without competition. Purpa, designed to decrease dependence on foreign oil, created opportunities for domestic alternative-energy producers to sell into the market.
"Before we had Purpa, the utilities would simply say: 'We won't interconnect, we won't take your power,'" says Jan Hamrin, president of the non-profit Center for Resource Solutions. "In the early years, the environment was hardly mentioned."
To comply, wind projects once had to be under 80MW, but now they are subject to legislative revisions that typically limit them to 20MW or less. Projects in several states comprise turbines under 100kW. But developers interested in bigger build-outs sometimes string several projects together, locating them just far enough apart to comply with the law. The definitive example, Idaho Wind Partners, links 11 subsidiary farms to fashion a 183MW project.
Purpa's broad success through the years is easily quantified. According to industry newsletter Electric Utility Week (EUW), the aggregate 35-year total of Purpa installations through 2011 is more than 71GW. Cogeneration accounts for at least 55GW, while smaller producers, including wind and solar, total 15.7GW.
Nationwide, Purpa installations from all sources dropped from a high of 4.7GW in 2002 to 545MW in 2006, and have not risen above 1.5GW in any year since, reports EUW. A breakdown for wind is no longer tallied by the Federal Energy Regulatory Commission.
Yet there was a day when Purpa ruled. Roughly 1.6GW of Purpa wind projects went online in California back when turbines were still measured in kilowatts, according to the California Wind Energy Association. Most of that machinery, however, was connected before 2002, when the state adopted its initial renewable energy standard.