In George Jetson’s world, Light Emitting Diodes (LED) are nothing new. Earlier light sources are only found in his kids’ history e-books. Back here in the 21st century, however, not all LEDs are Jetson-ready. While we are rapidly replacing fluorescent and incandescent lamps, and even some high intensity discharge (HID) lamps, care is needed when specifying LEDs for existing fixtures.

Rosie, the Jetsons’ robot maid, keeps the home clean and running like clockwork, all on renewable energy. But will she slow down if the wind stops blowing, or if clouds block the sun?

Many megawatts (MW) of wind and solar power are being added to grids across the U.S. While routinely intermittent until recently they represented such a small part of the system that their variability was inconsequential. That has begun to change.

Rather than buying a solar power system, many commercial customers purchase just the power they produce by using a Power Purchase Agreement (PPA). Like retail power contracts, PPAs (which may run for 20 years) need to be reviewed by an experienced consultant, as well as an attorney before it is accepted by a customer. In a subsequent article, we will discuss the technical issues involved with solar projects, but for now, we will focus on the financial and commercial terms of an agreement.

Technical issues may compromise the value of an on-site photovoltaic (PV) system. Reduced output, PV outages, or electrical problems may leave a host wondering if the decision to go solar was wise.

One way to minimize this risk is to consider a Power Purchase Agreement (PPA), in which a developer owns, installs, and operates the equipment, so all such issues should be his/her responsibility. If the system goes down, the developer loses electricity sales. That is a good incentive to ensure a quality installation, and most PPA-based systems have a decent track record.

Several recent legal challenges related to Demand Response (DR) may have a long-term impact on Demand Response programs, including how Demand Response participants get paid, and by whom.

The issues involve two separate cases about how energy and capacity are treated in DR programs. In one case, grid operators and power plants followed the Federal Energy Regulatory Commission’s (FERC) Order 745 for three years until it was challenged in the Pennsylvania, New Jersey, and Maryland Regional Transmission Organization (PJM RTO) market by a group of power producers. Order 745 sets the value of DR payments in energy markets to equal the hourly wholesale Locational Marginal Price (LMP) in effect at the time of demand reduction. This mechanism trims demand from the generators at times when hourly pricing is highest thereby cutting into their revenue during these high-priced periods.

As control of the U.S. Senate changes hands and Republicans begin chairing its committees, what changes in energy policy may we expect?

At about the same time the Senate majority switched parties, the last legal battle surrounding the Keystone XL Pipeline was settled in a Nebraska court. That set the stage for the first Congressional energy battle of the 114^th Congress. How that battle shakes out will also inform debates on fracking regulations and exporting of oil and natural gas. Such decisions may also impact the president’s position on using energy as a foreign policy tool. A recent example of this is the impact of lower energy prices combined with trade sanctions on both Russia and Iran’s economies. Do the recent advantages in foreign policy impact energy and environmental decisions put both parties on the same side of some of these issues? The Senate majority is too thin to overcome presidential vetoes, so probably not.

In March 2014, NYSERDA and Con Edison kicked off a very generous, but short-term, program to cut 125 MW off the utility’s summer peak demand. Unlike most existing energy-related incentive programs focused on reducing energy use i.e., kWh, the Demand Management Program (DMP) only rewards kW reductions. Also, it only applies if those reductions are both permanent and occur between 2:00 PM and 6:00 PM on weekdays between June 1 and September 30.

If there’s one constant in the energy business, it’s that things are always changing: Only 6 years ago, who would have thought that the average price of natural gas would drop by about 67%? Remember when some people thought the U.S. was running out of oil – until new extraction techniques reversed that Doomsday scenario? Or when everybody said, “you can’t economically store electricity,” and now battery prices are beginning to plunge?

Last winter saw some of the widest spreads for power pricing ever to occur in the Northeast. Some customers saw monthly bills double or triple, relative to the same month in prior years. What happened, and could it happen again?

Several factors influence hourly and daily power pricing, including the wholesale price of fuels, outage of a power plant or transmission line, or a sudden jump in power demand. Last winter, we experienced a lot of the first, some of the second, and a chunk of the third. The largest impact was the huge jump in the local price of natural gas, which supplies, on average, over 60% of power in the NYC region. The wholesale price of gas at the Henry Hub in Louisiana increased from a norm of about $4 a dekatherm (dTH) to over $7 on several days. The local price for Transco Zone 6 for New York City pushed that up to over $30 a day most of the time and more than $120 on a few occasions.  When natural gas is traded, the difference between the Henry Hub price and a specific location for delivery is called basis.

Recent regulations by the US Environmental Protection Agency (EPA) are causing some coal-fired power plants to shut down, either permanently or for extended periods for retrofits. Dire predictions are being heard about how that could cause wholesale and eventually retail power pricing to rise by 30%. Could that affect local electric bills?