The Natural Gas Act and the Federal Power Act charge the Federal Energy Regulatory Commission (FERC) with the responsibility to promote the development of robust, reliable and secure natural gas infrastructure. However, the mandate to promote natural gas development does not require that every project be accepted. The statutes also authorize FERC to issue certificates of “public convenience and necessity” for “the construction or extension of any facilities … for the transportation in interstate commerce of natural gas.” The 1999 Policy Statement describing how FERC would make the determination to issue such certificates, notes that the process would address “whether the applicant has made efforts to eliminate or minimize any adverse effects the project might have on the existing customers of the pipeline proposing the project, existing pipelines in the market and their captive customers, or landowners and communities affected by the route of the new pipeline.” During this process, the applicant must “show public benefits that would be achieved by the project that are proportional to the project’s adverse impacts.” “Vague assertions of public benefits will not be sufficient.” It is the Commission’s duty to be certain that the benefits of the project outweigh its adverse effects.

As part of this assessment FERC cannot solely rely on the capacity of the project under firm contracts but must also evaluate “all relevant factors reflecting the need for the project”. “Using contracts as the primary indicator of market support for the proposed pipeline project also raises additional issues when the contracts are held by pipeline affiliates”, according to the Policy Statement.

FERC will receive volumes of comments relating to how the construction of 556 miles of pipeline over new right-of-way will create an abundance of adverse effects that do not serve the “public convenience”. However, because several natural gas projects are proposed to serve the same needs in Virginia, the following comments pertain to the “necessity” of the project.

Need for Additional Natural Gas Transmission Capacity to Serve Virginia and North Carolina Markets

The case for new gas transmission pipelines to serve Virginia and North Carolina involve two major issues, one general and one specific. The general issue is the notion that we have discovered an abundant source of affordable gas in shale formations throughout the U.S., especially in the Marcellus formation situated primarily in Pennsylvania and West Virginia. Additional pipelines might be needed to distribute this new source of natural gas to existing markets. The second issue specifically relates to the demand for additional natural gas in Virginia and North Carolina, and the best ways to serve it.

Abundant Affordable Natural Gas

There is a good deal of confusion about the amount of natural gas in the U.S. Unfortunately, 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 can be recovered technically. Only a portion of the technically recoverable resources can be produced economically. Only a portion of the economically producible resources can be converted into supply. This economically producible supply is called a reserve. A reserve is only truly meaningful when you identify the price that is used to establish its size. The volume of the reserve for gas selling at $4 per thousand cubic feet (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.”

In the 1990’s natural gas was cheap – $2 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 shale gas wells declined significantly within the first few years of production. Their experience drilling for conventional gas was that wells would decline slowly over several decades.

Developers had big loans to pay for leases and drilling rigs but received much lower than expected revenues 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 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. Production rapidly declined 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 facilitating 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 U.S. natural gas supply expanded by 5.2 billion cubic feet per day (Bcf/d) in 2014; 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. But low prices have taken a toll on rig count. U.S. natural gas drilling rigs have fallen by nearly a third, from 320 to 222. U.S. oil drilling rigs have been harder hit, falling by over half, from 1,536 to 642. (This is important because associated gas from crude oil wells accounts for about 10% of natural gas production.)

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.

The Marcellus is now the largest natural gas production area in the U.S., contributing about 20% of the nation’s supply. Business leaders and policymakers are counting on the Marcellus 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. Detailed results 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.

Energy industry executives, politicians and policymakers have made decisions based on the forecasts from the Department of Energy’s Energy Information Administration (EIA). Dr. Hughes’s conclusions are based on an examination of actual well data from the Marcellus, not generalized projections. At the beginning of shale development there was a widespread assumption that we will have decades of affordable, plentiful natural gas. Current experience doesn’t match the forecasts. Why does the popular perception differ from what the experts are finding?

In order to have an accurate, unbiased assessment of shale gas potential, a team of a dozen geoscientists, petroleum engineers and economists at the University of Texas at Austin 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. Ruud Weijermars, a geoscientist at Texas A&M University notes the work is the “most authoritative” in this area so far.

The University of Texas team assumed natural gas prices would follow the scenario that the 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”.

The high resolution of the Texas studies allows their model to distinguish the sweet spots from the marginal areas. As a result, says study co-leader Scott Tinker, a geoscientist at the University of Texas at Austin, “we’ve been able to say, better than in the past, what a future well would look like”. After reviewing the University of Texas study, the EIA has changed course and predicted that contributions to domestic natural gas production from shale gas sources will peak around 2020 at their Reference Case price levels.

Members of the Texas team are still debating the implications of their own study. Tinker considers that the team’s estimates are “conservative”, so actual production could turn out to be higher. The big four shale-gas plays, he says, will yield “a pretty robust contribution of natural gas to the country for the next few decades. It’s bought quite a bit of time.”

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, argues that actual production could come out lower than the team’s forecasts. He talks about it hitting a peak in the next decade or so — and after that, “there’s going to be a pretty fast decline on the other side”, he says. “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 plants than it will be able to afford to run. “The bottom line is, no matter what happens and how it unfolds,” he says, “it cannot be good for the US economy.”

Australia’s experience might be a cautionary tale for the U.S. When that country began to use its plentiful natural gas for new uses such as burning it in power plants and exporting 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. policymakers 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”.

Increased utility prices might not be the only effect of rising natural gas prices in Dominion’s service territory. 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. Increased natural gas prices could cut back manufacturing in Virginia and reduce the projected load.

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 more 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.”

There is no definitive answer yet. Technological advances and market movements have a way of surprising us. However, with the entire U.S. utility industry moving towards much higher reliance on natural gas, it is worth a detailed look at the consequences of a significant price increase for natural gas in the 2020 – 2030 time frame. We experienced $13.50 mcf gas just seven years ago. At that time we were not exporting it or burning it in our baseload power plants.

The essential point is that many new natural gas infrastructure projects are being proposed assuming that we have an abundant source of affordable natural gas. Detailed independent studies indicate that will be an unlikely scenario. FERC should base project decisions on the best available information rather than industry forecasts based on incomplete data used to support a specific agenda. Currently, the best information shows that our existing pipeline network, plus select expansions, is likely to be sufficient to handle the foreseeable demand.

The Department of Energy (DOE) believes that is true. “Natural Gas Infrastructure”, a DOE study published in February, 2015, addressed the options for providing more gas to the southeast. The report states, “Even with the significance of the Marcellus, projected natural gas production and demand are geographically diverse, so the need for additional interstate natural gas pipeline infrastructure is lower than would be expected if the increased production or demand were concentrated in a particular region.” Furthermore, pipelines built since 2007 to accommodate “increases in shale gas production are projected to reduce the need for future pipeline infrastructure.” The Department of Energy 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”.

The report goes on to say that even if more coal-fired and nuclear plants are retired than expected, there is sufficient capacity in the existing system to handle the demand. The DOE report states, “Projected pipeline utilization for the top 200 pipeline segments by projected flow volume in the model in 2030 rises to 60% in the Intermediate Demand Case and 61% in the High Demand Case, compared to 57% in the Reference Case.”

Demand for More Natural Gas Supply in Virginia
The traditional uses of natural gas in Virginia will change very little over the next 20 years, according to a study funded by Dominion. ICF International predicts that the compound annual growth rate for residential and commercial uses of natural gas in Virginia will be 0.1% between 2014 and 2035. Dominion has emphatically stated that no gas flowing through the Atlantic Coast Pipeline will be used to produce LNG. Thus, additional gas supply to Virginia is needed only to fuel new power plants.

Dominion identified plans for future power plants in its Integrated Resource Plan, filed July 1, 2015, with the Virginia State Corporation Commission (SCC). Two new gas-fired combined cycle generating stations were proposed, each with a capacity of about 1585 MW. One beginning service in 2022; the second is proposed for 2030. Units of this size require approximately .250 Bcf/d of natural gas. Several other gas combustion turbines are planned over the next 15 years. These smaller units are used to handle peak loads and to smooth out variations in supply from solar and wind generation. However, they run only about 10% of the time and do not require nearly as much natural gas as do the combined cycle units.

It is difficult to understand how one plant possibly coming in service seven years from now and another on the distant horizon for 2030 would justify the construction of nearly 300 miles of pipeline on new right-of-way and an expenditure of billions of dollars to serve this potential demand in Virginia. It certainly makes a flimsy case for benefits when stacked up against the multitude of specific adverse effects of pipeline construction. Neither gas-fired plant is assured of approval. Beginning in 2020, the cost of solar installations are expected to be less expensive than gas-fired combined cycle plants according to many studies and confirmed by Dominion’s proposal to make solar its greatest source of new generating capacity between 2020 and 2030. Energy efficiency is less expensive than adding new generation of any type and could erase the need for these new gas plants. Many are concerned about an over-reliance on natural gas to deal with Clean Power Plan compliance. Burning natural gas for electric generation is only a “less bad” option than coal, rather than a solution such as carbon free sources of generation (solar and wind).

Gas-Fired Generation in Virginia Utilizing Other Pipelines
Three new gas-fired combined cycle plants will be built in Virginia prior to the in-service date for the proposed Atlantic Coast Pipeline and will connect to existing pipelines:

Warren County Power Station: a 1329 MW facility which began operation December 10, 2014, near Front Royal in Northern Virginia. Natural gas will be provided by the Columbia Gas pipeline serving northern and central Virginia.

Brunswick County Power Station: a 1358 MW facility currently under construction in Southside Virginia, expected to enter commercial operation in the summer of 2016. An application was filed with FERC (Docket CP13-30) by the Transcontinental Gas Pipe Line Company, LLC (Transco) to add 81 miles of 24” pipe on existing right-of-way in southern Virginia and 7 miles on new right-of-way to provide service to the power plant site. A new compressor station adjacent to the existing Transco compressor station in Pittsylvania, Virginia is included in the project. Modifications to the Transco pipeline in other states are required by this project to allow bi-directional flow on the Transco mainline, providing supply from both the Marcellus and Gulf Coast production areas. Transco will provide .250 Bcf/d to the Brunswick plant and .020 Bcf/d to Piedmont Natural Gas in Northampton County, North Carolina. Dominion Virginia Power will agree to a 20-year Long-Term Firm Transportation Service Agreement for the project with a targeted in-service date of September 2015. Twenty-three million of the $298.7 million project cost was covered by a Virginia Tobacco Commission grant.

Greensville County Power Station: Dominion Virginia Power has applied to the SCC for permission to develop a 1600 MW combined cycle plant four miles from the Brunswick power plant in Greensville County, Virginia. The facility is slated for operation in 2019. Transco has requested a Certificate of Public Convenience and Necessity from FERC (Docket CP15-118) to extend a 4.33 mile connection from the Brunswick pipeline to the Greensville site, to be completed by December, 2017. Expansion of the compressor station and other modifications are required to supply .250 Bcf/d of natural gas to fuel the power plant. Dominion Virginia Power will agree to a 20-year Long-Term Service Agreement to obtain gas from the $190.8 million project.

In its descriptions of the Atlantic Coast Pipeline project, Dominion has noted that it will connect both the Brunswick and the Greensville power plants to the Atlantic pipeline. Making it appear that the existence of the Atlantic pipeline is essential to the long-term operation of those facilities. It should be clearly noted that all three of these power plants have reliable long-term supplies of natural gas provided by existing pipelines, without the need for the Atlantic Coast Pipeline. Otherwise, approval for their operation would not have been granted by the Virginia SCC.

Any effort to replace the gas supplied by Transco’s Virginia Southside Expansion Projects 1&2 with gas supplied by the Atlantic pipeline during the 20 year term of the service agreements with Transco would definitely “Have an Adverse Effect on Existing Pipelines Serving the Market”. Dominion has committed to take 96% of the capacity of those two projects for at least 20 years. It is disingenuous for Dominion to make a commitment for gas supply in order to gain approval of the Transco projects, and then make the same commitment in order to gain approval of the Atlantic Coast Pipeline project. If it is the nature of the natural gas industry for project developers to make such insincere promises in order to gain approval of projects in which they have an interest, then how is the public to trust that there is truly market demand for any of these proposals?

Demand for More Natural Gas Supply in North Carolina
The situation in North Carolina is similar to Virginia. Electric and gas usage is flat or declining, even with a growing economy. The increased use of natural gas for power plants is all that is increasing gas demand. There is reason to question whether all of the proposed plants will be built. North Carolina is ahead of Virginia in the use of renewables. Energy efficiency could well reduce the need for new power plants. It is not required for a pipeline to exist in Virginia in order to expand gas supply in North Carolina, if necessary.

In the Resource Report 10 addendum to the application for the Atlantic Coast Pipeline, the Transco pipeline is identified as the primary receipt point for the North Carolina deliveries, as shown below:

Three customers (Duke Energy Progress, Inc., Duke Energy Carolinas, LLC, and Piedmont Natural Gas Company) identified the existing Transcontinental Gas Pipe Line Company, LLC (Transco) system as a primary receipt point with an interconnection in Buckingham County, Virginia.

Four customers (Duke Energy Progress, Inc., Duke Energy Carolinas, LLC, Piedmont, and Virginia Power Services, Inc.) identified the existing Transco system as a primary delivery point with an interconnection in Buckingham County, Virginia.


Alternative Energy Sources

In Resource Report 10, Dominion has noted that there might be alternatives to the two combined cycle plants in 2022 and 2030 that serve as the justification for a new gas supply pipeline in Virginia. The report states, “All of these alternative energy sources, depending on the location of the source, would require new infrastructure, including transmission facilities, to connect supply and demand areas.” This is not quite accurate according to documents filed by Dominion Virginia Power with the SCC. In their 2015 Integrated Resource Plan (IRP), Dominion proposes to build several utility scale solar installations at current power plant sites to make use of existing substation and transmission facilities. Numerous solar panels could be installed on the roofs of commercial, industrial and government buildings without the need for transmission lines or land.


Renewable Energy Sources

Dominion states in Resource Report 10, that “significant long‐term investment in new facilities would be necessary before renewable energy could potentially satisfy a substantial portion of the projected energy demand in Virginia and North Carolina.” And that there is “limited solar generation potential in the ACP Project area and . . . installation of solar generation facilities would be cost prohibitive.” Again this runs counter to how Dominion projects to develop its generation capacity over the next 15 years. During the period that Dominion proposes to add 3170 MW of capacity with the two new combined cycle plants, 3820 MW of new solar capacity is also planned. This is hardly a sign that their service territory has “limited solar generation potential”. Rather than these solar facilities being “cost prohibitive”, many studies indicate that solar costs will decline by another 50% in the next 5-6 years and undercut the cost of combined cycle plants.

Factoring in the risk of rising fuel costs, some planners are concerned that the declining cost of solar and wind generation could out-compete combined cycle plants, either negating the need for their construction or worse yet, leaving recently constructed plants idle or under-utilized. This would leave the utility with stranded costs which would have to be borne by ratepayers or shareholders, or both. Imagine a newly constructed $5 billion pipeline built primarily for power plants – that are no longer active.

Dominion concludes that, “there is limited potential to develop commercial scale wind and solar power in West Virginia, Virginia, and North Carolina based on wind and solar potential using current technologies. For these reasons, wind, solar, and hydroelectric facilities are not feasible alternatives to the Projects.” It is troubling that the statements used by unregulated subsidiaries of Dominion to support the development of this pipeline are so at odds with the plans made on the public record by its sister company and customer for the gas brought by the pipeline, Dominion Virginia Power. Not only is Dominion planning to develop thousands of megawatts of renewable generation by 2030, an equal or perhaps greater amount could be developed by residents and businesses which are not accounted for in their forecasts.


Energy Conservation
Dominion concludes that, “Although energy conservation measures will be important elements in addressing future energy demands, it is unlikely that they will be able to offset more than a fraction of anticipated demand in the foreseeable future. As a result, energy conservation alone (or in conjunction with other alternatives) is not a viable alternative because it does not preclude the need for natural gas infrastructure projects like the ACP and SHP to meet the growing demand for energy.”

For the past 7 to 8 years, electricity use has been flat or declining in the U.S., although the economy has increased about 8 percent. New innovations are coming to market which allow us to produce more economic activity while using less energy. The energy intensity (the amount of energy used per unit of state GDP) in Virginia is about 50% more than the energy required to produce a unit of GDP in California. With reasonable energy efficiency, there is sufficient room to expand our state economy without increasing load.

Even utility executives realize that the historical linkage between energy use and the economy has changed. Duke Energy’s CEO Jim Rogers noted, “we are not going to reach [forecasted] 2019 [load] levels until 2030 despite an economic rebound since 2008. In past decades, for every 1 percent growth in gross domestic product, there was as much as 5 percent growth in demand for electricity. But those days are gone.” He also said that “We are on the way to seeing a decoupling of the growth of demand for electricity with the growth in GDP. That will have a profound implication for how we think about our business.”

Virginia has a large presence of federal installations, especially military bases. The Department of Defense has embarked on a worldwide program of reducing energy use. Dominion should expect to see significant reductions in loads from military installations within its territory over the next 15 years.

Savings from the retrofits at the Naval Air Station Oceana outside of Virginia Beach are a good example. Using an energy savings performance contract (ESPC), the project is projected to reduce energy use by over 40% across more than 100 buildings and save the naval base over $6 million per year in energy costs. Dominion should forecast similar reductions in load from other bases in its service territory.

Rocky Mountain Institute (RMI) has produced a well researched energy and efficiency plan that will support an economy 2.5 times bigger by 2050 that requires no coal, no oil, no new laws, no new federal taxes, no subsidies, or even any new inventions. This can be done at a price that is $5 trillion less (nationwide) than our current business-as-usual approach with no consideration of the hidden costs of fossil fuels or a price for CO2.

RMI partnered with Johnson Controls and others to do an energy efficiency retrofit of the 2.7 million square foot Empire State Building. The project reduced the building’s energy use by 38%, saving $4.4 million annually, while creating 252 jobs.

Other states are well on their way to taking leadership in this arena. Vermont and California have been consistent leaders. Ohio and Indiana have adopted standards of 2% per year annual energy savings by 2019. Massachusetts has committed to making energy efficiency its “first fuel” asking utilities to invest $2.2 billion in order to save customers $6 billion in energy costs. Their plan calls for 30% of Massachusetts’ energy to be provided by energy efficiency by 2020.

While others are demonstrating what is possible with energy efficiency, it is clear that greater efficiency is typically the lowest cost method of creating new energy supply; considerably less than the cost of a new combined cycle plant. If Virginia decided to pursue energy efficiency aggressively, dramatic reductions in energy use could be realized in a relatively short time.


No Action Alternative
What are the consequences if the Atlantic Coast Pipeline is not developed as proposed?

In the near term, there would be no adverse effects in Virginia. Operation of the gas-fired power plant that is the justification for more gas supply to Virginia is at least seven years away. A site for the proposed facility has not been identified, so it is not known whether the ACP or an existing pipeline would be a better source of supply. In the next 3-5 years much could transform in our energy system. Regulators in many states are reevaluating the role of utilities and the principles guiding the development of our energy infrastructure. Costs, technologies, and attitudes associated with renewables and energy efficiency are evolving rapidly. These options have great promise that might soon be realized. Reductions in demand could postpone the in-service date for a new combined cycle plant; perhaps, until renewable options are clearly cheaper rather than just cost competitive. Since the first plant requiring additional gas supply to Virginia is seven or more years away, we need not rush to rip up our land to build a pipeline for a need that has not yet materialized.

The North Carolina partners in the ACP could determine if additional gas supply was required to serve their state. If needed, new pipelines could connect to the Transco right-of-way at the Virginia-North Carolina border where the Atlantic pipeline is proposed to enter the state. Laterals could also be extended from the Transco mainline that transits the state from north to south in the west/central portion of North Carolina. North Carolina needs would be adequately addressed without requiring the costs and damage of building 300 miles of pipeline on new right-of-way in West Virginia and Virginia.

Other options should be explored that provide the supply proposed by the ACP, but with lower costs and fewer impacts.


System Alternatives
Several projects have been proposed to move natural gas supply from the Marcellus to markets in the Southeast, as is intended by the Atlantic pipeline. As each of these projects intends to achieve essentially the same objective, not all are needed. Many of these proposals require significant disturbance of new right-of-way, some do not. FERC is encouraged to review all projects on their merits and choose the outcome with the lowest cost, greatest benefits and fewest impacts. The commission should not be swayed by those that apply first, or those that have the most firm supply commitments provided by project developers. It should be remembered that although developers invest in these projects, customers pay for them – in their utility bills and the effects on their communities and property.

When these projects pass through several states, FERC’s authority supersedes the need and impact assessments that normally occur at the state level. A federal review should encompass an equal, or more rigorous, review of the need for these projects and their impacts than would occur at the state level. Issuing a Certificate of Public Convenience and Necessity confers upon the applicant the right to develop their project on the property of an unwilling landowner. Given that eminent domain overrides a right held dear in this nation, it is imperative that FERC is convinced that the public benefits outweigh the impacts created by a project. A full review of all of the options should be undertaken before selecting the best outcome.

With the clamor to build pipelines to transport gas from what has been touted as an abundant supply of gas in the Marcellus to an apparent huge new market for burning natural gas in power plants, it would be easy for an agency charged with developing natural gas infrastructure to lean towards project approvals. Steady heads should prevail with a long-term strategic vision. We have seen a similar rush to develop shale oil. Developers took on massive amounts of debt to exploit what seemed like a long-term profit opportunity. Geopolitical forces countered in a way that changed the economic equation. Developers are now left with an average of 83% of their revenues required for debt service. Many cannot hold out long. Gas-fired power plants are a long term solution for a short term need to provide a bridge until lower cost carbon free renewables can fully deal with the load. Natural gas pipelines can have an 80-100 year useful life. Someone must pay for them even if they are not used to their intended capacity. Much is changing in our energy landscape over the next several years. Options should be selected which provide the greatest flexibility, at the lowest cost with the least disruption.

Alternative Routes

Spectra Energy announced that plans for the Spectra Carolina Pipeline are on hold.

Mountain Valley Pipeline
The Mountain Valley Pipeline (MVP) project comprises 301 miles of 42” pipeline from northwestern West Virginia to southern Virginia, terminating at the compressor station for the Transco pipeline in Pittsylvania, Virginia. The $3-$3.5 billion project, scheduled to be in service late 2018, would provide about 2 Bcf/d of natural gas capacity and require three new compressor stations. The project application is currently under review by FERC (Docket PF15-3-000).

By providing 2 Bcf/d of additional capacity to the Transco system in southwestern Virginia, the project would provide more capacity than the 1.5 Bcf/d proposed for the Atlantic pipeline. The Transco mainline runs throughout west/central Virginia and North Carolina, as well as a right-of-way through much of southern Virginia. The two gas-fired power plants that justify additional gas service to Virginia have not been sited so it is uncertain how much additional pipeline would be required to connect them to the Transco line. The same is true for the Atlantic pipeline.

North Carolina power plants could be served from the Transco system, either from the mainline in the west, or by accessing the Transco right-of-way at the Virginia-North Carolina border in the same location proposed for the Atlantic project.

The MVP could be considered competitive with the ACP. It provides more capacity at a lower cost with fewer miles of right-of way disturbed (not counting the pipelines required to connect future NC power plants). Only one of these projects would be required. However, there could be superior alternatives to both.

Appalachian Connector Pipeline Project – Transco
The Appalachian Connector is very similar to the MVP. It is designed to move up to 2 Bcf/d of natural gas from the western Marcellus to the Transco compressor station in Pittsylvania, Virginia. The route has not been formally defined, but is expected to be about 300 miles long. The cost has not yet been estimated. Issues with connections in Virginia and North Carolina would be the same as with the MVP.

The ACP, MVP, and Appalachian Connector proposals suffer from the need to disrupt 300-550 miles of new right-of-way, at a cost of $3-$5 billion dollars. Each pipeline intends to move gas from the Marcellus into the nation’s natural gas supply system. Perhaps there is a shorter, less expensive means of achieving the same end.

Atlantic Sunrise Pipeline Project – Transco
The Transco pipeline system is the largest in the U.S. Over 10,000 miles of pipelines, in a 1,800 mile corridor from the Gulf Coast to New York, carry 10.9 Bcf/d of natural gas. Atlantic Sunrise will connect to the highest production areas in the Marcellus, the counties in northeastern Pennsylvania, and then proceed 177 miles to connect to the multiple pipelines in the Transco corridor where it passes through southeastern Pennsylvania, adding 1.75 Bcf/d of additional capacity. Thanks partly to modifications made on behalf of Dominion to serve the Brunswick and Greensville plants, gas can flow in both directions on the Transco system supplying gas from the Gulf Coast and Marcellus production areas. The $2.1 billion project is expected to be online in late 2017. A Penn State study modeled the benefits of the Atlantic Sunrise project to customers in different regions of the Transco system, comparing market conditions during the period January 1, 2012 to June 27, 2014 with a simulated market that incorporated the additional system capacity from Atlantic Sunrise. The research projected that over this 30-month period, consumers in Zones 4, 5 (Virginia and the Carolinas) and 6 would have enjoyed about $2.6 billion in total benefits because of the Atlantic Sunrise expansion.

Every pipeline proposal comes with commitments that say the capacity of the project is fully subscribed. But there is not enough real demand to support all of the pipeline proposals. If capacity greater than that of the Atlantic pipeline is available in a major pipeline that travels through Virginia and North Carolina, commitments can be made for that supply rather than from a more expensive and far more disruptive pipeline such as the Atlantic Coast Pipeline. If ACP shippers are motivated, they can arrange for supply from this superior alternative.

Atlantic Sunrise

WB XPress – Columbia Gas
Columbia Gas 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, Virginia, various compressor upgrades along the system, construction of just 2.9 miles of new pipeline and 26 miles of replacement pipeline in existing corridors. The project is expected to be in service the second half of 2018 at a cost $875 million dollars.

Adding capacity to the Columbia Gas system would provide greater supply to the Chesapeake, Virginia region as well. The main Columbia Gas line feeds the AGL (Virginia Natural Gas) line which supplies the Chesapeake/Norfolk area. Supply constraints in this region prompted AGL to become an owner of the Atlantic Coast Pipeline project, which proposes a 77 mile 20” pipeline on new right-of-way to connect the Chesapeake area to the Atlantic Pipeline just after it enters North Carolina. Using the additional capacity in the Columbia Gas system avoids the costs and impacts from this new construction. If upgrades were required to gain more capacity in the AGL line, they would be for just a few miles on existing right-of-way.


It is apparent from the map that adding 3 Bcf/d of new capacity in the Transco and Columbia Gas pipelines provides Virginia with a multitude of options for siting the two new gas-fired plants when (and if) they are needed in 2022 and 2030. Compare the coverage of the Transco and Columbia pipelines in Virginia to a single line for the Atlantic pipeline. This would provide a great deal of flexibility for growth and development in Virginia without the disruption from new pipeline construction.

The Atlantic Sunrise connection is in the highest production areas; wells in Pennsylvania account for about 90% of the total Marcellus production. The Atlantic pipeline, MVP and the Appalachian Connector have their supply headers in the western Marcellus (West Virginia), where wells are much less productive. With the addition of the Atlantic Sunrise project and other take-away pipelines, the current constraint in getting the full output of the Marcellus to the general market will be resolved by 2017. Additional proposed take-away projects such as the Atlantic pipeline, MVP, and the Appalachian Connector would not be needed, as noted by the Department of Energy in their “Natural Gas Infrastructure” report. Relieving the “stranded” gas in the Marcellus will likely raise prices in Appalachian hubs closer to the prices at supply hubs in other zones.

Pipelines in North Carolina could connect over the same corridor planned for the Atlantic pipeline or by connecting to the Transco mainline running through North Carolina, as previously mentioned. Costs and impacts of pipeline development in North Carolina might be similar to what is proposed for the Atlantic pipeline. Duke Energy and Piedmont Natural Gas could file an application with FERC to gain approval for the necessary connections to North Carolina.

Lower load growth due to increased energy efficiency and the rapid decline in the costs of renewable generation bring into question whether all of the gas-fired plants currently under consideration will be built. A headlong rush to build pipelines could cause substantial adverse effects not counterbalanced by public benefits. The most prudent approach is to select the alternative which provides the most capacity and flexibility, with the lowest cost and fewest impacts. Within five years it should be apparent if additional capacity is required.

Choosing the Atlantic Sunrise and WB XPress option fulfills all of the supply goals proposed by the other alternatives. This choice also provides 50%-100% more capacity than the other proposals. The location of attachment to the Transco system provides great flexibility in meeting demand throughout the east coast as conditions change. Crucially, this higher capacity can be obtained at a lower cost with far less disruption of new right-of-way than the other alternatives.

Developers of the Atlantic Coast Pipeline might argue that they do not possess firm reservations for capacity in the Atlantic Sunrise and WB XPress projects as they do for the Atlantic pipeline. If FERC were to deny the Atlantic proposal, the early stages of the other projects provide ample opportunity for the Atlantic customers to gain firm supply from the Sunrise/XPress capacity if their demand truly exists.

North Carolina retains the same options as they had with the Atlantic proposal, plus added capacity available from the Transco mainline running across the state.

Virginia greatly benefits by choosing the Sunrise/XPress over the Atlantic pipeline. Although the need for the first new gas-fired power plant in Virginia is not until 2022 (or later), the Sunrise/XPress option provides capacity throughout the statewide network of Transco and Columbia Gas pipelines rather than just the single pipeline provided by the Atlantic pipeline option. AGL (Virginia Natural Gas) service to the Chesapeake area is far better served by a higher capacity Columbia Gas pipeline just a few miles away rather than building a 77 mile pipeline over new right-of-way into North Carolina. Best of all, these benefits can be achieved at a lower cost with no construction of new gas transmission pipelines required in the state to serve Virginia’s needs.

It is recommended that FERC deny the applications for the Atlantic Coast Pipeline, the Mountain Valley Pipeline, and the Appalachian Connector and that they approve the Atlantic Sunrise and WB XPress projects. Duke Energy and Piedmont Natural Gas should file an application with FERC to authorize the necessary pipelines to serve the needs in North Carolina.

Studies funded by Dominion show that traditional uses of natural gas in Virginia will grow just 0.1% each year between 2014 and 2035, thus the need for new gas supply to Virginia is entirely for new gas-fired power plants.

All three of Dominion’s gas-fired power plants going into service from 2014-2019 have firm long-term contracts with existing pipelines.

The first new gas-fired plant requiring additional gas supply to Virginia is proposed for 2022; the second in 2030.

Advances in energy efficiency and the rapidly declining cost of renewable generation might postpone or erase the need for one or both of these plants.

The Atlantic Coast Pipeline, the Mountain Valley Pipeline, and the Appalachian Connector are similar proposals to provide additional supplies of natural gas to Virginia and North Carolina. Since they address the same need, not all are required.

The Atlantic Sunrise project will connect to the highest gas production area in the Marcellus (northeastern Pennsylvania) and travel 177 miles to southeastern Pennsylvania and connect to the Transco Pipeline serving a corridor from New York to the Gulf Coast, including Virginia and North Carolina.

WB XPress involves a new compressor station and just 3 miles of new pipeline construction to add 1.3 Bcf/d of new capacity to the Columbia Gas pipeline system serving West Virginia and Virginia.

The Atlantic Sunrise/WB XPress option provides 50%-100% more capacity than the other alternatives at a lower cost with considerably less disruption of new right-of-way.

Pipeline development in North Carolina could be exactly as proposed with the Atlantic pipeline – or something better.

The Sunrise/XPress option provides 3.0 billion cubic feet of additional capacity added to the Transco and Columbia Gas pipelines (the pipelines that serve a majority of Virginia). This gives flexibility for development throughout Virginia rather than just from a single source (as with the Atlantic pipeline).

No new gas transmission pipeline is required in Virginia to serve the needs of the state. Just three miles of new pipeline construction would be required in West Virginia.

Those in need of additional gas supply can make commitments for the Atlantic Sunrise/WB XPress supply, rather than from the more expensive and far more disruptive Atlantic Coast Pipeline. If they truly need it, they can get it.

FERC should accept the Atlantic Sunrise/WB XPress option as the one best suited to meet the needs for new gas supply in Virginia and North Carolina. The Atlantic Coast Pipeline, Mountain Valley Pipeline, and the Appalachian Connector proposals should be denied. Duke Energy and Piedmont Natural Gas should file a new application for the development of appropriate pipelines to serve North Carolina.