A Plethora of Pipelines

pipeline_constructionFour companies are talking about building gas pipelines through Virginia. How many are needed — and who decides?

by James A. Bacon

How many natural gas pipelines does Virginia need? A lot of people are asking that question as two projects — the Atlantic Coast Pipeline and the Mountain Valley Pipeline — are actively developing routes between the Marcellus shale gas fields to the northwest and fast-growing markets to the south. Meanwhile, the Williams Companies, owner of the giant Transco pipeline, is talking up the Appalachian Connector, and Columbia Gas Transmission says it might upgrade an existing pipeline terminating in Northern Virginia.

All told, the four projects would add a capacity of 6.8 billion cubic feet per day, or roughly 200 billion cubic feet monthly. While much, if not most, of that gas would be destined for markets outside Virginia, that’s still a tremendous amount of capacity. By way of comparison, existing pipelines deliver to Virginia between 20 billion and 60 billion billion cubic feet monthly, depending on the time of year.

The question of how much is too much has become an urgent one as landowners in the path of the proposed pipelines resist survey crews from entering their property and vow to resist acquisition of their land by eminent domain. To acquire right of way using eminent domain, they say, companies must articulate a compelling public need to the Federal Energy Regulatory Commission (FERC). While there may be a need for some new pipeline capacity, they contend, it’s hard to justify all four projects.

“We’ve got a big infrastructure build-out proposed,” says Greg Buppert, staff attorney for the Southern Environmental Law Center (SELC), who is tracking the issue. “My suspicion is that some but not all of this capacity is needed. There is even a possibility that existing infrastructure can meet the need.”

But some say the market is self-limiting. Pipeline companies won’t spend billions of dollars adding new capacity unless they get enough long-term contracts to ensure they can pay for a project. If there is insufficient demand to support all four pipeline projects, all four pipelines will not get built.

For decades, Virginia has relied mainly upon two companies, the Williams Companies and Columbia Gas, to deliver gas to the state. Williams operates the high-capacity Transco pipeline — energy journalist Housley Carr refers to it as “the gas-transportation equivalent of an eight-lane highway”– connecting the Gulf of Mexico gas fields with New York by way of Virginia and other Atlantic Coast states. Columbia Gas runs a parallel pipeline highway west of the Appalachias, which serves a multi-state distribution system that feeds into Virginia via West Virginia.

Traditionally, most gas from both pipelines has come from the Gulf of Mexico. But fracking has turned North American energy economics topsy turvy. Gas fields tapping the Marcellus and Utica shale deposits in West Virginia, western Pennsylvania and Ohio are reputed to contain as much natural gas as Saudi Arabia. Marcellus gas is abundant and cheap, and gas pipeline companies have been scrambling to develop new markets, mostly in the U.S., but also for foreign markets by means of Liquefied Natural Gas.

The explosion in supply coincides with a surge in demand, especially from electric power companies. In two major waves of regulation in recent years the Environmental Protection Agency (EPA) has mandated power companies to reduce their toxic emissions from coal-fired power plants and then, with final rules issued early August, to reduce emissions of carbon dioxide by 32% nationally. In both cases, utilities are shifting en masse from coal to natural gas. While renewable sources such as solar and wind power are expected to gain electricity market share, industry officials say they must be backed up by gas generators to take up the slack when the sun doesn’t shine and the wind doesn’t blow, so demand growth for renewables actually supports demand growth for natural gas. Meanwhile, gas companies foresee a kick in long-term demand from a growing population and economy, especially among manufacturing operations seeking to tap some of the world’s lowest cost energy and chemical feedstock.

“Virginia is in need of new natural gas transmission that can get these new reserves to the parts of Virginia that need it the most,” says Christina Nuckols, deputy communications director for Governor Terry McAuliffe. “Hampton Roads is considered an energy cul-de-sac where natural gas capacity constraint has been an issue for years.  Particular counties in central and southern Virginia also have reported on numerous occasions that they lose out on manufacturing-related economic development opportunities almost immediately because they cannot provide access to natural gas.

“With any new market opportunity, there are going to be a number of companies looking to find success,” she says. “All of these proposed pipeline projects are recognition that Virginia is in need of additional natural gas capacity and the infrastructure to provide it.  It remains to be seen which projects will get approval from the appropriate entities.”

Here are the major projects proposed for Virginia:

acp_route2

Source: Dominion. Click for larger image.

Atlantic Coast Pipeline. The Atlantic Coast Pipeline (ACP) is a partnership of four major energy companies: operating partner Dominion Resources, Duke Energy, AGL Resources, and Piedmont Natural Gas. The pipeline would originate in Harrison County, W.Va., and run 550 miles to southern North Carolina, with 70-mile spur to Hampton Roads. Capacity would be 1.5 billion cubic feet per day. The ACP would interconnect with the Transco pipeline in Buckingham County, Va., allowing gas to flow north or south on the Transco system from there.

When describing their investment in the $5 billion project, Dominion officials emphasize the growing electric utility market for natural gas. Since he took on his job as CEO of Dominion Generation Group, says David Christian, the company has sold, closed or converted to gas 21 coal units nationally, several of them in Virginia. To take up the slack, Dominion opened a new gas-fired unit in Warren County, Va., in 2014 that burns roughly 250 million cubic feet of gas per day. Dominion is building another gas-fired plant just like it in Brunswick County, Va., which will burn a comparable amount, and has plans, if approved by the State Corporation Commission, to build another similarly scaled plant in Greenville County, Va.,  by 2018. Some of that gas can be reliably supplied with existing pipelines but not all.

delivery_points

This map shows the main delivery points in the proposed Atlantic Coast Pipeline. Click for detailed image.

Dominion has contracted in binding agreements to take roughly 300 million cubic feet per day of gas from the ACP pipeline. Duke Energy, which is undergoing a similar transformation, has committed to take about 725 million cubic feet per day, while Piedmont Natural gas will take 160 million cubic feet, Virginia Natural Gas 75 million cubic feet, and the Public Service Company of North Carolina 100,000 million cubic feet, according to a May 2015 data resource report. (The resource report measures gas quantities in decatherms. A decatherm contains roughly the heat content of 1,000 cubic feet of natural gas. I have translated the numbers into cubic feet  to make the numbers in the article easier to compare throughout.)

In total, 91% of the pipeline capacity is contracted for. The unsubscribed capacity will be awarded to other parties in accordance with FERC policies. While the ACP cannot say where that gas might be shipped, the report states emphatically that the pipeline “is not designed to export natural gas overseas.” The map above shows where the gas will be delivered.

While there is still spare capacity in the existing pipeline system, Dominion foresees a need for additional capacity to meet continued demand growth. “We project the demand curve, add a reserve margin [for safety], and we see a gap in the future,” says Christian.

Another advantage of having another pipeline, say Dominion officials, is the ability to diversify sources of gas supply. Right now, Marcellus gas is cheaper than the Gulf of Mexico gas that Dominion burns. There’s no guarantee that Marcellus prices will stay lower than Gulf prices, especially if exports of Liquefied Natural Gas take off, but to Dominion’s way of thinking, two sources are more stable and reliable than one. Another advantage is the ability to draw upon an alternate source of supply should the transport of gas from offshore drilling rigs in the Gulf Coast be disrupted, as it was after Hurricane Katrina; gas prices spiked until the Gulf infrastructure could be restored. A Dominion-commissioned study by ICF International concluded that consumers and businesses in Virginia and North Carolina would save an estimated $377 million a year in lower energy costs over 20 years thanks to the pipeline.

mountain_valley_pipeline

Source: Mountain Valley Pipeline. Click for larger image.

Mountain Valley Pipeline. The Mountain Valley Pipeline (MVP) is a partnership of four gas companies: operating partner EQT Corporation, NextEra Energy, WGL Midstream and Vega Midstream. The pipeline would run 294 miles from northwestern West Virginia, skirt south of Roanoke, and hook into the Transco Pipeline at compressor station 165 in Pittsylvania County.

The MVP, expected to cost between $3 billion and $3.5 billion, has secured 20-year contracts to provide at least 2 billion cubic feet per day of firm transmission capacity. With a connection to the existing Equitrans system in West Virginia, the company says, MVP will address infrastructure constraints holding back development of natural gas in the Marcellus and Utica shale plays, while also providing supply diversity to natural gas consumers across the Southeast.

Historically, Transco has moved about 10% of the nation’s natural gas supply. But as new pipelines flood New York and other northern markets with cheap Marcellus gas, Transco likely will lose market share there. While Transco mainly moved gas moved south to north in the past, parent company Williams is working to make the pipeline bi-directional. This new flexibility allows the MVP pipeline to reach a much wider market than it could on its own.

One of the MVP partners, WGL, already moves significant volume on Transco’s mainline pipeline. In December, according to the Roanoke Times, the company announced a sales agreement to export natural gas to India via Dominion’s Cove Point Liquefied Natural Gas facility in Maryland, which is served by Transco, spurring controversy in western Virginia where local citizen groups have contested the public necessity of the pipeline. However, in a May 2015 hearing, Paul Friedman, FERC environmental project manager, insisted that Mountain Valley gas would not be exported. Said he:

That will not happen, and I’ll explain why: Mountain Valley has not applied to either the FERC or the U.S. Department of Energy for permission to export natural gas. Without those applications and our permission, they cannot export natural gas.

MVP is in the process of determining the optimum route for the pipeline. The company is conducting civil survey work to identify sensitive environmental and cultural sites that need to be avoided, says MVP spokesperson Natalie Cox.

Columbia Pipeline Group network in Virginia and West Virginia.

Columbia Pipeline Group network in Virginia and West Virginia. Click for larger image.

WB XPress. Columbia Pipeline Group which transports an average of 3 billion cubic feet per day of natural gas through a 10-state pipeline network, is proposing a major upgrade to an east-west pipeline between Virginia and West Virginia. The project would boost capacity by 1.3 billion cubic feet  daily through the installation of a compressor station in Fairfax County, compressor upgrades along the system, construction of 26 miles of replacement pipeline in existing corridors and 2.9 miles of new pipeline. The stated purpose is “to meet growing market demands in western West Virginia and northern Virginia.”

Because the WB Xpress project would utilize existing rights of way for the most part, it would avoid the challenge encountered by the Atlantic Coast Pipeline and Mountain Valley Pipeline of requiring land surveys and right-of-way acquisition.

In July, the Federal Energy Regulatory Commission began soliciting public comments in preparation of an environmental assessment.

appalachian_connectorThe Appalachian Connector. The Williams Cos., owner of the Transco pipeline, is in the “early stages” of performing  desktop analysis of running a pipeline between Clarington, Ohio, and Transco’s compressor station 165 in Chatham, Va. The pipeline, as currently envisioned, would move up to 2 billion cubic feet of gas per day by late 2018. The project is unique, says that company, in that it is the only project currently proposed that would tap the western Marcellus and Utica regions to access the Transco pipeline. The route has not yet been identified, and the company has not yet started the process of conducting field surveys.

“We’re evaluating market interest,” says Chris Stockton, a spokeperson for Williams Transco. “We’ve had some interest — customers have come to us about connecting to that Utica supply. We’re determining if there’s enough market support. We can’t build a pipeline on spec. We need contracts from customers willing to pay for this multibillion dollar project.”

How much is too much? The Southern Environmental Law Center is skeptical that a need for all this capacity can be justified. All of a sudden, four big pipeline projects have sprung to life in the past year or so, says Buppert, the SELC attorney following the issue. SELC got involved because the Atlantic Coast Pipeline would run through the George Washington National Forest, which SELC has expended considerable resources to protect from industrial development.

“FERC is supposed to balance the need against the harm and decide whether or not to approve the project,” Buppert says. “A company can come in and say that it has a bunch of contracts, and FERC says, ‘Great, we can check the box for need, and that’s the end of the analysis.’ … My suspicion is, the need won’t justify all the projects that have been proposed. We have engaged an expert firm to answer that question.”

Buppert thinks there is an opportunity to persuade FERC to do something it has never done before — examine more than one project at a time. “Usually, FERC looks at its projects in isolation,” he says. “That might have worked when pipelines were rare occurrences. I think we can make the case with these four projects in Virginia that the agency needs to look at these in a more holistic way. If there’s some infrastructure build-out required, identify the optimal way to do that — the least harmful route.”

Some proposed pipelines may be able to utilize more existing rights of way than others, says Buppert. “What we’re pushing for is a holistic vision for pipeline development in the whole region. … You wouldn’t build highway infrastructure this way. Pipelines could use effective planning as well.”

But others argue that market forces will minimize the risk of excess capacity getting built. Pipeline companies require major up-front commitments from customers before sinking billions of dollars into a project. If those commitments are not forthcoming, a pipeline will not get built.

Last year Spectra Energy Pipeline announced that it was evaluating an interstate gas pipeline to deliver up to 1.1 billion cubic feet daily to markets between Pennsylvania and North Carolina, including Virginia, a project that was seen as competing with the Transco pipeline. But Spectra suspended development of the project, says spokesman Arthur Diestel. Confidentiality agreements prevent him from explaining why, he says.

“There’s no way all four [Virginia] pipelines will get built,” says the former CEO of a Virginia-based gas trading company, who asked to go unnamed for personal reasons. “Well into the process [one or more players] may decide to suspend further development of the project because they haven’t been able to get a full commitment. It’s a gut feeling — it just doesn’t seem there’s enough demand out there to support that many.”

Of the four proposed pipelines, the Atlantic Coast Pipeline and Mountain Valley Pipeline are the farthest along in the regulatory process. Both companies are surveying land and plotting routes. The demand for natural isn’t theoretical, says Jim Norvelle, director-media relations for Dominion Energy. “Our pipeline is being built for customers who have already signed a 20-year contracts.”

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41 responses to “A Plethora of Pipelines

  1. Jim did an awesome job on this and deserves congratulations for his effort.

    CONGRATS and THANK YOU!

  2. Yes, good job, Jim. One correction. Cove Point is not in Baltimore, it’s in far southern Maryland on the western shore of the Chesapeake. You may have been thinking of Sparrow’s Point which at one time was the site of a proposed LNG facility. That one is in Balto.

  3. I think it’s a bad idea to export gas. We don’t really know how long the Marcellus shale will actually last – and we don’t have any kind of an alternative plan if it becomes scarce and expensive or just runs out.

    The folks who would export it have a profit motive. They could care less what happens if it gets depleted. By that time- they’ve made their money and will move on to whatever the next profit opportunity is.

    and those folks certainly should not be benefiting from eminent domain.

    Natural Gas is a vital strategic fuel that underpins the strategy to move away from coal but more than that – it’s the fuel needed to modulate the variability of wind/solar.

    Without natural gas – we have no easy way to use wind and solar nor do we have a way to meet the gap between base load plants and peak power demands.

    there also a perverse irony here also with regard to having 4 competitors in a state that relies on certificates of public need…

    You have two existing long-term operators of gas pipelines willing to use existing rights of ways with some add on new connections and you have two new players who essentially want to recreate the wheel and build their own competing infrastructure.

    who sorts this out. what’s in the best interests of electricity users and other Virginia consumers of gas?

  4. For the first time perhaps ever, I find I may be in slight disagreement with Jim, or at least the folks he’s citing (though as others have pointed out, he did a bang-up job on the article.

    My disagreement goes to the argument that these projects are self limiting, that the pipeline companies wouldn’t spend gazillions if it wasn’t needed. I think a similar argument was made in New London CT, yet the Kelo’s property was taken by eminent domain, absolutely nothing was built, and the Kelos lost big-time. Probably at least one pipeline would be built in this case, but four? I think I prefer the approach that full due diligence be done before everybody starts “taking” and the digging begins.

    • geeze CrazyJD – are you actually advocating that the Govt figure out what to do?

      To do that Certificate of Public Need process?

      SHOCKING!

      here’s what I think.

      The govt only gets involved and grants ED – AFTER the companies have obtained 95% of the right-of-way through willing seller/willing buyer.. OR the company agrees to only provide the gas to public service utilities.

      acquiring right-of-way through voluntary transaction is not unattainable… it’s very doeable.

      ” The project was accomplished within budget and with
      nearly 100% voluntary acquisition. For REX West, voluntary
      acquisition was 99.7% successful. While REX East proved to
      be a more difficult area to acquire and the acquisition costs
      were somewhat higher, CLS still accomplished voluntary
      acquisition at the rate of 99.2%

      https://www.irwaonline.org/eweb/upload/mar_Web_RockiesExpress.pdf page 23

      CLS is a right-of-way acquisition company – Contract Land Staff, LLC

  5. Something is wrong with your numbers. You say ACP “Capacity would be 1.5 billion cubic feet per day.” I agree with this number and the numbers you have for pipeline capacity as I have seen similar numbers. About 2 billion/day per 42″ pipeline.
    But then you say “Dominion has contracted in binding agreements to take 300 billion cubic feet (bcf) per day of gas from the ACP pipeline.” So if the pipeline carries 1.5 billion but Dominion has contracted 300 billion out, then they have oversold by 200 times. All your numbers for power plants and the amount Dominion has contracted should be in million cubic feet, not billion. Please correct this because the article now makes it seem like we need about 20o MORE 42″ pipelines to accomodate even ONE power plant let alone all the plants you site.

    Thanks, otherwise good article.

    • Thanks for pointing that out. I’ll get right on it. I made an incorrect translation of decatherms into bcf (billion cubic feet).

      • Finally – none of them appear to be going to the Hampton area which I’ve always found puzzling because of a couple of things: (The ACP has a spur to the south Hampton Roads area)

        1. – Dominion says there is/will be a peak load problem (The problem in not a peak problem, it is a baseload problem given local coal/oil unit retirements. Power needed round the clock)

        2. – they’re closing a base load coal plant (Yes, more than one)

        3. – they’re proposing to replace the power by essentially re-routing Surry to cross the James and replacing the existing Surry area with a couple of gas plants. (Not that simple. DVP is adding gas plants in Brunswick and Greensville County, where that spur line is to run, and will be delivering that power, along with some from Surry, to the Peninsula through that proposed power line)

        but where is the gas plant for Hampton? (In Brunswick and Greensville Counties, where land is cheaper and available and local authorities want the plants.)

        don’t they need a peaker plant to supplement baseload for peak power demands in Hampton? (The have plenty of peaking capacity, but without additional transmission, no way to deliver it to the peninsula.)

      • The Dominion Cove Point LNG facility is a former LNG import terminal that is now being converted to export LNG. A map on Dominion’s website indicates that it is served by a Dominion pipeline that begins at Dominion’s gas storage facilities in the Marcellus in Pennsylvania. They could also connect to other natural gas transmission lines (perhaps Transco).

        Whew – that’s the last one. Sorry to bombard you. If people have questions on what I have written, I’ll try and respond today. Otherwise I won’t be able to connect again until Monday. Great discussion. thank you Jim.

    • I had noticed that also but failed to point it out… but good to have someone actually checking the numbers …

      The Maps are excellent and a fifth map combining all 4 into an overlay showing existing pipelines and proposed WITH the numbers for each would be especially illuminating…

      Finally – none of them appear to be going to the Hampton area which I’ve always found puzzling because of a couple of things:

      1. – Dominion says there is/will be a peak load problem

      2. – they’re closing a base load coal plant

      3. – they’re proposing to replace the power by essentially re-routing Surry to cross the James and replacing the existing Surry area with a couple of gas plants.

      but where is the gas plant for Hampton?

      don’t they need a peaker plant to supplement baseload for peak power demands in Hampton?

      Again to compliment Jim – his journalistic efforts are ever bit as good as and perhaps better than most of the more traditional news organizations covering this issue.

      I’d give a Hat Tip also to VPAP’s new VA News aggregation service which does a good job of scouring the news reports across the state each day.

  6. I agree. This is an excellent article.

    It raises a host of important questions on the place and roll of gas fired plants, and many of the issues earlier discussed to date on this website.

    • I have been traveling, first chance to get to a computer. Well done article Jim. Thank you.

      It would be wonderful if FERC would take a comprehensive look at this issue. Not just the pipeline routing but the overall demand cases and possible alternatives. They are not known as being excellent forecasters. By 2006, FERC had received 43 applications to construct new U.S. liquefied natural gas (LNG) import terminals, and a total of 11 facilities were ultimately built in anticipation of a large increase in LNG imports that never materialized. Unfortunately, substantial investments were made, degradation of natural areas occurred, property might have been seized from unwilling sellers, and ultimately, customers of these energy companies paid higher prices to cover the failed investments.

      It would seem most sensible to use existing pipelines and rights-of-way as much as possible. In a February 2015 report titled “Natural Gas Infrastructure”, the U.S. Department of Energy (DOE), the parent agency of FERC, concluded that no new pipelines are needed to supply Virginia and the Carolinas.

      The DOE explains how existing pipelines can be utilized to serve higher demand in Virginia. “Flow reversal [of existing pipelines] is also projected southward out of the Marcellus to serve markets in the Southeast. Pipelines that currently bring natural gas from the Gulf region to the north are projected to reverse flow so that Marcellus production can serve the Virginia and Carolinas markets”. This is the Transco pipeline to which they are referring. The proposed expansion of this pipeline is expected to provide 1.8 – 2.0 billion cubic feet per day (bcf) of additional capacity, which is greater than the 1.5 bcf provided by the Atlantic Coast Pipeline. There is a spur from this pipeline that also extends into North Carolina very near where the Atlantic Coast Pipeline is proposed to enter.

      Even if more coal plants are retired than expected, there is adequate capacity in existing pipelines. The DOE report states, “. . . the projected flow volume in the model in 2030 rises to 60 percent in the Intermediate Demand Case and 61% in the High Demand Case, compared to 57 percent in the Reference Case.”

      The WB Xpress development of the Columbia Gas pipeline adds 1.3 bcf of additional capacity, requiring only 26 miles of replacement pipeline and 2.5 miles of new construction. This serves northern Virginia and currently connects to the AGL (Virginia Natural Gas) pipeline which serves the Hampton/Norfolk area.

      Clearly, using pipelines that already exist with sufficient capacity to serve the needs projected for the Atlantic Coast Pipeline would be far superior to building 550 miles of new pipeline which requires a $5 billion investment and creates substantial adverse impacts. Using these two existing pipelines would also avoid the expense and damage associated with the planned Mountain Valley pipeline.

  7. Since these proposals are issues of interstate commerce, not intrastate who gets to play God and decide which if any are not needed? Are there national security issues involved?

    This is not a frivolous question; I’d really like to know how this is going to work.

    • The Federal Energy Regulatory Commission (FERC) decides.

      • “Gas fields tapping the Marcellus and Utica shale deposits in West Virginia, western Pennsylvania and Ohio are reputed to contain as much natural gas as Saudi Arabia. ”

        There has been a great deal of hype and overstatement regarding U.S. natural gas reserves. The current reserves in all of the United States are 9,860,000,000,000 cubic meters compared to 8,600,000,000,000 for Saudi Arabia. The Marcellus is just a portion of the total U.S. reserves although it is currently producing the most natural gas of any region (about 20% of dry gas supply). The Haynesville formation was by far the most productive shale gas formation in the U.S. but it has played out in a matter of a few years.

        Early published numbers regarding shale gas identified “resources” for various shale plays. The numbers were so large that it caused people to exaggerate and say that we now had a “100 year supply” of natural gas. In the oil & gas industry, resource means the amount of gas or oil that remains underground, and reserve means what could be produced from the resource. Only a portion of the resources could be recovered technically. Only a portion of the technically recoverable resources could be produced economically. Only a portion of the economically producible resources could be converted into supply. This economically producible supply is called a reserve. A reserve is only truly meaningful when you indentify the price that is used to establish its size. The volume of the reserve for gas selling at $4 mcf is smaller than the reserve for gas at $10-$12 mcf. If you want more gas you will have to pay a higher price for it. An industry insider has noted, “We can have cheap natural gas or we can have plentiful natural gas, but we’re not going to have cheap, plentiful natural gas.”

        The economic pressure on both shale oil and shale gas drillers has dramatically improved drilling techniques and efficiencies. Developers in all formations are highly leveraged with debt and must keep drilling to pay off their loans even if they are drilling at a loss. Cash flow is king. Necessity has pushed them to be more productive and it has paid off. There is good evidence that we have hit a peak of productivity in the Marcellus and productivity per well has begun to decline since the second half of 2014. However, with their businesses at stake, who knows what productivity gains are still to come.

        This uncertainty regarding long-term natural gas prices makes the rush to send our affordable gas overseas a bit suspect. Dominion claims to have 20-year take or pay contracts with customers in India and Japan for their Cove Point LNG facility. If gas prices rise in the next 5-10 years, I don’t know whether this is still profitable for Dominion. LNG exports will cause gas prices to rise faster for domestic uses however, such as gas-fired electrical generation and the typical uses of natural gas.

      • “While renewable sources such as solar and wind power are expected to gain electricity market share, industry officials say they must be backed up by gas generators to take up the slack when the sun doesn’t shine and the wind doesn’t blow, so demand growth for renewables actually supports demand growth for natural gas.”

        This is certainly an important use of natural gas – one that we should protect rather than squandering our supply of gas by sending it overseas for a short-term profit. If gas prices become too high, alternatives such as affordable storage (batteries, etc.) coupled with ever cheaper renewables, could replace the need for many of these gas-fired electrical generators.

        Adequate models exist to look at various scenarios. Who is looking at the big picture? All I see is many companies rushing to extend the 20th century paradigm of building facilities for a long-term stream of revenues without a careful evaluation of the risks of stranded costs, high utility bills, reduced economic activity, etc.

        A well researched alternative plan exists which outlines a scenario which allows us to have an economy 158% larger than we have currently, with no increase in energy use and no use of coal or oil by 2050. Far fetched? Perhaps, but what if we only got halfway there. That is far better than the path we are on.

      • “Meanwhile, gas companies foresee a kick in long-term demand from a growing population and economy, especially among manufacturing operations seeking to tap some of the world’s lowest cost energy and chemical feedstock.”

        Affordable gas and natural gas liquids give an advantage to U.S. industries over their overseas competitors. Jobs are just beginning to move back to the U.S. for industries which rely on these feedstocks. These U.S. manufacturers think the rush to burn up our affordable natural gas in electric power plants or sending it overseas is a bad idea.

        Paul Cicio, president of the Industrial Energy Consumers of America (IECA), a nonpartisan association of leading manufacturing companies with $1 trillion in annual sales and more than 2,900 facilities nationwide, believes that exporting LNG could threaten Virginia’s 231,073 manufacturing jobs and jobs throughout the nation. The concern is that high energy prices could stop the Virginia manufacturing renaissance that has created so many new jobs. Mr. Cicio says that our rush to export our secure supply of affordable natural gas “has unsettling consequences for manufacturing industries that depend upon affordable natural gas and power – but in fact, it will also substantially raise costs for all consumers and have detrimental effects to the economy long-term.” He urged the Obama administration to avoid any further export terminal approvals until the DOE defines whether gas exports are in the public interest.

        The CEO of Dow Chemical, Andrew N. Liveris, agrees. In a press release, he said, “The report issued by the DOE on liquefied natural gas (LNG) exports is flawed, misleading, and based on outdated, inaccurate and incomplete economic data.” “The report fails to give due consideration to the importance of manufacturing to the U.S. economy. Manufacturing is the largest user of natural gas in the U.S., and creates more jobs and more value to the U.S. economy from natural gas than any other sector.”

        Australia might be a cautionary tale for the U.S. When the country began to use its plentiful natural gas for applications beyond its historical uses, such as the export of LNG, domestic prices tripled, with prices still rising. An article in the Oil & Gas Journal notes, “Australian manufacturers are closing their doors and power companies and industries are taking action to switch from natural gas to coal.” As the cost of home heating and cooling has soared, “Domestic consumers are suffering because Australian public policymakers failed to take care of the people who have entrusted them to represent their interests. This has turned Australia’s natural gas from a strategic asset to a liability for domestic consumers.”

        The Australian government expected that supply would keep pace with the non-traditional demands such as exports. The same assumption underpins U.S. policy makers push for more gas-fired power plants and LNG exports. The U.S. Department of Energy’s own studies predict that increased demand for natural gas for LNG exports would “reduce wages and disposable income, increase energy prices, (and) curb investment in the U.S. economy (less investment in manufacturing).” The energy companies would be the ones to benefit from such a plan, “while the vast majority of the people in the country will lose economically”.

      • “Dominion is building another gas-fired plant just like it in Brunswick County, Va., which will burn a comparable amount, and has plans, if approved by the State Corporation Commission, to build another similarly scaled plant in Greenville County, Va., by 2018. Some of that gas can be reliably supplied with existing pipelines but not all.”

        I am puzzled by this statement. If there was not an adequate supply of gas to the Brunswick plant (and later the Greensville plant) from their connection to the Transco pipeline, how could the SCC approve the construction of the plant? There is no guarantee that the Atlantic Coast Pipeline will be built. How could the SCC approve a billion+ investment if there was no guarantee of an adequate fuel supply over the life of the plant?

        Besides, with the proposed increase in capacity of the Transco pipeline (that exceeds the capacity of the Atlantic Coast Pipeline) plenty of gas would be provided to serve Dominion’s plants without the need for the construction of a new pipeline. The issue seems to be that Dominion would rather pay themselves to transport the gas than pay someone else (the same for Duke Energy). This does not seem to justify the investment and damage related to building a new pipeline.

        If you note the secured contracts for the Atlantic Coast Pipeline, nearly all of them are from the owner’s of the pipeline. This is great for proving “need” to FERC, but diverts attention from the fact that existing pipelines (that are proposed to add capacity greater than the ACP) are located precisely in the areas intended to be served by the Atlantic Coast Pipeline.

      • “Another advantage of having another pipeline, say Dominion officials, is the ability to diversify sources of gas supply. Right now, Marcellus gas is cheaper than the Gulf of Mexico gas that Dominion burns. There’s no guarantee that Marcellus prices will stay lower than Gulf prices, especially if exports of Liquefied Natural Gas take off, but to Dominion’s way of thinking, two sources are more stable and reliable than one. Another advantage is the ability to draw upon an alternate source of supply should the transport of gas from offshore drilling rigs in the Gulf Coast be disrupted, as it was after Hurricane Katrina; gas prices spiked until the Gulf infrastructure could be restored.”

        Both the Transco pipeline and the Columbia gas pipeline (WB Xpress) will be able to transport gas from the Gulf Coast and the Marcellus. The Atlantic Coast Pipeline would not provide any additional flexibility or redundancy.

      • “A Dominion-commissioned study by ICF International concluded that consumers and businesses in Virginia and North Carolina would save an estimated $377 million a year in lower energy costs over 20 years thanks to the pipeline.”

        According to Atlantic Coast Pipeline Benefits Review produced by ICF, the long term benefits of the pipeline accrue primarily from one item: the less expensive price of shale gas from the Marcellus formation (represented by the Dominion South Hub price) compared to the standard U.S. price at Henry Hub. ICF projects that this price differential translates into price savings for both natural gas and electric consumers. They propose that this savings could also trigger stimulus effects that create long-term jobs, although the report never explains how this would occur.

        Henry Hub is a distribution hub in Louisiana which interconnects with nine interstate and four intrastate pipelines. Natural gas coming from most of the major drilling locations passes through Henry Hub. Onshore and offshore conventional gas coming from the Gulf Coast, gas from recently developed fields in Colorado, Wyoming and North Dakota, and gas from various shale gas plays, especially in Louisiana, Texas, Arkansas and Oklahoma, all pass through Henry Hub. As a result, the price at Henry Hub is generally considered to be the primary price set for the North American natural gas market, especially for futures trading. Hubs in other regions usually set similar prices, although differences can exist (often temporary) where there is a significant difference in supply or demand. ICF is presuming the situation that currently exists at the Dominion South Hub will be a permanent one. We should understand why this difference currently exists and determine if it is likely to continue.

        The Dominion South Hub is near where 11,000 miles of gathering pipeline that Dominion has recently installed in Pennsylvania and West Virginia terminate in large gas storage facilities and natural gas liquids processing plants (also owned by Dominion). This pipeline network, similar to those developed by other energy companies, takes gas from the wellheads at the drilling pad sites where millions of gallons of water along with sand and particular chemicals are pumped under very high pressure into deep wells to fracture the shale and release gas through the tiny crevices created by the fracking.

        In the 1990’s natural gas was cheap – $2 per thousand cubic feet (mcf). In the easy money days of the early 2000’s the economy picked up; demand exceeded supply; and we started to import natural gas which caused prices to rise to over $13.50 mcf in 2008. Drillers rushed in to the known but undeveloped shale gas formations in hopes of substantial gains. They soon discovered that the shale gas wells declined significantly within the first few years of production. Their experience with drilling for conventional gas was that wells would decline slowly over several decades.

        Developers now had big loans to pay for leases and drilling rigs but much lower than expected revenue because of the rapid well declines. They decided to keep drilling (even at a loss) to generate the cash to pay the loans. All of the drilling greatly increased supply, the economy crashed after the housing crisis, demand sank and prices began to fall.

        Wall Street investment bankers stepped in to seize a profit opportunity. They repackaged the drilling leases in much the same way they had repackaged mortgages and resold them for a profit. They resold the leases using drilling history from early profitable wells and said that the parcel was “proved up” and thus a “safe investment”. As worldwide oil prices peaked in 2011, foreign investors rushed in to buy up these leases thinking they were gaining access to a long-term supply of cheap gas.

        The second group of developers repeated the experience of the first. Rapid decline in production and too few wells were actually profitable. They got on the same treadmill and kept drilling wells to generate cash to meet their debt service. All of these wells added to overall supply and the surplus drove prices lower still. By January, 2012, prices had plunged to under $3 mcf – far too low for operators whose breakeven costs were about $4 – 6 mcf. Many took huge write-downs of their shale gas investments.

        Investment bankers made more money doing mergers and acquisitions with the now ailing companies, to which they had recently sold leases labeled as “safe investments”. Wall Street investment banks continued to promote shale gas plays, despite the experience of developers.
        Drillers became very efficient at working the “sweet spots”. Technology advanced so more wells could be drilled from a single drilling rig, making drilling more productive and less expensive.

        Although supply expanded by 5.2 billion cubic feet per day (Bcf/d) in the past year, demand grew by only 0.9 Bcf/d. Normally, production would be curtailed until supply more closely matched demand and the price increased. But the need for cash flow prevailed and more wells were drilled.

        Natural gas prices were $2.65 mcf in June 2015; 40% lower than a year earlier largely due to the excess production from Marcellus. The lack of connections from the Marcellus to existing pipelines kept the gas from easily getting to major markets. This “stranded” gas could sell only at a significantly lower level than the national price. Pipelines are being developed to connect Marcellus production to existing pipelines, so this situation is expected to be remedied by 2017 before the Atlantic Coast Pipeline is in operation.

        It was during the period of a maximum price differential between the surplus “stranded” gas in the Marcellus and the national price at Henry Hub that ICF used for its assumption for the savings available as a result of Marcellus gas flowing through the Atlantic Coast Pipeline. They also assumed that this condition would last for decades. Currently, prices have fallen so low that there is little room for a significant price differential between Henry Hub and Dominion South prices.

      • “Marcellus gas is abundant and cheap, and gas pipeline companies have been scrambling to develop new markets, mostly in the U.S., but also for foreign markets by means of Liquefied Natural Gas.”

        The Marcellus is now the largest natural gas production area in the U.S. and is being counted on to supply abundant cheap gas for decades to come. For some time, it has been difficult to obtain current accurate information about the field’s production. West Virginia provides data for one full year at a time. Pennsylvania is now a bit better, releasing data for six-month intervals. Data for 2014 are now available which provide a good measure of what is happening since Pennsylvania wells are 85% – 90% of the Marcellus production. David Hughes, a geoscientist and expert regarding unconventional natural gas potential for the Geological Survey of Canada and now the Post Carbon Institute in the U.S., has developed an in-depth assessment of all drilling and production data from the major shale plays. Some of his findings are summarized below:

        • Field decline averages 32% per year in the Marcellus. Over 1000 new wells are required each year just to maintain production levels.

        • Three of the 70 counties account for nearly half of the play’s production, five counties account for two-thirds, and 12 counties account for 90%.

        • Drilling is concentrated in the top counties which have the greatest economic payback; the cheapest gas is being produced now, leaving the expensive gas for later.

        • Average well productivity increased between early 2012 and early 2014 as operators applied better technology and focused on “sweet spots”.

        • The increase in well productivity over time peaked in 2014 and has fallen in the last half of 2014.

        • Better technology is no longer increasing average well productivity in the top counties. This is a result of either drilling in poorer locations or from well interference – where one well cannibalizes another well’s gas.

        • Geology appears to be trumping technology in Susquehanna County, which is the most productive area. Well density was 1.48 wells per square mile in mid-2014 with the assumption that 4.3 wells per square mile could be drilled; this may be overly optimistic.

        • This declining well productivity is significant, yet expected, as top counties become saturated with wells, and will degrade the economics which have allowed operators to sell into Appalachian gas hubs (e.g. Dominion South) at a significant discount to Henry hub gas prices.

        • There is a backlog of wells which have not yet been hooked to pipelines (often waiting for a higher gas price). This cushion can maintain or increase Marcellus production as they are connected even if rig counts continue to fall.

        • Current drilling rates are sufficient to keep Marcellus production growing until its projected peak in 2018, followed by a terminal decline (which assumes gradual increases in price; sudden major increases in price could temporarily check this decline if reflected in significantly increased drilling rates).

        • As for the massive investments in infrastructure on the assumption of cheap and abundant gas for the foreseeable future – CAVEAT EMPTOR.

        Clearly, the long term savings projected by ICF was only a temporary phenomenon; expected to disappear even before the Atlantic Coast Pipeline is projected to be in service. This is confirmed by an in-depth analysis from a veteran geoscientist.

        Another unbiased assessment of shale gas potential was provided by a team of a dozen geoscientists, petroleum engineers and economists at the University of Texas at Austin. They spent more than three years on a systematic study of the major shale plays. According to an article in Nature, the team received a $1.5 million grant from the Sloan Foundation to accomplish the research.

        The University of Texas team assumed natural gas prices would follow the scenario that the Department of Energy’s Energy Information Agency (EIA) used in its 2014 annual report (a price level of about $4 mcf). The Texas team forecasts that production from the big four plays would peak in 2020, and decline from then on. By 2030, these plays would be producing only about half as much as in the EIA’s reference case. Even the agency’s most conservative scenarios seem to be higher than the Texas team’s forecasts.

        The main difference between the Texas and EIA forecasts relates to how fine-grained each assessment is. The EIA breaks up each shale play by county, calculating an average well productivity for that entire area. But counties often cover hundreds of square miles, large enough to hold thousands of shale gas wells. The Texas team, by contrast, splits each play into blocks of one square mile, a much finer resolution than the EIA’s.

        Resolution matters because each play has sweet spots that yield a lot of gas, and large areas where wells are less productive. Companies try to target the sweet spots first, so wells drilled in the future may be less productive than current ones. The EIA’s model so far has assumed that future wells will be at least as productive as past wells in the same county. But this approach, the Texas team argues, “leads to results that are way too optimistic”.

        ICF’s assumptions of a prolonged price advantage for Marcellus gas appears to be based on the EIA’s original hopeful but inaccurate forecasts. Not only would Marcellus (Dominion South) gas not be less expensive than Henry Hub prices; Dominion South prices could possibly be higher than Henry Hub prices. Dr. Patzek, head of the University of Texas at Austin’s Department of Petroleum and Geosystems Engineering, and a member of the University of Texas research team, says that after the peak of production from the shale gas plays, “there’s going to be a pretty fast decline on the other side”. “That’s when there’s going to be a rude awakening for the United States.” He expects that gas prices will rise steeply, and that the nation may end up building more gas-powered industrial plants than it will be able to afford to run. With companies trying to extract shale gas as fast as possible and export significant quantities, he argues, “we’re setting ourselves up for a major fiasco”. “The bottom line is, no matter what happens and how it unfolds,” he says, “it cannot be good for the US economy.” Or for Virginia’s economy.

    • Yes, for interstate natural gas pipelines, FERC must issue a COPN. If it were intrastate origin-to-destination, maybe it would come to the VSCC, but natural gas pipelines have been largely FERC regulated since the 1930s. This contrasts with electric transmission, which has rates that are FERC regulated (because all bulk electricity is deemed interstate commerce), but COPNs are issued by the States, in this case the VSCC, because the federal law didn’t give that authority to FERC (except for a very convoluted provision that allows FERC to get involved if a State refuses to allow a transmission line built that the FERC believes is seriously needed).

  8. re: list of Dominion Plants

    Chesapeake is a coal plant to be shut down

    Gravel Creek is a base load gas plant on the Elizabeth River which is south of James from Hampton

    according to : Electric Generating Plants Currently Operating in Virginia (DEQ) http://goo.gl/HFB0Wg

    so where does Hampton get peak power generation from?

    curious.. my ignorance… for sure..

    • If the James River transmission crossing at Surry is built, there may be no local need for peaking generation for electric system stability in the Hampton area; in that case the peaking power will come from the Grid as dispatched by PJM, and those peakers may be located anywhere in PJM.

      • Acbar – if power can be supplied by PJM “anywhere” why does Dominion insist on power lines going across the James in that one place and not further downstream or upstream?

        if PJM can supply Hampton from existing powerlines why is the additional one across the James needed?

        why not locate the two new gas plants in Cheapeake and area and send power to Hampton from that location?

        • I’m working on an article that will provide all these answers. Still have a lot of research to do, but I’m working on it!

          The short answer is that the Surry nuclear plant across the James is served by a 500 KV transmission line. The next closest line of that capacity is in Chickahominy, halfway to Richmond. The route across the James crosses less environmentally/culturally sensitive land than a route from the Chickahominy. Dominion can’t build a gas plant because the Peninsula is not served by a gas line with enough capacity to supply the plant. A power line running under the river would cost an additional $250 million or so, and be vulnerable to lengthy outages (three months) if repairs were needed. Every option has drawbacks. The trick is to go with the least-bad option.

          Is the Skiffe’s Creek route the least-bad option? Stay tuned…

  9. The jerks who operate the gas pipeline through Northern Virginia have suddenly and randomly decided to cut down many old growth trees along the existing pipeline route. The trees were clearly older than the pipeline and had apparently been just fine. However, one fine day the pipeline company decided to start cutting the trees down. They went onto people’s private property and started the saws. Now there is a swath of large tree stumps along the pipeline route. I used to think that the pipeline companies were doing the best they could. No more. I urge all Virginians along the path of a proposed new pipeline or a pipeline slated gor expansion to resist. Do not let the bastards get a toe hold on your property or the asshat pipeline companies will behave like feudal land barons defoliating your property for no apparent reason and with no acceptable explanation.

    Call your county supervisor, call your state legislators, call your lawyers, call the environmental groups. Send the pipeline clowns packing before it’s too late. And definitely do not believe their string of lies as to how unobtrusive it will all be. These people are practiced liars. They will tell you any story to get that right of way. Once they have the right of way your rights are forfeited, right away.

  10. TomH, Thanks for all the input! You’ve seriously raised the bar for intelligent discussion of this issue. You’ve given me a half-dozen leads for follow-up stories.

    • I agree. thank you!

      and clearly this is about profits – as much as anything else and they intend to export the gas if they can and to use eminent domain to get the right-of-way so they can export the gas.

      And if the SCC and the Va GA so concerned about costs to rate payers from closing coal plants why are they not similarly concerned about what might happen to the price of natural gas for generating electricity if it gets exported and depleted?

      I think the contributions of TomH pretty much focus those issues.

    • Jim,

      Let me know what issues you are most interested in pursuing and I can send you some links to get you started and then you can follow your own trail.

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