By Stephanie Ritenbaugh / Pittsburgh Post-Gazette    June 23, 2015 12:15 AM

Over the next three years, the Marcellus Shale region can expect to see about 17 pipeline projects meant to ship about 17.3 billion cubic feet per day of natural gas out of Pennsylvania, West Virginia and Ohio to end-users, according to IHS Energy.

Those destinations “are varied, and in addition to New England, some are targeting the Midwest, eastern Canada and the South,” said Matthew Piatek, associate director of North American natural gas for IHS, which tracks energy markets.

One change is in who is driving demand for more pipelines. Now, more end-users are signing up to get the gas, rather than drillers pushing for the projects, said Mr. Piatek.

“That’s been one of the areas we expect to see major growth in demand, particularly for LNG exports from the Atlantic and Gulf Coast areas, new gas-fired generation in the Southeast, as well as an appetite for [local distribution companies] through the Midwest,” Mr. Piatek said.

Link to full article:


Views: 1410

Reply to This

Replies to This Discussion

Really only partially true.  The buyers from Asia will also determine the NG price for LNG exports.  LNG spot prices in Asia are now under $7.  Considering the cost turning NG into LNG, a $7 price doesn't allow for a NG price above $3. 

Asia’s LNG Buyers Get Sweeter Deals(excerpt)

As market dynamics have changed in buyers’ favor, they are opting for shorter-term contracts, sometimes for as little as one year. Pricing arrangements are becoming more flexible, too.

“Today, buyers have the curse of choice. They can buy at an oil-linked price, they can buy at a Henry Hub-linked price and they can buy on a European gas-based price,” said Matthew Arnold, head of LNG at EDF Trading, a unit of European energy company EDF SA, at a recent Platts conference.

Prices at the Henry Hub, a storage and delivery point in Louisiana, are considered the benchmark for all U.S. natural-gas pricing.

Deal terms that once were rarely disclosed publicly are becoming more transparent, industry participants said, and pricing is becoming less complex.

“There’s absolutely no reason now for LNG to be indexed to oil. It’s mature enough to be a product in its own right,” said David Morris, head of Asian LNG Business at E.ON EONGY -1.17 % Global Commodities.

Stagnant demand in Asia is also driving change. Japan’s nuclear reactors are slowly restarting, South Korea has large stockpiles of LNG, and China has access to cheaper gas via pipelines from places such as Turkmenistan. Consumers in these countries are seeking better terms on existing contracts.

“Asian buyers are in a strong position to negotiate for further concessions,” said analysts at BMI Research in a note.

Increased gas exports from North America are set to add to supplies, bringing a new level of competition to the market. The U.S. Energy Department has granted approvals to 10 projects to ship gas to countries that don’t have free-trade agreements with the U.S., giving those exporters access to major markets such as China and Japan.

Four of them are under construction, and one is expected to begin exporting later this year.

U.S. LNG exporters have said they would allow buyers to resell cargoes in the spot market, giving them the opportunity to trade the gas. That contrasts with major producers such as Qatar, which demand that gas be delivered to a specified location.

U.S. LNG exports will be “structured very differently to conventional supply. It’s a different pricing construct, but it also has more flexibility, less constraints and lower barriers to entry,” said Steve Hill, BG Group BRGYY 0.39 % ’s head of energy marketing and shipping.

Already, buyers in China, Japan and South Korea are using the prospect of LNG shipments from the U.S. as leverage in seeking lower prices and better terms from sellers such as Russia.

“The Chinese are likely to be looking to squeeze an even better price out of the Russians than would otherwise have been the case,” said Alastair Newton, a senior political analyst at Nomura International. “That’s what free market economics are about, after all.”

The article is about where supply will come from and my title is about what the operator's will be paid for that supply, not what end users will pay for the delivered LNG. Sorry for any confusion.

Hi Skip:

Just read your eye catching headline about Marcellus setting the pricing for US LNG exports.  As you know,  most of the LNG contracts are based on HH pricing plus a markup.  So, you are suggesting Marcellus will set HH pricing, correct?

QE/near ZIRP has distorted business practices, but as far as I know, not economics/math.  

The cheapest MCF will not set the price at HH; that's what the marginal MCF does…and one these years, the marginal floor-cycle cost MCF will set the price floor.  If you have info that indicates otherwise, would love to see.  

As someone invested in 2019 natgas futures (now at ~$3.50), I am focused on the marginal MCF and believe that will be likely produced by the Barnett or Haynesville play.  After a few more years of capital destruction and working thru the most economical parts of the plays - guessing we are looking at something closer to $5 or even $6+.

Attached some comments from another landman in Haynesville.  Be interested on your perspective on these remarks.   Thank you.



from Dion War, president of Baton Rouge Assoc of Landmen -

October 4, 2013

"...The Haynesville has entered the second phase of development - manufacturing and build out. This will be driven by revenues and cost metrics rather than the initial sunk costs of development (G&G, Land, Legal, Lease Acquisition). Production and profits will dictate the pace. Until the natural gas price ascends to a level that would warrant another wave of wholesale lease acquisition ($6 - $8+), depending on the source) and subsequent build out into the lesser tiers, or another "game changer" surfaces, things should remain static."




his profile & additional comments -



Hi. Arrest_ID.  What I'm saying is that Marcellus ng will be the cheapest source available to Gulf Coast LNG exporters.  Exporters don't care where an mcf comes from, only what it costs.  Marcellus operators can produce an mcf, incur transportation costs and still make a profit at a price comparable to what a Haynesville mcf costs to produce.  Therefore Haynesville gas will face stiff competition as the annual export volume increases as more trains come on line.

A lot has changed since Dion made that statement so I suggest you check with him.  It's highly unlikely that NG will sell for $6 to $8 for a number of years.  Take a look at the futures price to see when a $4 price is predicted (Jan 2020).

Guess your headline assumes the LNG importers lock in all the core/Tier I Marcellus production before other buyers and therefore do not need to source from HH for their tolling agreements...and that the Marcellus producers are will ignore market pricing in determining what they will sell natgas for.

No producers sell natgas futures in the out years like E&P MLPs - and they are refusing to sell 2018 and 2019 natgas.  Check out Linn Energy's presentations as an eg.  (can post if you like)


Even if all of Marcellus were cheap, and even if it were producing 20 BCF/day by 2019, that still leaves a lot of natgas required to fill up the tub.

Shale and conventional well declines amount to about 17 BCF/day per year.   

PIRA estimated the US will have an additional 18 BCF/day demand by 2019. 

Not sure how the US will do it all without using more expensive sources.

BEG had some interesting charts in their June EIA presentation showing the price sensitivity of the Barnett, Fayetteville and Haynesville plays:

 BEG EIA Presentation June 2015

...but this presentation still did not link the forecasted demand with the the sources required to, how much $6 natgas, if any, will be required in 2020?


Of course, the futures curve is not a good predictor of prices - and that especially holds true during time of financial turmoil.

2019-natgas going from $3.50 to $5 is a 40% gain.  Using 2:1 leverage (to put you on par with the leverage an E&P uses on your behalf) gets you to an 80% gain.

Guessing it won’t take the market until 2019 to realize that the U.S. cannot produce ~90+ BCF/day of $3.50-natgas….without hundreds of billions of dollars of write-offs. ;)

Seemed like a simpler bet than trying to value an E&P nowadays.


Does HH pricing affect or limit direct, long term PSA agreements between operator and end user such as the one negotiated between ECA and Nucor?  Marcellus operators will find the most profitable market available.  Transportation to the Gulf Coast appears to be far ahead of connections to un-served NE markets where pricing will provide a premium. 

Incoming! Marcellus Pipelines To Strike The Gulf Coast Spot Price

Nissa Darbonne  Friday, May 1, 2015 - 5:06pm

But EnerVest’s John Walker expects LNG and other demand growth will absorb the new, natural-gas supply.

Rusty Braziel spent most of his career figuring out how to get Midcontinent and Gulf Coast gas to the Northeast. “Now these guys don’t need it anymore,” Braziel noted in a recent ADAM-Houston meeting. The president and principal energy-markets consultant for RBN Energy LLC began his career in the 1970s in energy-marketing, -trading and -data services.

Marcellus natural gas at price points in Pennsylvania and the region are trading some $2 and $2.50 below that of the Henry Hub price. The Transco Zone 6-New York City price spiked above Henry Hub during the past two winters; however, the summer price has been as much as some $2 below Henry Hub.

“Think about this,” he told the group, which consists of E&P M&A professionals. “This is Henry Hub, Louisiana…and the price in New York City is (some) $1.50 under that. Surely the Lord did not intend this. Something is horribly, horribly wrong.”

Northeast gas shortages had become common, particularly in the 1970s, and pipelines directed Gulf Coast, Midcontinent and other gas to the region. The Rockies Express (Rex) pipeline was built earlier this century to feed gas to the Northeast from Colorado; the flow has been redirected to flow Marcellus and Utica gas, instead, to the Midwest.

“And Canadian gas—we don’t need it anymore,” Braziel added.

Marcellus production was 14.4 Bcf a day in January, according to an EIA report. The output was more than 36% of U.S. shale-gas production and more than 18% of all U.S. production. Range Resources Corp. reported this week that one of its Marcellus wells had a 24-hour IP of 43.4 MMcfe—a new record in the play. In the Utica, its Claysville’s Sportsman’s Club Unit 11H had a 24-hour IP of 59 MMcf/d.

More than 40 existing pipelines and newbuilds are under way, Braziel said, to send Marcellus gas into New England (5.8 Bcf/d), Canada (1.2 Bcf/d), Chicago/Midwest (5.3 Bcf/d), the southern East Coast (7.7 Bcf/d) and the Gulf Coast (8.2 Bcf/d). Some of the Canada-bound lines aim to serve Great Lakes-area industries; at least one aims to reach New England via a Canadian route north of the Great Lakes.

“Imagine what the (western) Canadian (gas) producers think about that,” he said.

His slide that showed the number of pipelines under way to take Marcellus and Utica gas to the Gulf Coast drew a gasp from the audience. The 15, bold arrows were reminiscent of missile-strike scenarios of the Cold War days. “It’s headed straight to the Henry Hub…,” Braziel said. “All of them will probably be built; most of them have producer backing already.”

Meanwhile, gas from the Bakken, Midcontinent, Permian Basin and Eagle Ford is being directed to the Gulf Coast as well. “All of that gas has got to go to the Henry Hub (price). It’s going to be an interesting market for the next few years.”

Meanwhile, new Gulf Coast demand is to consume that new supply, John Walker, chief executive officer of EnerVest Ltd. and executive chairman of EV Energy Partners LP, said at a recent reception in Houston.

He expects LNG exports will consume between 8 and 12 Bcf/d by 2020; the first two liquefaction trains are expected to come online this winter. Some of the eight existing pipelines into Mexico are being expanded and nine new projects are planned. First Reserve Corp. and BlackRock Inc. co-invested some $900 million with Pemex recently in two of these. Los Ramones North-Phase 2 and South-Phase 2 are to move into Mexico natural gas produced from South Texas, including from the Eagle Ford formation. Construction began last year. The lines are expected to be operating in mid-2016.

“I expect Mexico will take (the current) 2 Bcf/d to more than 8 Bcf/d by 2020,” Walker told attendees at the Texas Alliance of Energy Producers reception.

Exports plus growing, daily demand in power generation (+5.7 Bcf), industrial (+2.7 Bcf), natural-gas-fueled transportation (+2 Bcf), and residential and commercial use (+1 Bcf) could result in overall growth in daily demand for U.S. gas of between 22 and 30 Bcf, Walker said.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas InvestorOilandGasInvestor.comOil and Gas Investor This WeekA&D Contact Nissa at

Guess your headline assumes the LNG importers lock in all the core/Tier I Marcellus production before other buyers and therefore do not need to source from HH for their tolling agreements...and that the Marcellus producers are will ignore market pricing in determining what they will sell natgas for.

I don't understand all that I read about future price predictions and I certainly don't dabble in the futures market but it seems that none of these articles consider onshore chemical market demand from companies which might want to lock in cheap NG feedstock. Do you think there will be increased US demand in the near term (3-5 yrs) from chemical plants or manufacturers (don't laugh... we still have a few)? It just seems to me that you would have to give that some weight if you want to predict where the price might go.

Sasol ain't building that $8.4 billion cracker plant in Lake Charles for nothing. They will clean up that wet gas then load the dry gas onto the tanker ships and send the wet stuff to the chemical plants that dot the Gulf coast. Kinder Morgan was going to do the same thing at Mt Belvieu but Sasol beat them to the punch.

Just as with the LNG export facilities a number of the chemical plant upgrades and new builds that are on the drawing board, awaiting regulatory approval, or looking for financing will not end up being built.  Those that will won't come on line for a few years.  The 2018/2019 time frame seems accurate for those projects that will clear all the hurdles and get built.  Once it's clear which will go into operation I'm sure plenty of industry pundits will calculate the supply demand and make their projections public.  My point is that the Marcellus connections will be in place before the ramp up in demand.  Adding Marcellus/Utica production to the already plentiful Gulf Coast supply will limit the price of NG until some time in the future when all that new demand is on line.

The best information that I can find indicates that Haynesville gas being quite lean has less than 1% ethane on average.

Media Release
27 March 2015

Sasol breaks ground on world-scale ethane cracker and derivatives project

Westlake, Louisiana– Today, Sasol broke ground on its ethane cracker and derivatives mega project near Westlake, a facility that will roughly triple Sasol’s chemical production capacity in the United States.

Mayor Bob Hardey, Westlake city council members, Calcasieu Parish Police Jury President Nic Hunter, Speaker of the Louisiana House of Representatives Chuck Kleckley and more than 100 community partners joined Sasol executives today to mark the start of construction for the company’s world-scale facility.

"By the time construction is complete in 2018, Sasol’s investment will total almost 9 billion dollars, making it one of the largest investments in our company’s history,” said Steve Cornell, Executive Vice President of International Operations for Sasol. "Along the way, we’ll create more than 5,000 construction jobs and more than 500 full-time positions, 100 of which have already been filled.”

The end result will be a state-of-the-art petrochemical complex that uses abundant U.S. ethane to manufacture a diverse slate of commodity and specialty chemicals for markets around the world.

Early works activities, site preparation and civil construction work have been under way since 2014. Site aboveground work and heavy equipment deliveries will begin in 2015 and mechanical, electrical and instrumentation work in 2016 and 2017. Sasol expects the facility will achieve beneficial operation in 2018.

Ethane "cracking” is the process of converting molecules of ethane extracted from natural gas to create ethylene, one of the building blocks of the petrochemical industry. The facility will produce approximately 1.5 million tons of ethylene per year. The ethylene will be used in six new downstream derivative plants to produce a range of high-value derivatives used in everyday products such as synthetic fibers, detergents, fragrances, paints, film and packaging.

For more information about project progress, visit

Cheniere gets OK to export from Sabine Pass expansion  June 26, 2015 | By (Rhiannon Meyers)

A federal agency on Friday granted Cheniere Energy a key export authorization for its Sabine Pass expansion, paving the way for the company to press forward with the project.

The U.S. Energy Department agreed to let Cheniere ship supercooled gas produced by the two additional production facilities to countries with which the U.S. does not have free trade agreements. The agency said it gave its approval after “extensive, careful review” of the project that took into consideration the proposal’s affects on the economy, energy security and the environment.

The announcement comes days after another federal regulator cleared Cheniere to start construction on the project, which is expected to boost Sabine Pass LNG’s output by 50 percent.

With its major regulatory hurdles out of the way, Cheniere is poised to make a final investment decision on the project which will be built on the same site where the company already is building four liquefaction production facilities.

The company already received approval from the U.S. Energy Department to ship 2.2 billion cubic feet per day of natural gas for 20 years. Friday’s approval clears Cheniere to export an additional 1.38 billion cubic feet per day.

The first four trains are nearing the finish line, putting Cheniere on track to produce its first batch of LNG later this year, but work can’t start on the expansion project until Cheniere makes a final investment decision. The company has already locked in sales and purchase agreements for at least one of the trains, agreeing to sell LNG to Total Gas & Power North America and Centrica, but it’s still negotiating contracts for the other train.


© 2023   Created by Keith Mauck (Site Publisher).   Powered by

Badges  |  Report an Issue  |  Terms of Service