How will the business climate change over the next year or so? That’s anybody’s guess. The economic uncertainty of this era does not mean business stops, but it does mean activity moves like a soldier through a mine field – with great caution. To provide at least some guidance, because business hates uncertainty, the following two articles may reduce some of the cloudiness in your crystal ball. In the first article, Barbara Sands, PA Consulting’s Renewable Energy Consultant, suggests a few coping tactics for OEMs and wind farm operators. In the second, Anton Cohen, principle at accounting firm and business consultant Reznick Group, suggests what financing institutions like to see in a project and provides some insight for delivering them.
Addressing the challenge of expiring federal incentives
Federal incentives have been the major driver in reducing the direct cost of renewable energy generation to customers. Between 2009 and 2011, the federal cash-grant program provided almost $10 billion to renewable facilities, reducing the direct cost to customers by about 30%.
However, this program expired at the end of 2011, and other incentives, the Production Tax Credit in particular for wind generation, expires at the end of 2012, with others doing so soon after. Congress has extended these programs in the past, but not without challenges. Over the last several months, there have been several attempts to include the extension of these incentives as part of other legislation.
At the same time these incentive programs are going away, the target level for renewable generation under state renewable portfolio standards (RPS) is starting to increase, with most programs ramping up to hit their maximum targets around 2020.
With the elimination of federal incentives for renewable generation, more than $20 billion may be shifted from the federal level (i.e. all taxpayers) to the customers in states with RPS targets. The figure is based on approximate capital costs of $2,000/kW in 2012 dollars for installed wind capacity. The resulting rise in energy costs will test state, and by extension, regulator support for renewables, and participants across the sector will face a number of complex challenges from this evolving scenario.
Players across the supply chain will have to adapt in at least the following ways:
Equipment manufacturers will come under pressure to improve performance while operators continue to reduce the cost of their ongoing operations and maintenance. Considering the current projected level of natural gas prices of about $4.50/million Btus, the capital cost of wind projects would have to be at least 35% lower for wind generation to be competitive with new natural-gas-fired generation. The capital cost of solar projects would have to decrease by an even greater amount to remain competitive. Given the magnitude of equipment-cost decreases already observed in the market, further reductions will be challenging. Manufacturers would have to decrease fixed capital costs and improve efficiency for a broad base of renewable generators (i.e., not just a few selected resources located in the best wind regions) to become cost competitive across the U.S.
To be competitive renewable developers must focus on sites and projects that provide the best economics. Renewable generators are already grappling with the impact on power prices of the current and projected low cost of natural gas. Natural gas prices would have to almost triple from the current levels of less than $3.00/million Btus for renewables to compete on a total cost per MWh basis. In addition to low natural gas prices, previously proposed federal greenhouse gas legislation, which would increase the cost for generators using fossil fuel, is unlikely to be enacted and provide a boost to the renewable industry anytime soon. Furthermore, it is important to note that comparing wind and most solar resources to natural gas-fired generators is not exactly an apples-to-apples comparison. Most of these renewable generators are intermittent resources, providing minimal capacity value and thereby requiring a utility to buy additional capacity to firm up the renewable resource. Additionally, many of the best sites for such resources may require significant transmission investment to deliver the renewable power to the load centers. The elimination of federal incentives will compound the economic challenge that renewable developers face in acquiring financing for future projects and selling renewable power.
Utilities will have to find a way to recover the high cost of renewables. Many state renewable targets were established, and even increased, when state economies and budgets were stronger and commodity prices were higher. With the projected low price of natural gas and the expiring federal incentives, the price utilities pay for renewable energy purchases could potentially cost more than double the price they pay for their other energy purchases. This difference in cost could lead to potential prudence challenges in the coming years. As a result, utilities will place pressure on regulators to let them recover the higher cost of renewables in future rates, thereby passing these higher costs to customers. Ultimately, customer support will play an important role in determining the future of renewables.
Renewable Energy Consultant
PA Consulting Group
Wind-farm financers begin an uphill trek
Whether Congress will renew the Production Tax Credit is still up in the air. It’s unfortunate because the credit lets wind farm owners lower their tax burden by $22 for every MWh they produce. When the credit was a certainty, new wind-farm developers had room to negotiate a Power Purchase Agreement (PPA), usually with a utility. “The agreements we have seen range from $50 to $60 per MWh,” says Anton Cohen, a principal with accounting firm and business consultant Reznick Group (reznickgroup.com). Without the credit, PPAs will demand higher figures.
Removing the PTC from the table requires more creativity on all fronts by wind-farm developers, for equipment selection, financing, construction, and operation.
To date, the financial success of a wind farm has come down to the size of its PPA, says Cohen. “With a PPA locked in, developers could make better use of the PTC.”
Wind farm financing once came by a range of grants, deals, and certificates. In the recent past, wind-farm developers took advantage of the 1603 Treasury grants. The grants will expire on September 30, 2012 and it’s unlikely they will be expended.
At the end of 2011, many companies rushed to meet a beginning-of-construction test required by the 1603 grant rules. “Either through ‘physical work of a significant nature’ as the grant language read, or they incurred 5% of costs method. The guideline was to makes sure they were eligible for the grant,” says Cohen. A first round of funding gave access to a second round for those projects and encouraged companies to finish work getting turbines into service by year’s end.
A merchant deal, always a possibility, provides a less used revenue stream. In this arrangement, the operator usually has no PPA and so sells power whenever possible and at whatever price they can get.
Lastly, the Renewable Energy Certificate (REC) market is not as active for wind as it is for solar. “Hence, they matter little. For wind farms to be profitable, it comes down to the PPA,” says Cohen. None of these financing methods bode well for the wind industry. “So I would expect to see a significant slowdown in 2013,” he says. Regardless of whether a company supplies or develops wind farms, few want to commit now to new construction without the PTC.
Despite all this doom and gloom, a small number of developers believe they can get deals done and projects started.
Still, starting a project now is a risky move unless its financials are strong without the PTC. “This would come down to having good financing locked up, good debt terms, strong equity, and ideally, a strong PPA,” says Cohen.
What banks want
In this economic climate, says Cohen, banks first want to see companies with a balance sheet, and most players on the wind side have them. Banks also want to see that the project is fairly far along in concluding a PPA. Then they want to see a model of a project’s finances, whether based on probability factors of P50 or P90, that the wind will blow and let the project hit its goals. Most off-takers will still be utilities.
The cash-flow models Cohen refers to are a series of calculations that consider the vagaries of 20-year projections of capacity and pricing, and ideally, would show a bank that a project has a good chance it can hit revenue-stream targets. Banks want to make sure they get their loans paid back in 15 to 20 years. So developers have to show sources and inputs, and prove they can make the payments.
“Banks will go through their due diligence in part looking for answers from the debt and capital-markets guys. In a word, banks want certainty, and that comes from good wind resources,” he says. On the regulatory side, a successful project depends on connection issues, among other things.
Tax equities carry different weight based on probability factors, and how banks get their cash out. Remember, the banks are not getting the PTC.
Technology will also play a big role in financing decisions. Banks will take notice as OEMs introduce new turbines with greater outputs, more efficiency, and require less maintenance. As groups collect performance data that shows greater reliability, more developers will be convinced they don’t need a PTC when PPAs provides sufficient value.
Today’s wind turbines are more reliable than a few years ago. This is the big reason people think they can get deals done without the PTC. WPE
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