Energy Advisor

The Energy Policy Act of 2005 (EPAct) provides tax deductions for the installation of certain energy efficiency measures through section 179D. These measures must exceed (ASHRAE) 90.1 -2001 and can be installed at new or existing commercial properties. Your efficiency projects may be eligible for the maximum deduction of $1.80 per square foot of building space (including garages).

This is achieved in three separate categories (benefits):

• Lighting ($0.30-0.60 per sq ft)
• $0.30 per square foot = 25% reduction in wattage from (ASHRAE) 90.1 -2001
• $0.60 per square foot = 40% reduction in wattage from (ASHRAE) 90.1 -2001
• HVAC ($0.60 per sq ft)
• Building envelope ($0.60 per sq ft)

Lighting projects typically qualify including LED retrofits.

Effective January 2011, the program was updated allowing a company to deduct the efficiency measures completed from 2006 to the current year on the current year’s tax return. This eliminates the need to re-open previous tax years.

Fall is in the air, and it’s the time of year when commercial rebate and incentive programs are starting to run out of funds after a very busy year. A number of utilities have already exhausted their 2010-11 rebate program funding and most will not receive additional funds until 2012.

The following utilities are currently out of funding for the remainder of the 2011 program year:

• AEP-TX (on wait list status)
• Centerpoint-TX
• DTE Energy & Consumers Energy-MI
• Gas Public Purpose Program Fund-CA for PG&E, SCE, and SDG&E
• Oklahoma Gas & Electric (OGE)
• Oncor-TX
• Public Service of New Hampshire (PSNH)
• NV Energy Retrofit

In addition the utilities listed above, funding for the Connecticut Energy Efficiency Fund is nearly depleted.

If any of your fourth quarter projects are within these utility territories, make sure to call the Incentive Team at Coleman Hines to discuss whether it makes sense to move the project to early 2012 when incentive funds will be replenished.

Perhaps you discover some extra dollars in your capital improvement budget that must be spent by year end or prior to your company’s seasonal “black-out period” for construction. Most utilities stop accepting new applica- tions in November. This means that you should submit your projects to CHI by November 1, 2011, so we can start the application process and get them qualified be- fore the close of the year.

It’s also a great time to take advantage of some of the year-end bonus incentives. Energy Trust (OR), Ameren (IL), Xcel Energy (CO), and Long Island Power (NY) are just a few utilities currently offering bonuses to convert inefficient T12 fluorescent lighting systems. (Due to U.S. Department of Energy (DoE) regulations, the manufac- ture of nearly all T12 fluorescent lighting will be phased out in 2012 and will no longer be available).

Going forward, what role will the taxpayer have in the green energy industry? It’s a topic ripe for discussion considering the recent bankruptcy of Solyndra, the California-based solar cell manufacturer.

In September, Solyndra ended all business activity, laid off its employees and filed for Chapter 11 bankruptcy. Its filing was surprising since the company had the support of a $535 million federal loan guarantee as well as another $198 million from private investors.

Management was quick to blame competition from low-cost manufacturers in China and other economic factors. Though management itself may be partially responsible.

“After we got the loan guarantee, they were just spending money left and right,” said former Solyndra engineer Lindsey Eastburn. “Because we were doing well, nobody cared. Because of that infusion of money, it made people sloppy.”

Either way, taxpayers remain on the hook to repay the loan. But the bankruptcy fuels broader concern about the government’s hand in the green energy industry. Prior to the bankruptcy, Solyndra was President Obama’s highly advertised example of a green jobs future. The White House even scheduled a press event applauding the manufacturer just two days after the half-billion dollar loan was granted final approval in September 2010.

At stake is whether or not the government will continue to act as a venture capitalist for clean-tech companies. When candidate Obama campaigned for the White House, he promised to create 5 million green jobs. To fulfill the goal, his administration expanded the loan guarantee program that was initially established by the Energy Policy Act of 2005. But so far there are just 3,545 new green jobs after disbursing about half of the $38.6 billion available. That amounts to roughly $5 million per job created.

Since Solyndra’s collapse, the White House has been silent about the future of green jobs. This contrasts with President Obama’s initial rapport with the clean energy industry. Within weeks of taking office, President Obama signed a $787 billion stimulus package that included many benefits for clean-tech companies. The signing ceremony itself was symbolic – the bill was signed after touring the Denver Museum of Nature and Science, which has solar panels on its roof, and President Obama was introduced by the head of a local solar company.

Yet the most recent push for more stimulus spending didn’t make any appeal for green jobs or investing in clean energy. In his formal pitch to Congress, President Obama discussed ‘rebuilding America’ by repairing roads and bridges and renovating schools. But the speech delivered in the House Chamber avoided energy investment, renewable or otherwise.

The Obama administration will likely maintain some dis- tance between itself and the clean energy industry as long as Solyndra remains under investigation. If the Solyndra failure involved political cronyism, a concern lawmakers and others have raised, then it could have long term consequences for clean-tech companies that rely on subsidies and other forms of government support.

Just ask Arizona-based First Solar, Inc. The company will not get a $1.9 billion Department of Energy loan guarantee to construct a new solar power plant. The deal had preliminary approval but, according to at least one analyst, fell apart after Solyndra filed for bankruptcy.

How exactly does this affect energy managers? It really depends on the extent of the Solyndra fallout. At a minimum, these types of investments will face more scrutiny. But it could also derail other components of the administration’s agenda that include commercial incentives for energy efficiency. Coleman Hines will continue to follow this issue and communicate any relevant information to its clients.

Current Market Conditions

It’s Déjà vu all over again. This market just keeps going lower. In September, the 12-month strip opened at $4.434/MMBtu and closed at $4.113/MMBtu for a decrease of $0.321/ MMBtu or 7.2%. In addition, the 12-month strip for months 13 through 24 also reached a recent low of $4.701/MMBtu. This replaces the previous low mark of $4.331/MMBtu that was set last month.

The weather forecasts are calling for near normal temperatures and whenever varia- tions have occurred they have been too mi- nor to impact pricing. Although the East coast suffered a major hurricane this season, causing a lot of destruction and loss of life, there has been little activity in the Gulf to disrupt the supply of natural gas from that region. Further, shale gas or fracking, as reported last month, has created a lot of new supply options. BNP Paribus reported that four horizontal wells in the Utica shale regions of eastern Ohio and western Pennsylvania are producing 9.5 MCF/ day compared to an average production of 50 ccf/day from vertical wells in eastern Ohio.

In addition, storage is increasing and begin- ning to gain ground on both last year’s and the five-year average levels. The most re- cent weekly storage report shows the cur- rent storage level is at 3,312 Bcf, trailing last year’s level by only 91 Bcf. That is the closest this year has been to the previous year since this past April. Also, the report reveals that for the first time since April the current year exceeds the 5-year average level which is at 3,307 Bcf.

Increased supply, due to new drilling techniques, and demand destruction, resulting from the economy, appear to be the driving forces. The consequence is dramatically lower prices. Also, storage is becoming less of a concern.

The recent 5.8-magnitude earthquake in Virginia could spark more debate about the safety of US nuclear power plants. The quake was the East Coast’s most powerful in over a century, and it has led some nuclear opponents to draw comparisons to the disaster that happened in Japan earlier this year.

The earthquake caused twelve nuclear plants across six states to declare an “unusual event” – the lowest emer- gency classification – and one other plant, the North Anna Power Station, to declare an “alert” – the second lowest emergency classification.

The two reactors at the North Anna Power Station, located less than 20 miles from the epicenter, were auto- matically shut down after the quake shook relays on three large electrical transformers. Basically, the relays’ open- ing interrupted the electrical circuits that send power to the two reactors’ cooling system. When electricity was cut, the system automatically shut off the reactors.

The North Anna units, operated by Dominion Virginia Power, are actually designed to withstand a 6.2-magnitude earthquake. This may seem like a small variance but it’s actually a significant gap since the magnitude scale is logarithmic. A 6.2-magnitude earthquake is about four times as powerful as the earthquake that happened in Virginia.

After the disaster in Japan, the Obama administration ordered a nuclear safety task force to investigate our current infrastructure and make any recommendations to the Nuclear Regulatory Commission. The report concluded that existing NRC regulations pose no “immediate threat” to public safety and stressed that a disaster similar to Japan’s is highly unlikely in the US.

However, some are skeptical that current standards are strict enough. George Mason University environmental policy professor Allison Macfarlane says that setting reactor design standards slightly above recorded earthquake records is “really shortsighted.”

“We were really close here,” Macfarlane elaborated. “Some would say that’s evidence of us getting it right,

but I would say that we’re really pushing the envelope. With something like a nuclear reactor, I would like a large safety margin.”

The NRC has already announced it will require all nuclear power plant operators to provide an updated review of their earthquake risks. These precautionary steps, according to the agency, will also identify areas where plants can improve their design and reduce seismic vulnerabilities.

Still, others maintain there is little to worry about. Steve Kerekes, spokesman for the Nuclear Energy Institute, says that the response of these facilities is evidence that US nuclear facilities are “well designed and that they are sturdily built.”

What does all this mean for energy managers? It depends on the types of measures, if any, that could be ad- opted by the NRC. There are 104 nuclear power plants in the US and nuclear energy makes up approximately 20 percent of our national energy mix. Tighter regulations or a larger margin of safety, which could be determined necessary, would push up the cost of nuclear power. But the updated reviews are not expected to begin until next year and any potential changes would likely be several years out.

Also, for awareness purposes, electricity prices may rise in the event of a temporary nuclear plant shutdown. If the utility must purchase more expensive power on the market to offset the plant loss, these higher charges could be passed on to the end user. But this all depends on a variety of variables, such as PUC rules and whether or not the customer is on a fixed price contract.