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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Is this going to influence jefferson cty. Pa?

What we essentially have are a series of 'Hubs'; Leidy Hub being one.

Like a good hub, there are 'spokes' in and 'spokes' out; the more spokes the better.

What I feel we need are more interconnects  between the various hubs; to reduce the disparities in pricing .... to reduce surpluses at some hubs and scarcities at others (particularly in February). 

With respect to Jefferson County; the more easily natural gas can find multiple potential markets, the better .... Williams proposed pipeline (when/if completed) will help.

But, Jefferson County, PA is DRY GAS; there is a surplus of DRY GAS ... the market for DRY GAS is weak. Most rigs have moved from DRY GAS areas to the Wet Gas and Oily areas; or the DRY Gas areas that have been shown to be the most prolific.

IMHO, the rigs will return to Jefferson County, PA when natural gas sells at the Leidy Hub for $6/mcf (and does so for an extended period of time).

Today (on the spot market0 Natural Gas sold at the Leidy Hub for an average daily price of $2.3356.  

At $2.3356, Jefferson Count looks like Cow Pasture .... watch out, try not to step in any cow pies.

JS

Got it! But if exports run up ng prices and more markets in the n east open up dry gas may rise again. As far as stepping on cow poop in ground hog paradise, $750 an acre for surface and unleased land with marketable timber tempts me to step out of the utica a little. Nevertheless I enjoy your picks.

Ron,

RE: "$750 an acre for surface and unleased land with marketable timber"

That is ground hog heaven.

If you pick up the property (and there is a significant percentage of marketable timber), the timber alone should bring over $750/acre; I have the name of a person with the ability to handle all the details of marketing the timber.

He will mark the timber that is ready for harvest (selective cutting), prepare and send out bid tenders, interface with potential bidders, evaluate the bids for YOUR decision, police the cutting (such that only the marked trees are harvested), and make sure that there is cleanup. With luck, it can be timbered again in 15 years. All for necessary expenses and a nominal percentage. 

He is knowledgeable, experienced, totally honest, a Jefferson County native and life long resident.   

He has personally managed three timber sales for members of my family.

JS 

I'm in! I figured you were a local. Did I figure correctly? Pm me and let's work offline on this. Or call my country store 330 707 9688 thanks again jack.

OBTW, today spot gas traded at an average of $4.2412 at Algonquin Citygates hub (with a daily high price of $4.50).  Chicago Citygates .... $3.9994.

A not altogether rhetorical question: Would you rather drill wells that sold their gas at Leidy .... or would you rather get almost twice as much money/mcf by drilling wells that supply Algonquin Citygates?

If your cost of producing natural gas were $3.00/mcf .... would you rather sell it for a $0.67 LOSS at Leidy .... or would you rather sell it for a profit of $1.24/mcf at Algonquin Citygates?

JS

Too technical for me. Hopefully the deal I mentioned , the timber should get me close to even. Land averages ar 2k an acre there, the minerals might surprise us. Wonder what bonuses are out there if any?

Snyder Brothers Drilling have been soliciting LEASED mineral rights in Jefferson and Indiana County. initially offering $500/acre ... upped to $1000/acre .... and that is for 12 1/2 % Royalty interests.

I know this to be a fact.

JS

Please note that my pessimism is relative to the short term.

With regards Dry Gas, I am optimistic in the long term.

I define the 'long term' as 2016 and beyond,

JS

Thank you Jack Straw !   You are an AMAZING source of information !   God Bless you .....

Source: http://powersource.post-gazette.com/powersource/companies-powersour...

Pipelines in the works

Planning, permitting process under way to get more shale gas to New England


New England wants more natural gas to heat its homes and feed its power plants, and the region is looking southwest to its neighbor in the Marcellus Shale to fill that demand.

The region’‍‍s appetite for fuel was thrown into stark relief this past winter, when frigid weeks marked by storms and polar vortexes drove temperatures down and natural gas prices up.

Part of the problem is that the existing pipelines are already pretty full. Several pipeline projects are on the table to take more shale gas from the Marcellus and other shale plays to the region.

“Gas-fired power plants in the east had to compete for an increasingly limited amount of available pipeline capacity from a system that was already constrained, particularly in New England and New York,” the U.S. Energy Information Administration said in a report on Jan. 9.

About a year ago, representatives from each New England state got together to address “the hole-in-the-doughnut problem,” according to Tom Welch, chairman of Maine Public Utilities Commission.

“New England is surrounded by some very attractive renewable energy in the north and natural gas from the Marcellus in the southwest,” said Mr. Welch, who also serves as a manager of the New England States Committee on Electricity, an organization representing the six New England states on regional electricity matters. The organization plans to put out a formal request for energy infrastructure proposals in the near future, according to Mr. Welch.

The group is working out how much natural gas capacity is needed, but Mr. Welch estimates it will be about 1 billion cubic feet above current capacity. The group said it is also looking at adding new electric transmission infrastructure and other measures to make power generation and heating more reliable.

“Some have suggested that it needs to be 2 Bcf/d and others say nothing,” Mr. Welch said.

Energy prices spiked significantly in New York and New England this past winter.

According to ISO New England, the organization responsible for overseeing the wholesale electricity industry in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont, gas prices averaged $19.33 per million cubic feet (MMcf) during December, January and February at the Algonquin pipeline delivery point in Massachusetts — almost double the year-ago average price of $11.28/MMcf.

“In January, the average natural gas price rose to $24.19/MMcf at the Algonquin delivery point, the highest average price in more than 10 years,” the ISO NE said in a report issued in April. “The daily gas price spiked to a high of more than $78/MMcf on a day in January.”

When natural gas wasn’t available, power plants turned to oil and coal to make up the difference.

“We’re burning dirty fuel because we can’t get access to natural gas,” Mr. Welch said.

More than half of New England’s power is generated by natural gas power plants, in addition to its use as a heat source, according to ISO NE. Low gas prices and tougher environmental regulations have prompted more power generators to switch from coal and oil to gas.

 

Projects on the table

 

One pipeline expansion project proposed by Houston-based Kinder Morgan, the largest midstream company in North America, is called the Tennessee Gas Pipeline Northeast Energy Direct Project.

The expansion would include upgrading the company’‍s existing system in Pennsylvania and in New York, Massachusetts, New Hampshire and Connecticut. One section of the project would link the the dry gas region of the Marcellus in northeastern to Wright, N.Y. and then link Wright to Dracut, Mass.

The company is still in negotiations with customers and shippers.

“It will be very significant in terms of size and scope,” said spokesman Richard Wheatley. If the Federal Energy Regulatory Commission approves, the project could be in service by November 2018.

“Depending on customer capacity commitments, the pipeline could be as little of 600 MMcf/d or up to 2.2 bcf/d,” Mr. Wheatley said.

Meanwhile, Houston-based pipeline giant Spectra Energy this month announced new plans to expand natural gas pipeline capacity on its Algonquin and Maritimes systems addition to other projects the company already under way.

The announcement was made to anticipate New England States Committee on Electricity‘‍s request for proposals for new energy infrastructure.

Spectra said it can add up to 1 billion cubic feet per day (Bcf/d) by expanding the Algonquin system, which runs from New Jersey to Massachusetts after connecting to the 9,200-mile interstate pipeline Texas Eastern Transmission. Algonquin then links up with Maritimes, which runs from Massachusetts to Nova Scotia.

“With Algonquin and Maritimes, we serve about 60 percent of the New England gas-fired generators currently,” said Richard Kruse, vice president, rate regulatory affairs and chief compliance officer for Spectra.

“Our biggest suggestion is, based on our footprint, we’re already connected to gas-fired generation, and we can expand along existing rights-of-way in a scalable fashion,” Mr. Kruse said. “If they want 1 Bcf, we can do that. If they want something smaller, we can do that, too.”

Meanwhile, Spectra is already working on two other projects that are closer to completion: the Algonquin Incremental Market and Atlantic Bridge projects that mean to take shale gas to New England.

The Algonquin Incremental Market, which is expected to go into service in November 2016 would be located in New York, Connecticut, Rhode Island and Massachusetts and provide 342,000 Mcf/d. The Atlantic Bridge project is expected to go into service in November 2017 and add up to 600,000 Mcf/d.

Diana Oswald, energy analyst for Bentek Energy in Denver, noted that the first project to go into service is Spectra’s Algonquin Incremental Market project in 2016 , which means there will be little relief this upcoming winter.

“What we saw this winter may be repeated again this winter,” Ms. Oswald said. “Until November 2016, there’s no new project that will provide relief to the market.

“The Marcellus is there, but the pipes are full,” Ms. Oswald said. “And you can’t do a pipeline in six months. It takes roughly three to four years from idea to execution.”

Still, if all four projects announced by Spectra and Kinder Morgan are completed, New England ultimately will see about 4.1 Bcf/d of additional natural gas capacity.

“That’s more than plenty,” Ms. Oswald said. “The demand we have seen for that region is about 4 Bcf/d of peak demand in the winter.”

 

Challenges ahead

 

Still, there are some hurdles to overcome. Among them is the way the energy market works in New England.

When pipelines from the south and the west cannot carry enough fuel to satisfy both electric demand and heating requirements, the priority delivery goes to the heating industry because the utilities have firm contracts in place. Natural gas power plants typically do not have firm contracts and operate on a “just in time” delivery system, according to ISO NE.

Pipelines need firm commitments in place to be built, said Don Santa, CEO of the Interstate Natural Gas Association of America, in Washington D.C.

“This isn’t a business where pipelines are built on speculation, both due to the economics — this is long-lived, high-cost immobile infrastructure — and also due to being subject to rate regulations and approval from the Federal Energy Regulatory Commission,” Mr. Santa said. “You have to prove the need for the pipeline, so you the company has to show there’s commitment for capacity on it from others.”

The New England States Committee on Electricity also is evaluating ways to have the cost of the gas infrastructure paid for by electricity consumers through a tariff.

Such a plan, which has drawn both support and criticism, ultimately would have to be approved by FERC.

In addition, new pipeline projects, especially in an area as densely populated as the northeastern U.S., face backlash from residents who don’‍t want to see such a project cut through their communities.  

Stephanie Ritenbaugh: sritenbaugh@post-gazette.com or 412-263-4910

Source:  http://fuelfix.com/blog/2014/08/27/plenty-of-pluck-left-in-the-marc...

Plenty of pluck left in the Marcellus, report says
Posted on August 27, 2014 at 6:13 pm by Robert Grattan in Hydraulic fracturing, Natural gas, Natural gas liquids, Production, Shale

HOUSTON — The Marcellus region is now the biggest natural gas shale play in the world, and there’s still about $90 billion to be made by tapping the area’s reserves, according to a study by energy analyst group Wood Mackenzie.

The Marcellus, which stretches from New York to West Virginia, produced about 15.6 billion cubic feet of natural gas per day in August, about 38 percent of total U.S. natural gas production for the month, according to the U.S. Energy Information Administration. The agency doesn’t expect the boom to taper off anytime soon, and several of the biggest companies are cashing in.

Wood Mackenzie predicted that the top 20 operators in the Marcellus will earn nearly $86 billion over the life of the play after the costs of reaching the reserves. Among the 20 largest operators are Fort Worth-based Range Resources Corp., Pittsburgh’s EQT Corp., Houston’s Cabot Oil & Gas Corp. and Denver-based Antero Resources.

For comparison, Wood Mackenzie estimated that there’s about $118 billion to be made by extracting the resources in North Dakota’s Bakken region — but most production there is higher-priced oil compared to the natural gas dominant in the Marcellus.

At the peak of activity between 2018 and the early 2020′s, companies will drill 2,600 wells per year in the Marcellus, Wood Mackenzie analyst Jonathan Garrett projected, up from about 1,400 this year. The new wells will drive production up by nearly 25 percent to 20 billion cubic feet of natural gas equivalent per day by 2020, according to Wood Mackenzie.

Those big production numbers have contributed to lower natural gas prices in the region, especially in the northeast sections where there’s not as much infrastructure to bring the gas to market, Garrett said. But even with gas in those regions going for less than the U.S. benchmark Henry Hub price, operators can make a hefty profit. Returns on investments can be as high as 30 percent to 40 percent in the best areas of the play, Garrett said.

The prospect of returns like that will draw $10.9 billion in new capital to the region in 2014, Wood Mackenzie estimated, far more than any other gas play. Through 2035, the top 20 operators are expected to spend nearly $110 billion in the Marcellus and drill more than 25,000 new wells.

Most of those wells are now being drilled in the in the Southwestern Pennsylvania region and West Virginia, where wells produce natural gas that contains valuable natural gas liquids and condensates. There’s also still strong opportunity in the Northeastern Pennsylvania area, where high-pressure wells that contain only natural gas — what the industry calls dry gas — can produce a great deal of it quickly, Garrett said.

Overall, he said, Wood Mackenzie’s estimate of $90 billion in remaining value may turn out to be on the low side.

“If well costs continue to trend down and well results continues to trend up,” Garrett said, “I wouldn’t be surprised if this number goes up a bit.”

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