What follows is a discussion in which I will post/share industry related articles that I believe to be of general interest to some who frequent this site.

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Record Snow in South Carolina.

How is that 'Global Warming' working out for you?

HA HA .... Good One, Jack Straw !

Slowly (ever so slowly), the Natural Gas of the Marcellus and Utica is growing legs; and will be able to travel.

Source: http://insidetrade.co/test/insights-on-energy-transfer-equity-lp-ny...

Energy Transfer Equity LP (NYSE:ETE) announced that it has secured additional long-term binding shipper agreements on its Rover natural gas pipeline project to connect Marcellus and Utica shale supplies to markets in the Midwest, Great Lakes and Gulf Coast regions of the United States and Canada. As a result of the additional agreements, the pipeline is fully subscribed through 15 and 20 year fee-based contracts to transport 3.25 billion cubic feet per day (Bcf/d) of capacity.

The approximately 800-mile natural gas pipeline, estimated to cost $3.8 to $4.4 billion, will deliver natural gas from processing plants and interconnections in Northwest West Virginia, Western Pennsylvania and Eastern Ohio to the Midwest Hub near Defiance, Ohio as well as to multiple delivery points in Michigan and to the Union Gas Hub near Sarnia, Ontario. Rover also will interconnect with ETP’s Panhandle Eastern Pipe Line (PEPL), allowing shippers to deliver gas to Gulf Coast markets through ETP’s Trunkline system.

Transportation from the supply regions to the Midwest Hub near Defiance is expected to begin by December 2016 to serve the Gulf Coast and Midwest markets. The remaining service to other markets including Michigan will be in service by mid-2017.

Source: http://www.npr.org/2014/11/05/361420484/new-england-electricity-pri...

New England Electricity Prices Spike As Gas Pipelines Lag

November 05, 2014 3:28 AM ET

fromNHPR


Listen to the Story

3 min 53 sec

When Don Sage of Concord, N.H., learned his electric bill could rise by as much as $40 a month he got flustered. He and his wife make do on a bit less than $30,000 a year in Social Security payments, and they pay close attention to their electric bills.

"When the invoice comes in the mail to get paid, I have a target amount that we can fluctuate up or down, based on our fixed budget," Sage says. "They don't need my permission to hike up their rates, but the fact is we're the ones that are paying these increases."

Utilities in New England have announced electricity rates hikes on the order of 30 percent to 50 percent, making prices some of the highest in the history of the continental United States.

For Sage and other consumers, these changes seem to have come out of nowhere, but in reality, they have been a long time coming. Between the years of 2000 and 2013, New England went from getting 15 percent of its energy from natural gas to 46 percent. That's dozens of power plants getting built.

But the pipelines to supply those power plants? Not so much.


At the same time, with the fracking boom just a few hundred miles west driving down gas prices, more and more homeowners were switching to natural gas for heating.

So now when it gets cold and everyone turns on their heat, the pipelines connecting New England to the Marcellus Shale are maxed out.

Power plant operators are left to bid on the little bit of gas that's left over for them, and the prices can get out of hand.

"In New England, this winter, based on what's been recently trading, is likely to have the highest natural gas prices on planet Earth," says Taff Tschamler, chief operating officer of energy supplier North American Power.

Gas for January delivery is trading at nearly $19 per million BTUs. Gas in Japan, which relies entirely on imported gas and often has the world's highest prices, is forecast to cost less than $18 this winter.

Big pipelines in New England are on the drawing board, but they won't be built until 2018 at the earliest — and that's only if they don't get swamped by local opposition.

One proposed solution for New England's energy price spike problem: Importing more liquefied natural gas and feeding it into the pipeline network on the other side of the region's bottleneck.

One proposed solution for New England's energy price spike problem: Importing more liquefied natural gas and feeding it into the pipeline network on the other side of the region's bottleneck.

One proposed solution for New England's energy price spike problem: Importing more liquefied natural gas and feeding it into the pipeline network on the other side of the region's bottleneck.

Sam Evans-Brown/New Hampshire Public Radio

How To Cope

So what's a region to do? For one, if you import gas and plug it into the pipeline network at a different spot, you can avoid the bottleneck.

Distrigas, New England's only liquefied natural gas import terminal, is just north of Boston. Tony Scaraggi, the company's vice president of operations, says even with last year's frigid winter, New England only hit its maximum pipeline capacity for 40 days.

"That's equivalent to like, two and a half to three LNG tankers coming in. So you gotta compare that to the cost of a $2 to $3 billion pipeline," Scaraggi says.

He says burning more expensive foreign natural gas for those 40 days is still cheaper than building an oversized pipeline.

The environmental community is weighing in on the question, too.

Peter Shattuck with Environment Northeast put out a paper arguing the region could save money by using less power.


"If demand for gas remains low, because of things like energy efficiency, distributed generation, renewable heating technologies like heat pumps and biomass, we may not need any infrastructure overall," Shattuck says.

So while it's certain that some pipelines will get built, the big question is how much additional capacity, and who will pay.

A plan from the six New England governors to subsidize bigger pipes was tabled recently when Massachusetts announced it wanted to study the question further before committing.

Ultimately, whether electricity prices continue to rise in New England next winter and the winter after that will come down to weather.

"At any rate, what I think we're hoping for is that the good Lord who protects drunks and the United States will also protect New England," says Peter Brown, an energy attorney with the law firm Preti Flaherty.

In other words, pray for a warm winter.

Source: http://www.rgj.com/story/news/2014/06/14/fact-checker-fracking-use-...


Fact Checker: Does fracking use a lot, a little water?
Mark Robison, RGJ 10:59 a.m. PDT June 16, 2014

The claims

• Fracking uses tens of millions of gallons of water per well.

• In 2013, fracking in California used less water than the amount needed to keep a golf course green for a year.

The background

In April, the Reno Gazette-Journal's Jeff DeLong reported fracking has begun for the first time in Nevada.

Since then, the RGJ has published two opposite claims about fracking water usage — one says it uses enormous amounts while the other says relatively little is used.

Fracking is a method of creating cracks deep underground to give access to previously inaccessible deposits of oil and natural gas. Water is the main ingredient in fracking, also called hydraulic fracturing.

Carl Harris of Reno wrote in a letter to the editor: "The people of Nevada are about to find out what the residents of Pennsylvania learned the hard way, that fracking uses tens of millions of gallons of water per well …"

A 2011 report by the Environmental Protection Agency looked into this. It cites three studies published between 2008 and 2010 and concludes: "2 to 4 million gallons of water are typically needed per well."

Even the Center for Biological Diversity, which is fighting fracking in Nevada, said in a June 12 press release, "A typical hydraulic fracturing process uses between 1.2 and 3.5 million gallons of water per well, with large projects using up to 5 million gallons."

Meanwhile, Catherine Reheis-Boyd, president of the Western States Petroleum Association, wrote an opinion piece for the RGJ that said: "All hydraulic fracturing in 2013 in California used less water than the amount needed to keep a golf course green for a year."

California used 320 acre feet — or 104 million gallons — of water for all fracking last year. That's what Tupper Hull told Fact Checker. He is vice president for strategic communications at the Western States Petroleum Association.

For another assessment, Ceres — a nonprofit organization that works on climate change and water sustainability issues — put out a report last year that 113 million gallons of water were used for fracking in California over the 17 months ending May 31, 2013.

Now for the golf angle. Reheis-Boyd compared all of California's fracking water usage last year to that used annually by "a golf course." She didn't say where or how much water.

A 2013 factsheet by her group says: "353,000 gallons — amount of water needed to irrigate a golf course in a single day."

This works out to 129 million gallons a year.

If correct, she's right.

The statistic comes from the October 2005 issue of Golf Course Management. It refers to one of three "hypothetical" golf courses, this one in a southern marine climate.

It's the least water-intensive of the three — and yet this fictional course still used more water than was used for all California fracking last year.

But what if real courses were used. Nationally, a 2009 report on water use by the Golf Course Superintendents Association of America says, "Using water use data nationally, an 18-hole golf course uses an average of 152.5 acre-feet of water per year …"

That works out to 49.7 million gallons a year.

A factsheet by that same group says golf courses in the "Upper Mountain/West" region — including parts of Northern California and all of Nevada except Las Vegas — use 97.9 million gallons of water every year. (In the Reno area, golf courses reclaim their water.)

Reheis-Boyd's organization is based in Sacramento. A Sacramento Bee story earlier this year — using United States Golf Association data for California — estimated the average course there uses 81.5 million gallons a year.

And an RGJ story earlier this year reported that the Martis Camp golf course in Truckee uses 45 to 50 million gallons a year.

In all four of these real-world examples, fracking in California used more water than the golf courses in a year.

California, though, is atypical — fracking there uses small amounts of water. For example, a cluster of fracking wells in the Sacramento Valley used only 10,000 to 35,000 gallons each, according to an SFGate.com story.

That story continues: "In California, most fracking has involved vertical wells. Vertical wells have less pipe length than horizontal wells of equal depth, because they don't veer off sideways at the bottom. They therefore require less water for fracking. …

"In addition, most fracking in California is for oil, not natural gas. And the oil typically resides in rock formations that contain large amounts of brackish water," (said Tim Kustic of the Division of Oil, Gas, and Geothermal Resources). Since the pores within the rock are already full of liquid, drillers don't need to add much to increase the pressure."

The story notes that in Pennsylvania, fracking wells often take 4.5 million gallons of water while Texas fracking wells take 6 million gallons.

Finally, it's worth mentioning that a golf course superintendents' report estimates total annual water usage by U.S. golf courses at 762 billion gallons a year. And a 2011 EPA report put total annual water usage for fracking at 70 to 140 billion gallons.

The verdict #1

The claim that fracking uses "tens of millions of gallons of water per well" isn't true — 2 to 4 million gallons per well is more accurate.

Truth meter: 1 (out of 10)

The verdict #2

The claim that all fracking in California last year used less water than a golf course is based on a fictional course that uses more than typical water.

Even in cases where courses use more, the claim is still misleading because California's geology requires so much less water for fracking than in other places.

On the other hand, the overall point that golf is more water intensive is correct.

Truth meter: 4 (out of 10)

P.S. For comparison, the Nevada Department of Agriculture reports Nevada's 66,000 dairy cows use 429 million gallons of water a year while a 126-acre crop with a single irrigation pivot uses 163 million gallons — both more than all of California's fracking projects.
Believe it or not, they have created "hybrid" Wind/Natural Gas turbines.
When the wind doesn't blow (70% of the time) ... these apparent wind turbines spin while powered by natural gas ..... do these run efficiently when powered by natural gas ... well no! When you look up at these under calm wind-less skies, they continue to wildly spin (natural gas powered).

If they are inefficient, how is it economically feasible to do this?
Somehow, I bet many of you have guessed the answer .... they are economic because of (involuntary taxpayer provided) government subsidies!

When the wind doesn't blow, our government 'suck starts' the turbines.
Isn't wind power wonderful ... no I do not mean the wind provided by Mother Nature, I am referring to all the hot air coming out of Washington, D.C.

JS

Source: http://adventuresportsjournal.com/blogs/earth-talk/from-the-editors...


Gas-Powered Motors on Wind Turbines?


Some wind energy companies have developed back-up systems that can spin turbines even when the wind isn't blowing, thus optimizing and keeping consistent the power output. Colorado-based Hybrid Turbines Inc., for example, makes systems that marry a natural gas-based generator to a wind turbine. Even with that fossil fuel usage, the electricity produced is much cleaner than burning coal. (Jorge Lascar, courtesy Flickr)

I heard that some wind farms use fossil fuels to power their generators when the wind won’t. Doesn’t that defeat their whole renewable energy purpose? Why not let the wind power it or not? Also, I’ve heard that the low-frequency sounds generated by these turbines can harm people and animals. Is this true?
– Ryan Lewis, Plainwell, MI

Indeed, one of the major drawbacks to wind power is the fact that, even in windy locations, the wind doesn’t always blow. So the ability of turbines to generate power is intermittent at best. Many turbines can generate power only about 30 percent of the time, thanks to the inconsistency of their feedstock.

In order to overcome this Achilles’ heel of intermittent production, some wind companies have developed back-up systems that can spin turbines even when the wind isn’t blowing, thus optimizing and keeping consistent the power output. For example, Colorado-based Hybrid Turbines Inc. is selling wind farms systems that marry a natural gas-based generator to a wind turbine. “Even if natural gas is used, the electricity produced…is twice as environmentally clean as burning coal,” reports the company. Better yet, if a user can power them with plant-derived biofuels, they can remain 100 percent renewable energy-based.

While some wind energy companies may want to invest in such technologies to wring the most production out of their big investments, utilities aren’t likely to suffer much from the intermittent output if they don’t. Even the utilities that are most bullish on wind power still generate most of their electricity from other more traditional sources at the present time. So, when wind energy output decreases, utilities simply draw more power from other sources—such as solar arrays, hydroelectric dams, nuclear reactors and coal-fired power plants—to maintain consistent electrical service. As such, reports the American Wind Energy Association, utilities act as “system operators” drawing power from where it’s available and dispatching it to where it is needed in tune with rising and falling power needs.

But just because generating wind power all day long isn’t imperative doesn’t mean that suppliers aren’t doing all they can to maximize output. To wit, turbine manufacturers are beginning to incorporate so-called Active Flow Control (AFC) technology, which delays the occurrence of partial or complete stalls when the wind dies down, and also enables start-up and power generation at lower wind speeds than conventional turbines. The non-profit Union of Concerned Scientists lauds AFC for these capabilities, which in turn can help system operators create a more reliable electric grid less dependent on fossil fuels.

As to whether or not noise from wind farms can harm people and wildlife, the jury is still out. New York-based pediatrician Nina Pierpont argues in her book, Wind Turbine Syndrome, that turbines may produce sounds that can affect the mood of people nearby or cause physiological problems like insomnia, vertigo, headaches and nausea. On the flip side, Renewable UK, a British wind energy trade group, says that the noise measured 1,000 feet away from a wind farm is less than that of normal road traffic. Here in the U.S., a Texas jury denied a 2006 noise pollution suit against FPL Energy after FPL showed that noise readings from its wind farm maxed out at 44 decibels, roughly the same generated by a 10 mile-per-hour wind.

CONTACTS: Hybrid Turbines, Inc., www.hybridturbines.com; American Wind Energy Association, www.awea.org; Union of Concerned Scientists, www.ucsusa.org; Nina Pierpont’s Wind Turbine Syndrome, www.windturbinesyndrome.com.

EarthTalk® is written and edited by Roddy Scheer and Doug Moss and is a registered trademark of E – The Environmental Magazine (www.emagazine.com). Send questions to: earthtalk@emagazine.com. Subscribe: www.emagazine.com/subscribe. Free Trial Issue: www.emagazine.com/trial
Interesting as always. Thanks for sharing Jack.

WOW !    So Interesting !   Thanks Jack Straw.

Source: http://www.reuters.com/article/2014/11/10/oil-atlantic-basin-refini...

More info. on Hovensa St. Croix Refinery


UPDATE 1-Atlantic Basin Refining to buy, restart Hovensa St. Croix Refinery

Mon Nov 10, 2014 12:03pm EST

Deals of the day- Mergers and acquisitions
Atlantic Basin Refining to buy, restart Hovensa St. Croix Refinery
As oil price falls, funds looks to pipelines and refineries
Exclusive: Potential buyers checking out two Citgo refineries - sources
UPDATE 2-U.S. refiner HollyFrontier's profit misses as costs rise

Nov 10 (Reuters) - A little-known entity, Atlantic Basin Refining, has agreed to buy the shuttered Hovensa LLC oil refinery in St. Croix and restart it with a 300,000 barrels-a-day capacity to handle crude from the U.S. shale boom, according to a statement on Monday.

The project's managing partners are Robert B. Moore Jr., Jack Thomas, William D. Forster, and Steven D. Schmitz, executives with trading and refining experience, according to biographies provided by the company to Reuters.

The agreement between ABR and plant owners Hess Corp and Petroleos de Venezuela (PDVSA) is subject to a vote by the Legislature of the U.S. Virgin Islands, scheduled for Nov. 12.

The details of the agreement and information on the project's financial backers remain well-guarded.

The company's managing partners have decades of experience in the energy business, according to information provided by the company. Moore was previously a trader and manager at companies including Sun Oil Trading Co, Marubeni Inc, Castle Oil Corp, and Reliant Energy. Thomas is a senior partner in the St. Croix Renaissance group, which redeveloped the former Alcoa facility adjacent to the Hovensa refinery, with experience in environmental mitigation. Forster is an investment banker with 16 years at Lehman Brothers and 23 years working independently. Schmitz managed U.S. business development activities for Glencore and was a member of the refinery acquisition teams for PBF, Tosco and Hill.

Their plan focuses on upgrading the refinery, once the largest plant in the Western Hemisphere, which processed heavy Venezuelan crude before its January 2012 closure, to refine light sweet crude of the kind produced in shale formations, the statement said.

"The U.S. shale revolution has created an abundant supply of U.S. light sweet crude, and there is currently a limited ability to process this type of feedstock at U.S. refineries," said Mark W. Eckard, Atlantic Basin's managing director for legal and governmental affairs.

The shale boom has enabled other East Coast refineries that were shuttered for underperformance to restart.

The reconfiguration and restart will take approximately 24 months, according to the company's website. ABR plans to restart the refinery with partners including Samsung Engineering, Wyatt Field Service Co., and an affiliate of SunExcel.

The company's website does not address how much the restart will cost or where the financial backing will come from. The company declined to immediately comment on the financing. (Reporting by Jessica Resnick-Ault; Editing by Alden Bentley and James Dalgleish)

Source: http://www.newsobserver.com/2014/11/11/4313413/dominion-sends-lette...

Dominion sends letters to NC land owners who won't cooperate on gas pipeline

jmurawski@newsobserver.comNovember 11, 2014 Updated 6 hours ago

Dominion-Blue Racer just called me to ask permission to survey my land in Guernsey county, Millwood twp. OH 

Source:

http://www.bloomberg.com/news/2014-11-21/the-153-year-old-oil-well-...

The 153-Year-Old Oil Well That Hasn't Stopped Pumping Yet

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