(Photo by Damian Gadal via Creative Commons)
In deregulated Midwestern states, many residential customers and whole towns and cities – through municipal aggregation – are now able to choose an electricity supplier other than their utility.
Shopping around for an alternative natural gas supplier, however, is much less common, and many customers likely don’t know they have the option to switch gas suppliers even years after deregulation laws made it possible.
Alternative gas suppliers and energy marketplace companies – like ChooseEnergy, which launched its residential natural gas switching services in Illinois and Ohio recently – say that consumers can save money by shopping around for a gas plan.
Some consumer advocates and energy experts, meanwhile, say that differences between the gas and electricity sectors mean that customers have much less to gain by switching to an alternative gas supplier. In fact an analysis by the Citizens Utility Board (CUB) in Illinois shows that a great majority – 88 percent – of customers have actually lost money by switching natural gas plans.
(Photo by Michael Krigsman via Creative Commons)
After a three-year pilot program that won praise from state officials and environmental groups, Minnesota’s largest natural gas utility is proposing to walk away from a concept known as revenue decoupling.
CenterPoint Energy, which is in the midst of a contested rate case, said in a Jan. 31 regulatory filing that it will no longer seek approval for a permanent decoupling mechanism it proposed last summer.
That proposal faced opposition from the Minnesota Attorney General’s Office, which argued that it would confuse customers and shift too many costs and risks onto residential and small business ratepayers.
Michael Vickerman is program and policy director of RENEW Wisconsin.
By Michael Vickerman
As this latest blast of arctic air slides away from the Upper Midwest, now is a good time to take stock of the conventional wisdom that grips natural gas markets today.
The Energy Information Administration (EIA) last week reported another large weekly withdrawal of natural gas–230 billion cubic feet (bcf)–from underground inventories. While this is a big number, it is well short of the record-setting 287 bcf withdrawal reported two weeks earlier. This week’s report may eclipse that number.
The heavy demand for natural gas this winter leaves inventories at their lowest levels for this time of year since 2004. Even if temperatures returned to normal this February and March, we could finish the heating season with only one-third the volume in storage back in early November.
In fact, we’re on track to pull 26 trillion cubic feet (tcf) out of storage this heating season, a volume likely to exceed all the natural gas extracted from domestic sources last year (an estimated 25.5 trillion cubic feet).
Remember the extraordinary surplus that accumulated in the winter of 2011-2012? It’s ancient history now. Without a moment’s thought to what was happening, we managed to Hoover through every last cubic foot of ballooning inventories that in 2012 sent gas prices plunging down to levels not seen since 2002. One month into 2014, the pendulum has clearly swung over to the deficit side of the supply-demand equilibrium.
GE’s natural-gas-fueled oil field engines are manufactured in Waukesha, Wisconsin. (Photo via GE)
In remote and rugged areas from the Great Plains to Appalachia, drilling and hydraulic fracturing is typically powered by diesel fuel rather than electricity from the grid like more established drilling operations.
But companies are increasingly using natural gas or a mixture of natural gas and diesel, meaning significantly lower emissions and lower costs for hydraulic fracturing and enhanced oil recovery – getting the last remnants of oil out of tapped-out wells.
In Pennsylvania, the switch to powering with natural gas fracked onsite has been described as a “triple threat” reducing emissions, costs and truck traffic. And earlier this year Texas-based Apache Corp. announced plans to become the country’s first fracking operation powered entirely by natural gas, projecting a 40 percent savings on fuel costs.
Last week at the High Horsepower Summit in Chicago — a conference aimed at promoting natural gas use in mining, maritime, oil and other industries — GE Power & Water touted the recent Environmental Protection Agency certification of natural gas engines from their Waukesha, Wisconsin, plant for “mobile, non-road uses” including oil and gas extraction.
Natural gas flaring in McKenzie County, North Dakota. (Photo by Tim Evanson via Creative Commons)
©2013 E&E Publishing, LLC
Republished with permission
By Mike Lee
The amount of natural gas being burned away at oil wells in North Dakota rose the most in more than a year in July, and state officials now say it may take new regulations to tackle the problem.
Oil and gas producers burned, or flared, 30 percent of the gas produced at wells in the Bakken formation, up from 28 percent in June, according to figures released Friday by the North Dakota Oil and Gas Division. That’s below the high of 36 percent in September 2011 but far above the state’s historical average.
The rise was the biggest percentage-point increase since April 2012, when it rose to 34 percent from 32 percent in the previous month.
North Dakota has relied on private companies to find ways to reduce the amount of flaring. However, the state recently did some modeling that shows the level of flaring won’t fall below 5 percent until after 2020, state Mineral Resources Director Lynn Helms said on a webcast with reporters.
Construction of a new natural gas power plant in Oregon. (Photo by PGE via Creative Commons)
©2013 E&E Publishing, LLC
Republished with permission
By Daniel Cusick
The unprecedented boom in natural gas production from places like Pennsylvania, New York and Ohio should make those densely populated regions self-sufficient in gas production by 2020, which in turn could encourage more electric utility fuel switching, according to two top energy sector analysts with Navigant Research.
But utilities will still face a difficult set of questions when charting the future of power generation, including whether to invest billions of dollars in environmental controls at existing power plants, replace aging coal-fired units with cleaner-burning natural gas generators or meet future electricity demand using other technologies.
A fundamental question underscoring all of these decisions, according to Rick Smead, a director for Navigant’s energy practice, is whether the gas boom, now in its fifth year, will continue into the middle and latter half of the decade, when a series of new federal regulations targeting coal plant pollutants comes into full force.
“If you can’t build any new coal plants, that tends to work in favor of gas,” said Smead, who specializes in upstream and midstream natural gas issues at Navigant’s Houston office.
An artist’s rendering of Boeing’s “SUGAR Freeze” LNG-fueled aircraft concept. (Image via Boeing)
©2013 E&E Publishing, LLC
Republished with permission
By Blake Sobczak
Ever since he was 6 years old, Jon Gibbs has been fascinated with aircraft.
But while toy planes seemed pretty cool to him as a kid, Gibbs now thinks he’s onto something more significant, and literally cooler: cryogenic aircraft fueled by liquefied natural gas.
Unlike conventional, oil-based jet fuel, super-cooled LNG is condensed from simple methane gas and sells for a fraction of the price.
Gibbs thinks the cleaner-burning fuel could be the biggest innovation to hit aviation since the development of the jet engine more than a half-century ago. And the aircraft designer, former Boeing employee and recent Massachusetts Institute of Technology graduate hopes he can lead an industry shift toward LNG through his new company.
A drilling rig in the Marcellus Shale. (Photo by Penn State News via Creative Commons)
Republished from ProPublica via Creative Commons
By Abrahm Lustgarten
Don Feusner ran dairy cattle on his 370-acre slice of northern Pennsylvania until he could no longer turn a profit by farming. Then, at age 60, he sold all but a few Angus and aimed for a comfortable retirement on money from drilling his land for natural gas instead.
It seemed promising. Two wells drilled on his lease hit as sweet a spot as the Marcellus shale could offer – tens of millions of cubic feet of natural gas gushed forth. Last December, he received a check for $8,506 for a month’s share of the gas.
Then one day in April, Feusner ripped open his royalty envelope to find that while his wells were still producing the same amount of gas, the gusher of cash had slowed. His eyes cascaded down the page to his monthly balance at the bottom: $1,690.
Chesapeake Energy, the company that drilled his wells, was withholding almost 90 percent of Feusner’s share of the income to cover unspecified “gathering” expenses and it wasn’t explaining why.
“They said you’re going to be a millionaire in a couple of years, but none of that has happened,” Feusner said. “I guess we’re expected to just take whatever they want to give us.”
(Photo by Kate Ausburn via Creative Commons)
As the population grows, the economy improves and the climate warms in its service territory, Xcel Energy projects rising demand for electricity on hot summer days before the end of the decade.
On April 15, the Minnesota utility proposed meeting that new peak demand by building three 215-megawatt natural gas power plants — one in the Twin Cities and another two in North Dakota.
Six weeks later, though, Xcel and other investor-owned utilities in Minnesota were presented with a new legislative mandate to generate 1.5 percent of their electricity from solar by 2020.
The state’s new solar standard is expected to spur development of an estimated 450 megawatts of solar power over the next six and a half years, which raises the question: does Xcel still need all three of those gas peaking plants?
Todd Foley is the Senior VP of Policy and Government Relations for the American Council On Renewable Energy, based in Washington D.C.
By Todd Foley
The American entrepreneurial spirit is an incredibly strong force in the domestic and global marketplace. And when markets allow businesses – small and large – to compete, grow, and innovate on an equal and fair playing field, all Americans benefit.
Since 1987, many conventional energy sources have taken advantage of Master Limited Partnerships (MLPs), a business structure that is traded like a corporate stock but is taxed as a partnership, avoiding double taxation. However, renewables have been excluded from utilizing the MLP market that exceeds $400 billion in capital investments.
It’s time to allow renewable energy access to this important market tool, which has spurred tremendous investment in the nation’s energy infrastructure.
It is true there is a serious need for renewable energy policies at the federal and state levels that create long-term market certainty, boost distributed generation, and spur the growth of all renewables. The existing tax credits and CLEAN contracts, or feed-in tariffs, have been successful and remain vitally important. But that hardly means MLPs are a “lousy policy for renewables,” as John Farrell wrote in a May 31 commentary published on Midwest Energy News.