Re-Posting The Recent MDU Natural Gas Pipeline Story -- July 20, 2021

First, from June 3, 2021:

MDU:

• MDU pipeline: FERC certificate for ND natural gas pipeline project; press release;
• WBI Energy, the pipeline subsidiary of MDU;
• North Bakken Expansion project
• expansion project to transport 250 million cubif feet of natural gas per day from the Bakken
• 62 miles of 24-inch natural gas pipeline
• 20 miles of 12-inch natural gas pipeline
• a new compressor station
• $260 million
• 260/82 = $3.2 million / mile of pipeline
• entry: new Elkhorn Creek compression station, southeast of Watford City
• runs pretty much NNE to Portal, ND, on Canadian border
• map at this link; previously posted;
• by the way, this was huge; see SeekingAlpha note;

Now, this update, from July 19, 2021:

MDU press release, link here. I believe this project may have been "fast-tracked" with the assistance of North Dakota's senators and congressman.

BISMARCK, N.D., July 19, 2021 -- WBI Energy, Inc., a subsidiary of MDU Resources Group, Inc., began construction this week on the North Bakken Expansion project in northwestern North Dakota.

This natural gas pipeline expansion will have capacity to transport 250 million cubic feet of natural gas per day from the Bakken Formation. WBI Energy received a notice to proceed on July 8 from the Federal Energy Regulatory Commission, allowing construction to commence.

"WBI Energy transports more than 50% of the natural gas produced from the Bakken. This project will bring WBI's total pipeline system capacity to more than 2.4 billion cubic feet per day while reducing natural gas flaring in the region by allowing producers to move more gas to market. Producers have reinforced their need for this additional capacity by committing to long-term transportation contracts with WBI," said David L. Goodin, president and CEO of MDU Resources. "We appreciate the support from state and federal officials who helped elevate the significance of this project for both its environmental and economic benefits."

The North Bakken Expansion project includes construction of approximately 63 miles of 24-inch natural gas pipeline and 30 miles of 12-inch natural gas pipeline, as well as a new compressor station and additional associated infrastructure. It is estimated to cost $260 million and, during peak construction, is expected to employ up to 450 people. WBI Energy expects to have the pipeline in service by the end of the year.

Follow-Up On ND "Hot Gas" And The Northern Border Pipeline -- September 5, 2020

This is in response to the story posted earlier today regarding "hot gas" and the Northern Border Pipeline.

A reader wrote that he/she had a I have a very dear friend from college. He managed gas plants throughout the OK/TX panhandle. His dad did the same in TX, NM and AZ. I've been lucky enough to have them each walk me through a plant, drive me through the country they were gathering, etc. I asked him for Cliff Notes on our "too hot" gas. This is the reply from that individual with extensive experience with this issue:

It is not uncommon to have some 1200 BTU gas in a field, depends on zone, depth, area, etc. 

It sounds like they need more gas processing in North Dakota. 

The regulation is dumb to me because the gas can be processed downstream.

Normally pipelines are NOT the end user, they are only the transporter and someone else can pull the BTU out of the gas.

Also it is important to gas processing plants to be able to leave the ethane in the gas if the market is paying more for the ethane in the gas rather than in the liquids stripped out of the gas.

All gas processing plants are designed to run in ethane rejection (leave the ethane in the gas rather than remove it with the propane, butane, pentane, etc. ) if the markets pays better for ethane in the gas rather than in the liquids removed. 

Every plant I ever worked in or managed was capable of ethane rejection even if not originally designed for it. Just warm up the tower temps and the ethane goes out the top with the methane rather than out the bottom with butane, propane, pentane, etc. 

If designed for it then they can do it more efficiently. 

It does sound like the ND gas is pretty hot overall. I saw / toured one plant in the Denver area years ago that BP ran and they sold to the pipeline that provided Denver. In order to cut the btu they actually injected air into the pipeline. It sounded insane to me because we spent a lot of time making sure we did not get air into our pipelines, we operated some lines at below atmospheric pressure so any leak pulled air into the system, and air can cause explosions, but at the Denver site they actually injected air into the system. Probably was no added compression on the system after the air injection. Air and compression don't mix well.

This was my reply, noting that is way above my pay grade, and far ahead of my headlights, to mix metaphors:

Two immediate thoughts come to mind: 

Political: someone is trying to keep ND gas out of the Northern Border Pipeline so the Canadians can ship more of their own gas; or, more likely, it's a matter of who pays: 

Financial: either the operators in ND pay to "dilute" their "hot gas" before it goes into the pipeline, or the end user (in Illinois, or wherever) pays for the process of doing that (sounds minimal). 

Regardless: it sounds like a manageable problem, and maybe this will spur ND to put in more natural gas processing plants.

Wow, this takes me to the early days of the Bakken: ethane rejection. I had forgotten all about it. I have a lot of problems with tags (bottom of page) but in this case, I'm glad I had an "ethane rejection" tag. 

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The Original Post

This was the original post:

From Geoff Simon's top stories of the week:

A tariff pending before the Federal Energy Regulatory Commission may place limits on the heat content of natural gas in the Northern Border Pipeline.

Justin Kringstad, director of the ND Pipeline Authority, told members of the ND Industrial Commission this week that the tariff would allow Northern Border to reject any gas that exceeds 1,100 BTU per cubic foot.

That could be a problem for North Dakota producers because natural gas produced in North Dakota is rich in ethane and other natural gas liquids.

Kringstad said the gas must be processed to remove those NGLs to reduce its heat content to the 1,100 BTU level.

North Dakota gas now makes up about 80 percent of the total moving through the Northern Border Pipeline, and "signs are pointing toward North Dakota being almost the exclusive shipper in the next three to six years," Kringstad said. He said achieving the 1,100 BTU threshold would require the removal of additional 80,000 bbl/day of ethane by the year 2027.

Industry sources say the ideal heat content for natural gas is between 950 and 1,100 BTU/cubic foot. Gas that burns hotter can damage appliances and other equipment that burn it. Kringstad said Northern Border interconnects with several downstream pipelines that limit heat content to 1,100 BTU or less.

"The downstream folks are concerned that North Dakota's gas is getting too hot," Kringstad said. "The marketability and safety issues downstream are what's driving pressure on Northern Border to implement the tariff change."

North Dakota may have a little time to adapt if FERC approves the new tariff. Kringstad said the change would not be immediate because the tariff would be phased in, starting at 1,155, stepping down to 1,140 and eventually down to 1,100. He said the near-term solution is balancing the hotter gas going into the pipeline with dryer gas that has had most of its liquids removed. Kringstad said one other possibility he's exploring that could provide opportunity to electric generators is injecting hydrogen gas in the pipeline.

Fascinating story on so many levels. 

 

Northern Border Pipeline Could Reject US Natural Gas If ND Producers Don't React -- September 5, 2020

 From Geoff Simon's top stories of the week:

A tariff pending before the Federal Energy Regulatory Commission may place limits on the heat content of natural gas in the Northern Border Pipeline.

Justin Kringstad, director of the ND Pipeline Authority, told members of the ND Industrial Commission this week that the tariff would allow Northern Border to reject any gas that exceeds 1,100 BTU per cubic foot.

That could be a problem for North Dakota producers because natural gas produced in North Dakota is rich in ethane and other natural gas liquids.

Kringstad said the gas must be processed to remove those NGLs to reduce its heat content to the 1,100 BTU level.

North Dakota gas now makes up about 80 percent of the total moving through the Northern Border Pipeline, and "signs are pointing toward North Dakota being almost the exclusive shipper in the next three to six years," Kringstad said. He said achieving the 1,100 BTU threshold would require the removal of additional 80,000 bbl/day of ethane by the year 2027.

Industry sources say the ideal heat content for natural gas is between 950 and 1,100 BTU/cubic foot. Gas that burns hotter can damage appliances and other equipment that burn it. Kringstad said Northern Border interconnects with several downstream pipelines that limit heat content to 1,100 BTU or less.

"The downstream folks are concerned that North Dakota's gas is getting too hot," Kringstad said. "The marketability and safety issues downstream are what's driving pressure on Northern Border to implement the tariff change."

North Dakota may have a little time to adapt if FERC approves the new tariff. Kringstad said the change would not be immediate because the tariff would be phased in, starting at 1,155, stepping down to 1,140 and eventually down to 1,100. He said the near-term solution is balancing the hotter gas going into the pipeline with dryer gas that has had most of its liquids removed. Kringstad said one other possibility he's exploring that could provide opportunity to electric generators is injecting hydrogen gas in the pipeline.

Fascinating story on so many levels. 

 

Dominion, Duke, Warren Buffett, Natural Gas, And All That Jazz --- July 5, 2020

Three stories.

1. The proposed Atlantic Coast Pipeline project has been scrapped after years of legal challenges and construction delays. Project developers, Dominion Energy and Duke Energy, announced the pipeline's cancellation earlier today, Sunday, July 5, 2020. From USA Today:

The project’s developers, Dominion Energy and Duke Energy, announced the pipeline’s cancellation in a joint statement on Sunday, citing “increasing legal uncertainty” — less than a month after the U.S. Supreme Court approved a critical permit that West Virginia Gov. Jim Justice celebrated as an “exciting” victory.

“This announcement reflects the increasing legal uncertainty that overhangs large-scale energy and industrial infrastructure development in the United States,” Dominion CEO Tom Farrell and Duke CEO Lynn Good said in the statement. “Until these issues are resolved, the ability to satisfy the country’s energy needs will be significantly challenged.”

The 600-mile natural gas project had faced opposition since its 2014 introduction from environmental advocates, landowners and activists who argued that the pipeline would scar pristine landscapes while also questioning its necessity.

The proposed $8 billion pipeline, which would have crossed under the Appalachian Trail and carried natural gas from West Virginia into North Carolina and Virginia, had been touted by supporters as a boost to economic development.

2. Also from USA Today: Warren Buffett / Berkshire Hathaway adds to energy portfolio; buys Dominion Energy as lines in $10 billion deal.

The energy division of Warren Buffett's Berkshire Hathaway will acquire gas lines owned by the power company Dominion Energy in a nearly $10 billion deal, the two companies announced Sunday. 

Dominion has sought to expand its pipelines along the Atlantic Coast for years to take advantage of the nation's fracking boom. However, after a number of regulatory hurdles, the Virginia-based company is abandoning those plans and ceding control of its natural gas and storage network to Berkshire Hathaway. 

Dominion has more than 7 million energy customers across 20 states in the U.S. Berkshire Hathaway Energy provides service to 12 million customers around the world.

In addition to owning 100% of Dominion Energy Transmission, Berkshire Hathaway will also take a 25% stake in Cove Point, a natural gas facility in Maryland. Berkshire Hathaway will also own 50% of Iroquois, a natural gas system that serves the Northeast. 

The $9.7 billion deal does not include acquisition of the proposed 600-mile Atlantic Coast Pipeline, a joint venture between Dominion and Duke Energy that would've stretched from West Virginia through Virginia and North Carolina.

3. Berkshire Hathaway is also interested in San Diego Gas and Electric; see Voice of San Diego, a couple of weeks ago.

SDG&E also responded to the city’s request, as expected since the franchise fee is the utility’s bread and butter. By law, SDG&E can’t make a profit on buying and selling energy, a business the utility has signaled it’d like to leave. Instead San Diego Community Power, the newly formed government-run utility in the region, will take that over for at least 40 percent of SDG&E’s customer base come 2021.

SDG&E is one of five business divisions under the Sempra Energy umbrella. It will be interesting to listen to Sempra's 2Q20 conference call.

Disclaimer: this is not an investment site.  Do not make any investment, financial, job, career, travel, or relationship decisions based on what you read here or think you may have read here. 

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Berkshire Hathaway Energy

Years ago I wrote on the blog that if I ever quit blogging about the Bakken, I would start blogging about Berkshire Hathaway. LOL.

Talk about an interesting "company."

Berkshire Hathaway Energy website. At that website, links to each of the businesses within BHE. Most of these companies are within the US; two exceptions:

• AltaLink: Alberta, Canada
• Northern Powergrid: Yorkshire, England, and surrounding area

Two thoughts:

• it's easier to buy pipelines in the US than build them;
• better than dividends? "Rent."

Wholly owned Berkshire Hathaway companies: link here.

Natural Gas Pipeline Constraints -- Update -- January 11, 2020

I don't follow natural gas closely enough to understand all this, but this article over at Platts seems to be fairly straightforward.

The link.

These are the summary data points:

• southbound corridors from Carthage, Perryville becoming constrained 
• estimated 1.5 Bcf/d capacity remains from Midwest, Northeast, Permian 
• summer-2020 Gulf Coast demand growth anchored by LNG liquefaction

Too much natural gas (and that amount is increasing) from Carthage, Perryville; not enough pipeline capacity to get the natural gas to Louisiana and east Texas. Producers have to cut costs to get access on pipeline. From the northeast, natural gas prices are, apparently, running ten to twenty-four cents behind Henry Hub prices. Farther afield, from the northeast and the midwest (think Bakken), the discount is even greater -- Chicago is 22 cents below Henry Hub while Dominion South is as much as 42 cents below Henry Hub.

As summer approaches, the situation will worsen; producers will do what it takes to get their product in the pipeline, and the discounts will widen.

While flow data along much of the North-to-South corridor appears to suggest ample capacity to reach the Gulf Coast, bottlenecks actually exist closer to locations like Henry Hub and Houston Ship Channel.

From the article:

For Midwest and Northeast gas flowing to the Gulf Coast on key interstate corridors – ANR Pipeline, Columbia Gulf Transmission, Natural Gas Pipeline Co. of America, Tennessee Gas Pipeline, Texas Eastern Transmission, Texas Gas Transmission, Trunkline Gas and Transcontinental Gas Pipe Line – congestion south of Carthage in West Louisiana and south of Perryville in the state's northeast will pose serious constraints to gas moving southbound next summer.

According to Platts Analytics, approximately 500 MMcf/d of available capacity remains between Carthage and Houston Ship Channel on Gulf South Pipeline, NPGL, Tennessee and Texas Eastern.

From Perryville to Henry Hub, a combined 83% utilization rate last summer on ANR Pipeline, Columbia Gulf, Tennessee, Texas Gas and Trunkline left about 1 Bcf/d of available capacity along the other key southbound corridor.

Including the eastbound corridor from the Permian Basin, Platts Analytics estimates that last summer, roughly 1.5 Bcf/d of spare capacity to Houston Ship Channel and Henry Hub remained from West Texas, Carthage and Perryville.

Compared to summer 2019, demand along the East Texas and Louisiana Gulf Coasts is forecast to rise about 4 Bcf/d, anchored principally by the growth in LNG liquefaction activity.

[So, if I'm reading this correctly, there may be 1 Bcf/d of available capacity, but demand is likely to rise above 4 Bcf/d -- if I'm reading that correctly -- holy mackerel -- that's a huge gap.]

At Freeport LNG, the startup of commercial service at Train 2 and Train 3 is expected by February and June, respectively.

At Cameron LNG, Train 2 and Train 3 are scheduled to enter service by April and August.

Along with a higher anticipated utilization rate at Cheniere Energy's Sabine Pass, LNG producers will likely require an incremental 3.5 Bcf/d of gas this summer compared to last.

Additional factors weighing on the region's available supply include stronger demand from Gulf Coast power generators and industry, as well an anticipated decline in Gulf Coast and offshore gas production.

Compared to last summer, though, more supply should be delivered to the East Texas and Louisiana Gulf Coast region from Kinder Morgan's 2 Bcf/d Gulf Coast Express, which entered service last September.

Hmmmm....one of my regular readers knows the natural gas pipeline story very, very well from an investment point of view. It will be interesting to see if she/he has anything to add regarding this story.

Disclaimer: this is not an investment site.  Do not make any investment, financial, career, travel, job, or relationship decisions based on what you read here or think you may have read here. 

KMI:

• currently trading at $21.51
• from one year ago, up from $17.32 one year ago
• pays 4.73%
• target: $22.27

See Motley Fool -- ten largest pipeline companies by enterprise value.

WMB:

• currently trading at $23.50
• from one year ago, down from $25.45
• pays 6.36%
• target: $27.46

OKE:

• currently trading at $75.53
• from one year ago, up from $60.96
• pays 4.84%
• target: $75.68

This article is two years old, but provides a nice overview. Look at the discounts (two cents to ten cents) back in 2017 and then compare them to the discounts, in 2020, noted above.

Growing demand along the Gulf Coast from industrial projects and exports have driven up Houston Ship Channel basis relative to Henry Hub from a discount of $0.02 in the summer of 2017 to a premium of $0.11 for May 2017. While Houston Ship Channel and Henry Hub prices are both much stronger year over year, pricing at Carthage and Perryville have seen discounts to Henry Hub widen to $0.10 back.

It sounds like the discounts will be "bad" on the pipelines leading into Carthage and Perryville, but the discounts will be even greater on the pipelines between Carthage/Perryville and Henry Hub.

Appalachian Trail -- 2,200-Mile Barrier To Pipelines -- Industry -- August 29, 2019

Link here.

Environmental groups weighed in against US Supreme Court action to free up the 600-mile, 1.5 Bcf/d Atlantic Coast Pipeline, countering assertions that an appeals court ruling left unchecked could have widespread implications for eastern US energy projects.

The natural gas project, intended to move Appalachian gas to Mid-Atlantic markets, has faced a series of legal setbacks, including a 4th US Circuit Court of Appeals decision that struck federal authorizations allowing the pipeline to cross the Appalachian National Scenic Trail and national forests.

Dominion Energy and the US Department of Justice in June asked the Supreme Court take up the case, challenging the part of the ruling that found the US Forest Service lacked authority under the Mineral Leasing Act to grant the right of way to cross the trail because the land is under exclusive authority of the National Park Service.

If the case gets to the US Supreme Court, any guesses on how RBG will vote?

Permian Natural Gas Pipeline Expansion -- What Will The Faux Environmentalists Complain About Next? -- May 26, 2019

Remember this back on May 15, 2019? A Permian pipeline bubble?

Hold that thought.

North Dakota flares about 15% of the natural gas it produces. Bakken flaring was a huge story years ago; that story has pretty much gone away. Environmentalists are now going after the Permian and flaring. Google it.

So, I was curious. How much natural gas is being flared in the Permian? I think we discussed this before. There are two numbers. An "older" number is 4.4%; a newer number is 5.8%. Whatever. I find both numbers incredibly small considering what is going on in the Permian. Remember, unlike the Bakken, the Permian has a lot of natural gas along with its crude oil. From my perspective the operators and the state have done a great job keeping flaring to about 5% of total natural gas production.

But, now look at this. From mrt.com, March 4, 2019:

The proposed pipeline capacity expected to come online in the Permian Basin over the next three years is vastly greater than the estimated volumes of flared gas, according to a Texans for Natural Gas analysis. Recent media reports have called attention to flaring levels in the Permian as production has increased, with one environmental group even suggesting that the market can’t solve the issue. But the new pipeline capacity being added over the next few years appears to contradict that claim.

A TNG review found an estimated 14 billion cubic feet per day (Bcf/d) in additional natural gas pipeline capacity set to come online in the Permian by the end of 2022. This equates to more than five trillion cubic feet of natural gas annually.

I don't know what that means. Is "14 billion cf/d in additional natural gas pipeline capacity" anything to get excited about?

Answer:  That proposed capacity is about 93 times larger than the current flaring levels, according to data from the Texas Railroad Commission.

Comment: private enterprise tends not to like to "over-build." If proposed capacity is 93 times larger than the current flaring levels, that speaks volumes. No pun intended.

If they are over-building, they will cut back.

If they are not over-building, there will be a huge surge in natural gas production over the new few years.

14 billion cubic feet = 2.3 million bbls boe. Per day. That's in addition to whatever is already being produced. 

ONEOK Making The Bakken Better -- To Extend Bakken NGL Pipeline -- April 25, 2019

Press release, data points:

• $100 million project
• 75-mile extension
• NGL pipeline
• will connect the northern portion of the Bakken NGL Pipeline with a third-party NG processing plant in eastern Williams County
• should be complete by 4Q20

It Never Quits -- Another Pipeline Connector In The Bakken -- MDU -- January 25, 2019

North Bakken Expansion Project:

• pipeline connector: natural gas connector from western North Dakota to interconnection point with Northern Border Pipeline
• MDU's WBI Enercy, Inc
• 67 miles of new pipeline 
• 20-inch diameter
• wag: at $1 million /mile = $67 million
• MDU's press release: $220 million 
• will start near Tioga, ND
• new connection with NBP in McKenzie County, ND
• Tioga is in Williams County
• this means that the pipeline will have to cross the river
• that probably explains the higher cost 
• initial phase: 200 millio cfpd)
• could expand to 375 million cfpd (65,000 boepd) if demand exists
• note: WBI Energy plans to utilize the Federal Energy Regulatory Commission's National Environmental Policy Act pre-filing process for the North Bakken Expansion Project and will begin that process by late in the first quarter of 2019.

From wiki:

Northern Border Pipeline is a natural gas pipeline which brings gas from Canada through Montana, North Dakota, South Dakota, Minnesota, and Iowa into the Chicago area. It is owned by TC PipeLines, LP and ONEOK Partners and is operated by TC PipeLines, LP . Its FERC code is 89.

Website and map here.

Embattled -- ETP -- Effectively Ended -- rovEr -- May 2, 2018

From ArgusMedia:

• ETP's Rover Pipeline
• FERC: "go for it"
• approval to reach full flow rates -- effective immediately
• connects Appalachian shale gas pipelines in West Virginia to markets in Ohio, Michigan, and Ontario, Canada (yes, shipping NG to Canada; who would have thought?)
  
• full flows: 3.25 billion cubic feet / day (about a half-million boepd?)
• comment: pretty cool; making America great again

WBI Energy's Valley Expansion Project -- North Side Of Fargo -- Has Been Approved By FERC -- Huge Shout-Out To The Bakken Frackers That Made It All Possible -- February 17, 2018

Updates

November 10, 2018: in-service.  

Original Post 

From WBI Energy:

WBI Energy's proposed Valley Expansion Project is an approximately 37.3-mile, 16-inch-diameter pipeline that will deliver natural gas to eastern North Dakota and western Minnesota. The pipeline would connect the Viking Gas Transmission Company pipeline near Felton, Minnesota, to WBI Energy's existing pipeline near Mapleton, North Dakota. New facilities include an electric compressor station near Mapleton, a regulator station in Barnes County, North Dakota, and town border stations in Burleigh and Stutsman counties, North Dakota.

EIA Posts Update On Elk Creek Pipeline Project -- February 2, 2018

Is it worth it to the states to have pipelines? From The Bismarck Tribune, October 10, 2017:

The Dakota Access Pipeline has boosted North Dakota’s tax revenues by $19 million in its first three months of operation, according to an analysis by the North Dakota Pipeline Authority.

But I digress.

From Twitter, twelve minutes ago, we've discussed the Elk Creek pipeline project earlier:

Story here.

Route runs nowhere near Standing Rock Indian Reservation in North Dakota and does not enter Nebraska. Whoo-hoo! Even Iowa is out of play. LOL. Even though Iowa is out of play, the green arrows suggest Iowa will gladly accept the energy once it's been produced, transported, processed, and delivered, maybe even subsidized by the state. Oh, no, that's wind energy that's subsidized. My bad. One of my favorite books in kindergarten when growing up in Williston, The Little Red Hen.

See RBN story here.

At the blog, January 5, 2018.

As we see more and more of these stories, we start to see a real buildout of another geographical energy sector in the US. For the first five or six years of the Bakken, it seemed many folks considered exploration and production of Bakken oil from North Dakota as simply a one-off, that it would peak and then slowly become a "backwater" energy play. As more and more infrastructure goes in, more and more production comes on line.

It's fun to read the history of Calgary.

ONEOK Announces New NGL Pipeline; Montana To Kansas; $1.4 Billion -- Keeping America Great -- January 5, 2018

Updates

January 8, 2018: the ONEOK story is also at the Bismarck Tribune. At $1/bbl, 240,000 bbls/day, $1.2 billion, a reader notes that it will take more than 13 years to simply pay off the $1.2 billion. This suggests to me that ONEOK thinks

• fossil fuel will be around for a long, long time; and,
• the Bakken and DJ will be a huge source for NG for a long, long time.

Long, Long Time, Linda Ronstadt


January 8, 2018: another reader weighs in on this announcement, see comments:

Ethane right now is left with the methane stream except at Tioga Hess Plant, where the Vantage pipeline to Alberta takes it too a cracker. That line has a 68,000 barrels per day.

The new lines won't be able to accommodate ethane, so ethane cracking could be another industry courtesy of the Bakken.

Ethane doesn't have the value for long distances so it needs to be consumed locally.

January 6, 2018: see comments -

OneOK built a 12" NGL line from MT to SE Wyoming about 5 years ago.

If you look at a map of the new line it looks like it is parallel with the original. I wonder if it is in the same right of way?

The original line was designed to carry 60,000 BBL per day, then it was boosted to 110,000 barrels and then 165,000 BBL. You can see mention at this link http://bismarcktribune.com/bakken/oneok-investing-in-several-projects/article_b8147fa6-516d-11e3-8f2d-0019bb2963f4.html.

Pipeline builders would probably like to keep their intentions as quiet as possible until the line is built. As I recall the original line ran into some opposition in the area of the Bear Lodge Mountains around Devils Tower due to the line passing through an area with gyp rock.

With this much increased capacity to transport NGL out of the WB the future looks bright for future production growth it appears to me. New or expanded gas plants in the works also? Or maybe updated Central Tank Battery production facilities with pad drilling being the new source of NGL?

I've seen a few CTB sites the last couple times I was in Dunn County and they contain several what appears to be ASME code vessels with many pipes connected to each vessel. Do these mini processing plants strip volatile/liquids from the oil and the gas? Which end up in NGL pipelines? (http://www.oneok.com/~/media/ONEOK/Newsroom/ReleaseDocs/ElkCreekPipeline_Map.ashx) link to the map of the new line. [By the way, to open an "ashx document" use Adobe.]

Later, 1:27 p.m. CT:  see first comment --

Sending unfractionated NGLs - aka 'Y grade' out of the Bakken could have a significant positive impact on operators' financials.

Essentially, removing the methane from the gas stream (possibly 70% +/- of the total volume) enables the higher value liquids to be transported and processed via pipeline.
I think liquids are presently transported by rail.

Today's spot pricing at Belvieu, expressed in barrels ...

• Ethane ~$11/bbl.
• Propane ~ $40/bbl
• Butane ~ $42/bbl
• Pentanes ~ $58/bbl

Transportation and processing fees would come out of these figures, but, still, it adds up in addition to the methane price realized at the Northern Border transfer point.

Original Post

Every now and then a developer announces a small wind farm and the local media is all over it, talking about the "new" wind farm. At the other end of the continuum the oil and gas sector seems to announce a new billion-dollar project every week. And there's no fanfare. If it weren't for the company's press release, we would probably never hear about it.

If a Martian were to read all the energy stories in the mainstream media, the alien would get the feeling that fossil fuel industry is dead, replaced by wind and solar. Hardly.

Another example, sent by a reader: ONEOK Announces Plans to Increase Natural Gas Liquids Takeaway Capacity out of the Rocky Mountain Region, press release. Details:

• the Elk Creek pipeline
• from ONEOK's Riverview terminal in eastern Montana to Bushton, KS
• 900 miles, 20-inch diameter
• to be completed by end of next year (2019)
• capacity: 240,000 bbls/day of unfractionated NGLs
• the pipeline: $1.2 billion
• related infrastructure costs: $200 million
• with additional pump facilities, capacity will increase to 400,000 bpd

TransCanada pipeline operational. Data points:

• Leach XPress
• 160 mile; 1.5 billion cubic feet/day
• will supply gas to Southeast and Gulf Coast markets
• had received approval from FERC on January 9, 2017

The Bakken -- It Just Never Quits -- December 23, 2017

The item is very short:

WBI Energy Transmission Inc. filed an application with the Federal Energy Regulatory Commission for a new section of pipeline to boost transportation capacity to the company's interconnect with Northern Border Pipeline Co. in western North Dakota.

The project would include 12 miles of 24-inch-diameter steel pipeline that would begin at the Spring Creek meter station and end at the Cherry Creek valve setting. The company said it has precedent agreements with Oasis Petroleum Marketing LLC and ONEOK Rockies Midstream LLC for 196,000 Dth/d and 10,000 Dth/d of incremental firm transportation service, respectively.

That was it. My comments/observations:

• huge, huge pipe: 2 feet in diameter -- think about that next time you see pipeline (water, natural gas, sewer, whatever) -- a 2-foot diameter pipe is one huge pipe
• total ND natural gas production: 2,000,000 or 2 million mcf/d 
• 206,000Dth/d = 200,000 mcf/d
• 200,000 / 2,000,000 = 1% -- one percent
• if my figures are correct, this pipeline will move about 1% of all the North Dakota natural gas produced in one day
• the connector is 12 miles; at $1 million / mile = $12 million dollars

This is pretty cool. If you are remotely interested in this project or just want to have some fun looking at FERC documents and maps of North Dakota, simply click on this http://www.wbienergy.com/docs/default-source/demicks-lake-ferc/wbi-demicks-lake-draft-resources-report-10.pdf?sfvrsn=4. A PDF will probably download on your desktop.

It downloads incredibly quickly suggesting it's in the cloud. It will download faster on a cloudy day.

I don't know how long the Bakken will last or how important the Bakken will be in the big scheme of things. All I know is that "they" aren't putting in 12 miles of 2-foot-diameter pipeline for upwards of $15 million for a one-year science project. Art Berman can say it's the "beginning of the end" for the Bakken and The Atlantic can say the boom is over and oilprice can say that US shale is not the answer and yada, yada, yada, but without question there's a lot going on in four little counties in western North Dakota, providing a lot of high-paying jobs for a long, long time, and for the most part not upsetting the gods to any significant extent -- at least the volcanoes in western North Dakota are not erupting, suggesting the gods can't be too mad at "us."

FERC Approves Columbia's West Virginia / Virginia NG Pipeline -- November 20, 2017

An earlier post:

March 17, 2016: the deal is announced -- TransCanada will buy Columbia for $10.2 billion. It looks like Warren Buffett missed a deal.

Today, from Platts: Columbia gets FERC sign-off for 1.3 Bcf/d WB XPress pipeline project.

Columbia Gas Transmission won certificate approval Friday from the US Federal Energy Regulatory Commission for the 29-mile, 1.3 Bcf/d WB XPress natural gas pipeline project.

The project will increase capacity along Columbia's existing WB Line, which runs bi-directionally through West Virginia and the northern part of Virginia.

The project will pick up gas around Braxton County, West Virginia, and deliver 500 MMcf/d eastbound into interconnects with Cove Point Pipeline and Transcontinental Gas Pipe Line as well as sending 800 MMcf/d westbound into interconnects with Tennessee Gas at Broad Run and existing Columbia infrastructure including Columbia Gas Appalachia Pool.

The FERC action came after Columbia parent TransCanada recently warned FERC of pressure on its schedules for WB XPress and its 171-mile, 2.7 Bcf/d Mountaineer XPress project without prompt approval, particularly as an environmental window controlling timing of tree clearing had already opened.

It's "funny" how things work out. Although the Keystone XL is important for a number of reasons, in the big scheme of things, with regard to pipelines, the big story for the US has been and will be natural gas pipelines.

US refiners need heavy oil -- two sources: Canada and Venezuela. But US refiners will get the heavy oil they need -- it may be just more expensive than necessary.

The real story right now: natural gas pipelines. And fortunately the current administration and FERC support natural gas pipelines. 

Natural Gas Pipeline Shortfall -- Platts -- November 20, 2017

Story here.

The Southeast natural gas market has a problem. Gas demand from LNG exports is expected to grow 10 Bcf/d the next five years, and in a high case, as much as 15 Bcf/d. To supply that growing demand, a massive buildout of pipeline capacity has been undertaken recently to move Northeast gas to the Southeast, with further capacity planned through 2019.

However, the actual new capacity from the Northeast that reaches these demand centers, specifically in Louisiana and East Texas, falls well short of the new demand.

Graphic:

It appears demand is 2.5x the current capacity.

More Natural Gas To Hit The Market; Companies Buying Oil From SPR For Trading / Profit --September 15, 2017

Updates

September 22, 2017: see RBN Energy note below regarding the Nexus pipeline. Argus Media is reporting that the pipeline has received a key water permit from the Ohio EPA.

The $2.1 billion Nexus pipeline project, jointly owned by Enbridge and Michigan utility DTE Energy, will transport Appalachian shale gas to Ohio, Michigan, and Ontario, Canada. One can assume this would not have happened had Hillary been elected president.

Original Post

Active rigs:

$49.92→	9/15/2017	09/15/2016	09/15/2015	09/15/2014	09/15/2013
Active Rigs	56	34	71	199	178

RBN Energy: ETP's Rover pipeline sends more Marcellus / Utica shale gas west.

In another key milestone for Northeast pipeline takeaway capacity expansions, Energy Transfer Partners’ beleaguered Rover Pipeline project began partial service on its Phase 1A portion on gas day September 1. The 3.25-Bcf/d project, which is due for completion in early 2018, is expected to provide relief for constrained Northeast producers while exacerbating oversupply conditions and gas-on-gas competition in the Dawn, Ontario, storage and demand market area and surrounding region.

Within days of initial start-up, flows on Rover ramped up to 700 MMcf/d, and both Ohio and overall Northeast production already have posted record highs since then as a result. Today, we take a look at the project, including initial flows and the expected timing of full completion.

It’s been a long, tumultuous road for ETP’s Rover Pipeline project so far. From its inception, the project was competing head-to-head for shipper commitments and investment dollars against the DTE Energy Co./Enbridge 1.5-Bcf/d NEXUS Gas Transmission project which would begin in the same general gas-supply area (eastern Ohio) and serve the same general markets (southeastern Michigan and Ontario). 

Then, in late 2016/early 2017, ETP found itself racing against the clock to secure its final certificate of approval and finish clearing trees along the project route before some endangered bats — yes, bats — came to roost . The developer managed to beat the clock on that, with the Federal Energy Regulatory Commission (FERC) issuing the certificate in early February 2017, just one day before the departure of Commissioner Norman Bay broke the quorum needed to get that final approval.

With the certificate in hand, Rover construction proceeded at break-neck speed, and for a while the project seemed unshakable — that is, until disaster struck in May 2017 in the form of a two-million gallon spill of fluid containing diesel in a protected wetland area near the Tuscarawas River in Stark County, OH, which prompted FERC to issue an order halting any new Rover-related drilling activity pending a third-party review.

Can't turn it off! Canada gas set to strike back against US shale as glut eases.

Canadian natural gas, locked in a fierce battle for market share with U.S. shale, may stage a modest recovery as output from some longtime producers wanes and pipeline maintenance ends.

While Canadian gas will almost always trade for less than U.S. gas -- due mostly to the cost of moving the fuel to markets in Texas and the American Midwest -- the discount recently widened to the most since 2005. The culprits are prolific new wells that are hard to shut off, along with outages on a network of pipelines that move gas around Alberta.

But with the pipeline repairs that caused those disruptions mostly completed and producers like Royal Dutch Shell Plc and Petroliam Nasional Bhd's Canadian unit dialing back on output in British Columbia, the glut of Canadian gas may ease. Higher prices would be a boon for Canadian producers that have been forced to cut costs and seek new outlets in the face of escalating competition from the U.S. shale gas boom.

Canadian gas, which is tracked using benchmark Alberta Energy Company prices -- AECO for short -- traded at $2.70 per million British thermal units less than the U.S. benchmark Henry Hub gas price on Tuesday, the steepest discount since December 2005. It narrowed to $1.33 on Wednesday.

That project, which is nearing completion, will increase the capacity of the northwest portion by about 700 million cubic feet a day, the Calgary-based company said in an emailed statement. Many sections are completed and operating again, and others will be back in service this month.

The work hurt Canadian prices because many producers weren't able to stop output. For some, the cost of shutting down and reactivating fields would have been more burdensome than taking a short-term hit. For other wells, a complex ownership structure and varying types of contracts with pipeline companies kept them producing even if one partner would have preferred to stop.

Buy low, sell high. Six companies buy oil from SPR. Data points:

• 14 million bbls sold/bought
• the six companies:
• BP Oil Supply
• Exxon Mobil
• Phillips 66
• Shell Trading
• Valero Marketing and Supply
• Macquarie Commodities
• bought: range from $46.91 to $47.91/bbl; slightly below current futures price of about $49.70

Reading between the lines: the companies had no need for the oil -- they were buying it for trading, arbitrage.

Job watch, link here:

• dropped: 14,000
• at 284,000
• affected by hurricanes
• better than the forecast of 300,000

Update On Texas Natural Gas Pipelines -- RBN Energy; Should The Samsung Galaxy Be Renamed The Samsung Supernova? -- October 10, 2016

Brent crude oil hits one-year high. WTI up 83 cents to $51.27. 

Presidential poll, USC-LA Times: I doubt this poll reflects most recent debate (but I could be wrong) but it does come late enough to "capture" the Trump comments in a 2005 (eleven years ago) video that has caused a bit of consternation among those interested:

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Back to the Bakken

Friday's NDIC daily activity report posted. Link here.

Three new permits:

• Operator: EOG
• Field: Parshall (Mountrail)
• Comments: three Wayzetta permits, sese 12-153-90 (one) and sese 6-153-90 (2)

Two permits renewed:

• HRC: a Fort Berthold permit in Dunn County
• Oasis: a Lydell permit in Burke County (years ago, at the height of the boom, the "consensus" was that not many wells would be drilled in Burke County; the county was not particularly noteworthy

Three producing wells completed:

• 29145, 350, Triangle, J Garvin Jacobson 150-101-8-5-8H, Pronghorn, t10/16; cum --
• 31031, 1,038, EOG, Shell 6-1930H, 2 sections, Parshall, t9/16; cum --
• 31032, 910, EOG, Shell 5-1930H, API 33-061-03666; 2 sections, Parshall, t9/16; cum --

For #31032

• 6.925 million gallons of water, 8% by weight sand, per FracFocus:
• 79.97% of what =  57,791,895 pounds of water = 72,266,968 pounds proppant (water: 1 gallon = 8.3454 lbs)
• 19.95% sand by weight = 14.4 million lbs of sand
• Later, from the NDIC: pending

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Active rigs:

	10/10/2016	10/10/2015	10/10/2014	10/10/2013	10/10/2012
Active Rigs	33	68	190	185	187

RBN Energy: update on Texas natural gas pipelines.

Over the next three years, 16 pipeline projects are in the works to add more than 14 Bcf/d of new take-away capacity to move Marcellus/Utica natural gas to the south and west, relieving takeaway capacity constraints that have plagued the Northeast since 2012-13. Much of this gas will be moved to the Gulf Coast, primarily via reversals of pipes that traditionally transported gas north and east, and will target rapidly growing LNG and Mexico export markets. But few of these pipeline projects get the gas all the way to those export outlets. The new supplies must traverse “Miles and Miles of Texas” (and Louisiana) to reach the export gateways and along the way deal with shifting production trends within the state, pipeline systems that are "telescoped the wrong way" constraining capacity of the Texas pipeline grid, and unique regulatory considerations associated with Texas intrastate pipelines.

Most of the pipeline projects that will provide desperately needed takeaway capacity out of the Marcellus/Utica region will either bring gas to states on the U.S. Gulf Coast or move gas into markets that have been traditionally served by Gulf Coast supplies, displacing those volumes back into the Gulf region.

Either way, significant volumes of gas are being pushed into two states that have historically been the most prolific U.S. sources of natural gas supply: Louisiana and Texas.  

Isn’t this a bit like bringing coal to Newcastle?  What are Louisiana and Texas going to do with all that incremental gas supply?  Some will be used to generate electricity, not only in Louisiana and Texas, but in a few states where gas will be dropped off along the way to the Gulf Coast. 

But most of the gas is targeted for exports into Mexico, where it will be used to generate power in that country, or is intended for LNG exports to meet demand in Latin America, Europe and Asia.

A few new natural gas export facilities have already come online over the past two years, including the first liquefaction trains at Cheniere Energy’s Sabine Pass LNG terminal in Louisiana and NET Midstream’s pipeline to Mexico, which together have ramped U.S. gas exports almost 2.0 Bcf/d over the past two years.

Many more export facilities are being developed, including liquefaction/LNG export capacity at Sabine Pass, LA; Freeport, TX; Hackberry, LA; and, Corpus Christi, TX, plus another half dozen new pipeline projects being built into Mexico connecting through Texas natural gas supply corridors. 

It is amazing isn't it, that 16 pipeline projects are in the works to move Marcellus/Utica natural gas since 2012-13, and the Obama administration is concerned about the DAPL? Wow. Time for someone to go. 102 days. Feels like an eternity.

I can't remember if I posted this one. Permian gas output remains high; processing capacity is being added. From RBN Energy while I was traveling.

Natural gas production volumes in the Permian Basin are very near the all-time record of 6.9 Bcf/d set last September, and crude oil and gas producers alike see nothing but blue skies for the highly prolific West Texas/Southeast New Mexico play.

The Permian already has a lot of gas processing capacity, but a good bit of it is older, and parts of the region—especially the super-hot Delaware Basin—need more of the big, efficient cryogenic plants that can process 100 to 200 MMcf/d. Today, we continue our review of gas production and processing in the biggest U.S. gas-producing region that is not named Marcellus.

The past two years have been a challenging time for crude oil and natural gas producers in most of the U.S., but much less so for exploration and production companies in the 75,000-square-mile Permian Basin. In rock ‘n’ roll terms, the Permian is a lot like Bruce Springsteen––it’s been a consistent producer (of both gas and oil) for decades, and it has more respect today than ever. (You might even call the Permian “The Boss” of hydrocarbon output.) Thanks to favorable production economics and multiple pay zones, output levels in the Permian dipped only slightly as oil and gas prices tumbled, and have since rebounded. As we said in Part 1 of our series, crude oil has always been the big draw for Permian producers, but most of the wells there also produce large volumes of liquids-rich or “wet” natural gas that needs to be processed to extract natural gas liquids (NGLs). In its latest Drilling Productivity Report, the Energy Information Administration (EIA) projected that the Permian would produce an average of nearly 6.9 Bcf/d in October (2016), only 30 MMcf/d less than it did at its peak a year ago. Gas production in the Eagle Ford in South Texas, meanwhile, is projected to fall below 5.6 Bcf/d in October—a 25% drop from its all-time  high in February 2015. (Of course, Appalachia, with the prolific Marcellus and Utica plays, still reigns supreme as far as gas is concerned, with almost 25 Bcf/d now being produced in the region based on RBN production numbers).

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Humor

From Reuters:

Saudi Arabia's Energy Minister Khalid al-Falih said on Monday that OPEC should not crimp oil supply too tightly and said he was optimistic a global production deal to limit supplies could be reached by November.

I doubt the last thing Khalid needs to worry about is OPEC "crimping"oil supply too tightly. LOL.

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The Market

Late-day trading: Dow 30 appears to hold; up 100 point; WTI still near $52

Mid-day trading: after going as high as 125 or thereabouts, the Dow 30 is up about 100 points:

The Opening: Dow 30 up 144 points. NYSE:

• new highs:  140-- Deere, Encana, Halcon WT, Halliburton, SM Energy, 
• new lows: 19

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The Apple Page

It looks like Samsung will halt further production of its "safe" Galaxy Note 7 until they get it figured out. I wonder if the Samsung Galaxy Note should be renamed the Galaxy Supernova.

From the AP today: new incidents defy Samsung's efforts to end smartphone woes. Also, it was reported that the US Supreme Court will take the case involving Apple vs Samsung. If I read it correctly, it was to determine the amount of money Samsung owed Apple for "copying" Apple's smartphone design.

It seems somewhat of a precedent for the US Supreme Court to take a case like this. I don't know; just a random thought. So, let's look it up -- here it is, over at CNET: "This is the first time a design patent case has been examined by the Supreme Court since 1800s." And yes, "What's at question is how much money one company has to pay for copying the designs of another. Samsung says an Apple victory would stifle innovation."

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Buffett Owns A Railroad And Is The 7th Largest Natural Gas Pipeline Operator In The US -- September 17, 2016

Ranked: Natural Gas Pipeline Owners

Link here. 

The narrative:

On September 6, Enbridge Inc. announced its purchase of Spectra Energy Corp. Enbridge currently operates 1,800 miles of large-diameter (24 inches or greater) natural gas pipelines in the United States. Before its acquisition of Spectra Energy, Enbridge was the 15th-largest holder of large-diameter U.S. natural gas pipeline miles (including co-owned pipeline), and Spectra ranked fourth in the nation with nearly 9,800 miles.

Enbridge/Spectra's newly combined pipeline holdings are still the fourth-largest overall.

Nearly 82% of large-diameter pipeline miles and 62% of all pipeline miles in the United States are owned by 10 companies.

Kinder Morgan Inc., with 32,000 miles of large-diameter pipeline, has more than double the mileage of TransCanada Corporation, which acquired Columbia Pipeline Group in July 2015.

The merger of Energy Transfer Equity LP (third-largest holder) and Williams Companies, Inc. (fifth-largest holder) that was recently canceled would have resulted in a large natural gas pipeline conglomerate ranked second to Kinder Morgan, which owns about 19% of all U.S. pipeline. 

The graphic:

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Valiant Ambition: George Washington, Benedict Arnold, and the Fate of the American Revolution

Nathaniel Philbrick

c. 2016

DDS: 973.4 PHI
Part II: Secret Motives and Designs

Chapter 7

The Bite of a Rattlesnake

Recap:

• Gates and Arnold in the north; Bemis Heights; Saratoga; to stop the Brits from getting to Albany
• Geo Washington in the south; along the Brandywine River to stop Howe from getting to Philadelphia

Now, in the North: 

Burgoyne surrenders, October 17, 1777; the Battle of Saratoga had changes the course of the war; American General Gates the victor but Benedict Arnold deserves the credit
by October 23, 1777, news of Burgoyne's surrender reached the eastern seaboard; celebrations from Boston to Portsmouth, NH
Geo Washington, King George III, and finally, Ben Franklin in Paris all got the "electrifying" news
Benedict Arnold laid up in bed for the fall / winter of 1777 - 1778; Arnold had been reinstated as major general
Now, in the South:
General Williams Howe (army) had accomplished almost everything he had planned
Howe had bested Geo Washington; the Brits had reached the rebel capital Philadelphia
but Americans had "barricaded" where the Scuykill flows into the Delaware, preventing his brother's (Admiral Howe) ships from reaching Philadelphia (which sites on the Delaware)
the river barricade known as a chevaux-de-frise
Howe unable to take Philadelphia; he resigned, fall of 1777
but Howe still tried to take Philadelphia
Americans' Fort Mifflin, at the confluence of the Schuylkill and the Delaware was the Americans' last hope
Geo Washington's HQ at Whitemarsh, PA, about 16 miles north of Philadelphia
Geo Washington rode south; wanted to see the Siege of Fort Mifflin
Geo Washington had entered one of the most difficult and frustrating periods of his life: Gates had succeeded at Saratoga; Geo Washington had lost Philadelphia
22-y/o Alexander Hamilton was Geo Washington's aide at the time
Gates and his top lieutenants were conspiring against Geo Washington
Fort Mifflin was finally lost, but American resistance was incredible -- p. 184
Brits take Philadelphia
Geo Washington "pondered" what to do next
Gates was the here of the day; mostly due to Benedict Arnold
Geo Washington not doing well; appealed to his generals for advice
Geo Washington did not attack Howe at Philadelphia; he knew that if he lost, the revolution might be over
Geo Washington establishes inter HQ at Valley Forge, 20 miles from Philadelphia
December 19, 1777 -- June 19, 1778: map of engagements, p. 186
 

Keystoned! Why I Love To Blog -- Reason # 84 -- April 25, 2016

Had I not been blogging for the past nine years, most likely I would not have paid attention to this story. Through RBN Energy I learned about the Constitution natural gas pipeline, and then on April 19, 2016, we learned that Bernie Sanders wanted this pipeline project keystoned. And today we learn he got his wish.

Keystoned! Bernie Sanders got his wish. New York state denies permit for the Constitution natural gas pipeline. 

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LNG Exports

This story has been told very, very well by RBN Energy over the past couple of years. Mark Perry now provides another nice summary. If the folks in New England and New York state don't want natural gas from the US, "we" can always ship it overseas. From Mark Perry:

Thanks to the shale revolution, the United States is now on its way to becoming a major exporter of liquefied natural gas (LNG). In February, two LNG cargoes left Cheniere’s Sabine Pass export terminal in Louisiana for Brazil and India.

And these are just the first LNG shipments. With five U.S. LNG terminals under construction with a combined export capacity of roughly 10 billion cubic feet per day, many more LNG shipments are on the horizon. After all the export facilities become operational, the United States will become the third largest liquefaction capacity holder in the world after Australia and Qatar.

No matter how you view a new era of LNG exports — whether looked at from its impact on the U.S. economy, our commitment to free trade, the energy security of our allies, or the potential for a significant reduction in carbon emissions as gas replaces coal in electricity production — the results will be positive and beneficial.

How times have changed. Less than a decade ago, energy analysts thought the U.S. was destined to become one of the world’s largest LNG importers. At the time, domestic gas production couldn’t keep up with demand.

The shale revolution, however, has been a game-changer. To be sure, there are those who have yet to grasp the consequences of this change. Studies from the U.S. Department of Energy as well as various think tanks show LNG exports as economically beneficial to the nation, not only providing thousands of construction jobs, but incentives for increased domestic gas production. All of this promises to be a boon to gas producers, rig hands, royalty owners and energy-rich states like Pennsylvania and Texas. Meanwhile, the notion that the price of natural gas might spiral upward as exports grow has been debunked.

By the way, ever wonder who is financing all those efforts to have fracking banned in the US? This doesn't take a degree in rocket science.