Creating a way of life for the new millennium

The ACP in a Nutshell

Dominion and its partners in the Atlantic Coast Pipeline (ACP) have made what appears on the surface to be an enticing proposal. They have said that we need a greater supply of natural gas in Virginia to fuel our power plants and our economy. The developers say they must build a 550-mile pipeline to make this possible and that the pipeline will provide many jobs and financial benefits. They ask us to take their word that this is the best option and that they should receive rapid approval with little review in order to get the project underway so that it will be available in time.

Upon inspection, we find that the first power plant that requires a new supply of natural gas in Virginia is not scheduled for operation until 2022, the next one is proposed for 2030. So what is the rush? We have plenty of time for thorough deliberation of the options.

If the ACP is approved, Dominion claims that thousands of jobs and millions of dollars will benefit the states through which the pipeline will pass. A developer of a similar pipeline through West Virginia and Virginia has admitted that it is likely that just 10% of the workers will come from the area in which the pipeline is built. This means that just a few hundred workers are likely to be hired from West Virginia, Virginia, and North Carolina rather than the thousands that have been advertised. Most of the skilled workers will come from other regions in the U.S. and will send their paychecks home. The main period of pipeline construction in any one area will last just 6-8 weeks. This is not long enough to require area businesses to add more long term employees or for the money to circulate throughout the local economy. Only businesses such as motels, gas stations, bars, fast food restaurants and convenience stores are likely to benefit, and then just for a short time. All but perhaps 5% of the construction material will be purchased from outside the 3-state region.

The economic models that were used to create the millions of dollars of projected benefits were developed for situations considerably different from pipeline construction and vastly overestimate the benefits to our local economies.

The tax benefits accruing to local jurisdictions along the pipeline route are stated as if they are a net addition to local government coffers. Recent studies show there will not be any net tax benefit. The added property value of the pipeline will be offset by reduced property values for the many parcels in or adjacent to the pipeline right-of-way. Loss of tourism income, lower economic development, and other costs will overwhelm pipeline tax revenues and other purported benefits of the pipeline. Developers have painted an image of economic windfalls. In fact, just four of the counties through which the Atlantic pipeline will pass in Virginia will experience economic losses greater than the total cost of the pipeline.

The ACP is intended primarily to transport natural gas for power plants. The traditional residential and commercial uses of natural gas for water and space heating are expected to be essentially flat through 2040. The ACP is a wholesale pipeline for large users such as utilities, not for supporting the growth of communities and businesses along its path.

The need for additional natural gas supply in Virginia is to fuel a possible new plant in 2022. Finding ways not to use energy (energy efficiency) is far cheaper than building a new gas-fired power plant and saves all ratepayers money when the peak load is reduced. Many believe that solar power, which does not require any fuel, will also be less expensive than gas combined cycle plants within 5-7 years. But assuming more gas supply to Virginia is needed, the question remains – is the ACP the best means to supply it?

Two new gas-fired combined cycle plants are being built in Southside Virginia. The Brunswick facility is scheduled for operation in 2016, the Greensville plant is proposed for 2019. A spur from the Transco pipeline is nearing completion and will serve these two plants for an investment of $490 million. Dominion has said that it prefers to use the ACP to provide the gas supply to these plants, but the ACP will require about 300 miles of new pipeline construction and a cost of more than $3 billion to reach these same two plants.

The ACP developers say that they have long-term commitments from customers wanting to receive natural gas deliveries from the Atlantic pipeline and these commitments are adequate to prove that the ACP is necessary. All but one of the identified customers is a subsidiary (affiliate) of the same holding companies that own the developers of the pipeline. Dominion’s willingness to renege on a 20-year Long Term Supply Agreement with Transco after just a few years of operation of the new pipeline highlights that these commitments are not binding. They are often used by developers to gain approval to construct a new pipeline and are not indications of the economic need for a project, although they are often considered as such by FERC.

If 96% of the new Transco spur will go unused if supplanted by the ACP, will Dominion ratepayers have to pay for both pipelines? Since the gas transport fee is part of the fuel cost and is automatically passed through to ratepayers, can Dominion and Duke force their utility subsidiaries to pay for the ACP even if it is more expensive than other alternatives?

The ACP developers say the Atlantic pipeline is the only realistic alternative, but that is seldom the case. If the Dominion’s utility subsidiary (Dominion Virginia Power) was free to choose or if they were directed by the SCC to select the lowest cost choice for reliable natural gas supply, what might that be?
Currently, natural gas drillers in the Marcellus are continuing to drill, even if prices are below their production costs, in order to generate the cash necessary to service their debts. U.S. natural gas prices declined more than 40% in 2015 compared to a year earlier largely due to excess production in the Marcellus. As yet, there are not enough takeaway pipelines serving the Marcellus production area to move all of the gas into the existing gas transmission system. This “stranded” gas must sell at a discount to the national price in order to find a market. By 2017, this situation will be remedied by the addition of new takeaway pipelines. Dominion has forecast hundreds of millions of dollars of financial benefits for the Atlantic pipeline as a result of this price differential, but it will likely disappear well before the ACP is projected to be in operation. If some price advantage remains for Marcellus gas, the lower price would be available whether the gas is transported by existing pipelines or the ACP.

Once these new takeaway pipelines are in operation, the entire Marcellus production can gain access to existing gas transmission pipelines. When this occurs much of the supply to the mid-Atlantic and northeast will come directly from the Marcellus. Traditionally, much of the gas traveled from south to north from the Texas and Gulf Coast supply zones using pipelines in the Transco corridor to serve markets along the Atlantic seaboard. With much of the northeast demand supplied directly from the Marcellus, several of the existing pipelines in the Transco corridor would be available to reverse flow and bring natural gas from the Marcellus to Virginia and the Carolinas. This is the plan identified in the Natural Gas Infrastructure report published by the Department of Energy in February, 2015.

Existing pipelines, which are largely paid for, will provide gas supply to Virginia and North Carolina at same the locations proposed for the ACP.

Another project, the WB XPress, would provide 1.3 billion cubic feet per day (nearly the amount of the ACP) of additional capacity in the Columbia Gas system requiring just three miles of new pipeline and 26 miles of replacement pipeline in West Virginia and a new compressor station in Virginia and modifications to several existing ones. The project is expected to be in service the second half of 2018 at a cost of $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. The Atlantic Coast Pipeline project 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.

Adding over twice the capacity of the ACP 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 corridor 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.

Pipelines serving North Carolina could connect over the same corridor planned for the Atlantic pipeline or by connecting to the Transco mainline running through North Carolina. Costs and impacts of using existing pipelines to serve North Carolina would be the same or better than with the Atlantic pipeline.
Developers of the ACP might argue that they do not possess firm reservations for capacity using existing pipelines as they do by utilizing a pipeline that they own. The producers in the Marcellus are eager to find committed long-term markets to supply with their surplus production. This is the very best time to obtain commitments for low cost supplies. If the ACP were not to be approved, the proposed customers of the Atlantic pipeline would find willing suppliers, if their demand truly exists.

One can see that Dominion and its partners would prefer to own the supply pipeline to their captive utilities. There are business advantages to paying themselves more rather than paying someone else less to transport the natural gas. However, the benefits accrue only to them. Ratepayers would pay higher transport fees for the ACP compared to existing pipelines; Virginia would have a poorer infrastructure for future economic development and power plant siting; West Virginia and Virginia public and private landowners would suffer greatly from the impacts of unnecessary new pipeline construction.

The spirit of eminent domain is to require a landowner to sacrifice their individual interest in order to serve the greater public good. In this case, the greater public good is better served both economically and environmentally by using existing pipelines. No rights to eminent domain should be granted to developers of the ACP.

The superiority of the option of using existing pipelines applies to the Atlantic Coast Pipeline, and to the Mountain Valley Pipeline, the Appalachian Connector and any other major new pipeline construction project intended to bring natural gas from the Marcellus into the Virginia and North Carolina markets. The Department of Energy states that adequate capacity exists in the existing pipeline system to serve this region throughout the multi-decade planning horizon of their studies.

We ask that the land, the landowners, and ratepayers of Virginia be respected by selecting the clearly superior option of using existing pipelines to supply the future natural gas needs of Virginia. Dominion and other Virginia utilities are needed for the important role of developing a more reliable and resilient grid for the 21st century that easily accommodates decentralized solar and wind projects which they or other parties develop. Dominion should seek out projects that benefit the ratepayers and residents of Virginia, as well as their shareholders. Setting the interests of shareholders against the interests of customers is not good for any business in the long run. There are numerous other important energy projects where Dominion can work for the good of all Virginians.

Who is protecting the Interests of Virginians?

Dear Virginia Elected Officials and Regulators,

We ask for your assistance in protecting the interests of the ratepayers, local governments and landowners of Virginia. Typically, utility projects in Virginia are reviewed by the State Corporation Commission with frequent input by the Attorney General’s Office of Consumer Protection. These state agencies serve as advocates for the ratepayer’s interest as well as setting a fair return to utility shareholders. With the approval of the Atlantic Coast Pipeline (ACP) determined by the Federal Energy Regulatory Commission (FERC) no one is speaking for the overall well-being of Virginia ratepayers and citizens. We respectfully ask that someone fulfill that role. Below are several issues which affect ratepayers and citizens of Virginia.

1. FERC sets rates for transporting natural gas primarily using incremental costs. This means that transporting gas in new pipelines is more expensive than using existing pipelines which are partially paid for. The transport fee becomes part of the fuel cost which is automatically passed on to utility customers. The ACP will cause Virginia ratepayers to pay more than necessary for their electricity compared to using existing pipelines. Who will speak for Virginia ratepayers?

2. A new pipeline spur is being completed to serve the Brunswick and eventually the Greensville power plants that Dominion is developing in Southside Virginia. This $490 million new spur from the Transco mainline can access supply from both the Marcellus and the Texas/Gulf Coast production regions to assure a reliable supply of natural gas. Dominion states in their application to FERC that they plan to serve these two plants with the ACP when it is completed. They are planning to spend over $3 billion to construct nearly 300 miles of new pipeline to provide a third source of supply to these same power plants. Dominion will make the investment in the Atlantic pipeline, but it is the ratepayers who will pay for it. Who will speak for Virginia ratepayers?

3. When Dominion backs out of their 20-year Long Term Supply contract with Transco, which was the basis for FERC approving the project, to switch to the ACP – the new Transco pipeline built for Dominion will lose 96% of its business. If customer contracts serve as the basis for FERC approval, but are easily cast aside once a pipeline is built, where is the proof that the ACP is truly needed? Will the ratepayers have to pay for the more expensive ACP and the abandoned new Transco spur? Who will speak for Virginia ratepayers?

4. If the ACP is built, Dominion will want to attach the power plants proposed for 2022 and 2030 to the pipeline they own. If the new plants are approved, this either limits the locations in which those plants can be developed or requires longer than necessary spurs to be built for these new plants. The ratepayers will shoulder this added expense. Who will speak for Virginia ratepayers?

5. Dominion admits that the ACP is a wholesale pipeline intended to serve only electric and gas utilities. If the same or greater amount of natural gas flowed from the Marcellus through existing pipelines in to the Columbia Gas and Transco pipelines which already crisscross Virginia – not only will the power plants be served, but so will residential, commercial and industrial development throughout the state. Who will speak for the economic interests of the citizens of Virginia?

6. If the new natural gas supply is moved in existing pipelines it can flow through the Columbia Gas pipeline which feeds the AGL (Virginia Natural Gas) line which already supplies the Chesapeake -Norfolk area. Developers of the Atlantic Coast Pipeline propose 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. The great savings from tapping the Marcellus gas that Dominion proclaims, if it does exist, is equally available when using existing pipelines, but at a lower cost and with far lower impacts. Who will speak for the economic and environmental interests of the citizens of Virginia?

7. Construction of a new pipeline on or near a parcel reduces the long term value of the property, limits future uses of the land and makes it unavailable for sale while construction is occurring. The turmoil of construction also reduces tourism and recreational visitors which provide valuable income to many of our rural communities. Reductions in land values will greatly reduce tax receipts to counties along the pipeline route plus the added expenses of dealing with the boom/bust of construction activities. A recent study of only four of the thirteen counties affected by construction of the ACP in Virginia showed that the economic losses related to the Atlantic pipeline in just these four counties will equal more than the $5 billion that the developers will invest in the entire pipeline. Who will speak for the local governments and citizens of Virginia?

8. An amount of natural gas equal or greater than the capacity of the ACP can be supplied to North Carolina using existing pipelines, without the need to the construct the ACP through Virginia. Our land and communities need not be damaged to serve the energy needs of another state. Who will speak for Virginia?

9. The ACP will damage the unique habitats, the precious streams and ancient aquifers that are the source of the pure water that flows through our communities and into the James and Potomac River watersheds. We are the stewards of this land. The bounty of our ancestors’ labor was passed from generation to generation on farms that existed before our nation was formed. Who will speak for Virginia’s heritage?

We believe that you, our representatives in Virginia, are uniquely qualified to be the voice for Virginia. To speak for the people’s many interests. We need not be forced choose between having an adequate supply of natural gas and preserving Virginia. Using existing pipelines saves money, promotes future prosperity and preserves our communities, our water and our land. We need your help to make it so. Please be involved in the FERC proceeding to represent the interests of Virginians by promoting the use of existing pipelines rather than building new pipelines in Virginia.

 

Respectfully,

Your Constituents and Virginia Citizens

Response to Dominion’s Answer to Protests

The following comments were submitted to FERC in response to Dominion’s answer to issues raised by many individuals and groups concerned about the need and impacts of the Atlantic Coast Pipeline (ACP).

A. The Need for ACP and the Supply Header

There remain serious questions about the need for the ACP and its benefits to the public which have not been satisfied by Dominion’s answers submitted to the Commission on December 4, 2015.

In its policy statement of February 9, 2000, clarifying the Statement of Policy issued September 15, 1999, the Commission explained “that as the natural gas marketplace has changed, the Commission’s traditional factors for establishing the need for a project, such as contracts and precedent agreements, may no longer be a sufficient indicator that a project is in the public convenience and necessity.” In the original 1999 Statement of Policy, the Commission states that “in considering the impact of new construction projects on existing pipelines, the Commission’s goal is to appropriately consider the enhancement of competitive transportation alternatives, the possibility of overbuilding, the avoidance of unnecessary disruption of the environment, and the unneeded exercise of eminent domain.”

The Commission continued, saying “that it was considering how best to balance demonstrated market demand against potential adverse environmental impacts and private property rights in weighing whether a project is required by the public convenience and necessity.”

In its discussion of the Drawbacks of the Current Policy, under “Item 1 Reliance on Contracts to Demonstrate Demand”, the Commission noted that “The amount of capacity under contract also is not a sufficient indicator by itself of the need for a project, because the industry has been moving to a practice of relying on short-term contracts, and pipeline capacity is often managed by an entity that is not the actual purchaser of the gas. 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. Thus, the test relying on the percent of capacity contracted does not reflect the reality of the natural gas industry’s structure and presents difficult issues.”

And “finally, by relying almost exclusively on contract standards to establish the market need for a new project, the current policy makes it difficult to articulate to landowners and community interests why their land must be used for a new pipeline project. All of these concerns raise difficult questions of establishing the public need for the project.”

Nearly all of the Customers identified for the ACP are affiliates of the developers of the pipeline. There is little surprise that they would notify the Commission that “they strongly support the Project”.

What is the True Need for Additional Natural Gas Supply?

The ICForecast Strategic Natural Gas Outlook predicts the compound annual growth rate for residential and commercial uses of natural gas in Virginia will be 0.1% between 2014 and 2035. Since Dominion has emphatically stated that no gas flowing through the Atlantic Coast Pipeline will be used to produce LNG, any 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 natural gas combined cycle generating stations were proposed, each with a capacity of about 1585 MW. Neither plant has an identified location, nor is approved for construction by the Virginia State Corporation Commission. The first electric generating station that will require additional gas supply in Virginia is proposed to begin service in 2022; the second in 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 much smaller units handle peak loads and 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.

Energy efficiency is less expensive than adding new generation of any type and could postpone or erase the need for these new gas plants. As could more rapid adoption of affordable, zero carbon emitting sources of generation such as solar.

Dominion is building a 1358 MW natural gas combined cycle plant in Brunswick County Virginia, due to begin operation in the summer of 2016. They are also planning to develop a 1600 MW natural gas combined cycle plant in Greensville County (4 miles away), slated for operation in 2019.

To gain approval of these pipelines (FERC Dockets CP13-30 and CP15-118), Dominion Virginia Power committed to 20-year Long-Term Firm Transportation Service Agreements with Transco. Expected costs are $298.7 million for the Brunswick pipeline and $190.8 million for the connection to the Greensville plant. Approximately 96% of the capacity of this new pipeline is assigned to the Dominion power plants.

In its description of the Atlantic Coast Pipeline project, Dominion said 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. The Friends of the Shenandoah believe 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 (ACP). In a footnote (#33) to their answer to Interveners, Dominion replies, “Access to one pipeline, of course, does not mean that an alternative means of supply is not necessary or desirable. VPSE, as the supplier of those power-plants, has committed contractually to ACP and the views of certain environmentalists obviously provide no reason for the Commission to question that contractual decision.” They go on to say that a 20-year contractual commitment does not necessarily “represent genuine market demand”. If it is common for customers of project developers to make insincere promises in order to gain approval of projects, then how is the public to trust that there is truly market demand for any natural gas pipeline proposal?

The existing Transco connection to these plants provides supply from both the Gulf Coast region as well as the Marcellus in case there is a supply disruption in one region or another. Dominion is asking their ratepayers to support a multi-billion dollar investment, with all of its associated disruption, in order to add one more backup supply for its plants after the ratepayers have already purchased a belt and suspenders from Transco.

The need for additional gas supply to Virginia, in whatever form or amount that might exist, is served at a significantly lower cost by existing pipelines with far less disruption of property and sensitive areas. The existing pipelines traverse the breadth of Virginia, rather than the single corridor proposed for the ACP.

Threshold Tests

In consideration of the public convenience and necessity, the Commission assesses potential adverse impacts on three primary interests: 1) the applicant’s existing customers, 2) the interests of competing existing pipelines, including any subsidies of the proposed project, and 3) the interests of landowners and surrounding communities.

Existing Customers

The intention of FERC policy is to assess the effects of the expansion of a pipeline on the existing customers of that pipeline. As a new development, the ACP has no existing customers. However, the developers of the pipeline have used their affiliates to prove the need for the ACP and be its primary customers. Therefore, those affiliates are intimately connected with the economics of the project.

Dominion Transmission, through its affiliates, will ultimately supply natural gas as fuel to produce electricity for sale by Dominion Virginia Power, a regulated utility in the state of Virginia. Assuming the price of the natural gas is constant, the difference in fuel price between scenarios would be attributed to the cost of transportation in the pipeline. Any higher costs from transportation in the ACP compared to other alternatives would automatically be passed on to Dominion ratepayers as a fuel cost adjustment without further regulatory review.

Transportation costs in new pipelines are typically based on incremental costs, plus the rate of return authorized by FERC. Generally, new construction would result in higher transportation costs compared to using existing pipelines for which the original investment has been substantially repaid.

Dominion has decided to connect two if its power plants to the ACP rather than relying on the pipeline (with redundant supply) that was recently built to serve them. This requires nearly 300 miles of pipeline construction and billions of dollars of investment. These higher costs will add to the price of fuel and be automatically passed on to ratepayers. The ratepayers gain no benefit from these higher costs; reliable gas service already will be provided by the new Transco spur.

Additional costs may accrue to the ratepayers in the development of the new plants proposed for 2022 and 2030. By limiting their connection to the ACP, rather than the existing statewide network of Transco and Columbia Gas pipelines, higher transmission costs might result or longer and more expensive than necessary gas supply spurs could be required.

These unnecessary added costs to existing customers are usually the purview of the Virginia State Corporation Commission (SCC), with input from the Consumer Protection group of the Virginia Attorney General’s Office. However, the federal authority, invested in FERC in this case, has usurped the state authority and the normal regulatory oversight that protects the interest of “existing customers” in this instance cannot occur. FERC is the only authority that can give this issue consideration and it is recommended that they do so as part of their overall review of the project. The adverse economic effects on existing customers should definitely be weighed against the purported benefits of the project.

Construction of the ACP through West Virginia and Virginia is not necessary for North Carolina to have access to sufficient supplies of natural gas. North Carolina can maintain the option of accessing additional supply from about the same location as proposed with the ACP or they can select a better option. Their interests are unaffected if no new pipeline is constructed through Virginia.

Existing Pipelines and Subsidies

The added costs that existing customers must bear automatically from higher gas transportation charges associated with the ACP compared to existing alternatives, is a form of subsidy. These customers are captives of the affiliates of the developers and absent state regulatory oversight; they have no say in whether they pay more in order to subsidize the construction and operation of the Atlantic pipeline. This subsidy is extracted from the existing customers by the affiliates of the developers with no offsetting advantage since reliable gas supply is available to them through lower cost means.

Construction of the Atlantic pipeline definitely has an adverse effect on the interests of existing pipelines. The Transco spur being built to supply Dominion’s Brunswick and Greensville plants costs $489.5 million and Phase I is scheduled for operation in late 2015. Dominion has stated in its application for the ACP that it will elect to connect both of these plants to the Atlantic pipeline. If the ACP becomes the primary source of supply, then the Transco spur will have lost a customer for 96% of its capacity. The developer (Transco) will have invested nearly $490 million in the new pipeline and almost immediately lose 96% of its ability to repay that investment as Dominion reneges on its 20-year agreement to purchase natural gas delivered by the Transco spur. This certainly qualifies as a “significant adverse effect on an existing pipeline”.

If Dominion maintains the Transco pipeline as its primary source, then 300 miles of 42” pipeline would be built unnecessarily through West Virginia and Virginia, only to serve as a backup for a new pipeline which already includes a backup source of supply. Customers of Dominion’s affiliate would likely pay for this unnecessary expense and gain no value from it, which amounts to a huge subsidy of the ACP.

On a much larger scale, the landscape of the nation’s natural gas transmission system has shifted significantly with the increased output of gas from the Marcellus. As take-away pipelines are added for the Marcellus supply to gain access to the national network of gas transmission pipelines, the historical movement of gas from south to north will shift. Especially along the 1,800 mile multi-pipeline Transco corridor going from the Texas and Gulf Coast production areas along the Atlantic Coast to beyond New York City. Much of the supply will now come from the Marcellus zone in Pennsylvania and move directly to the areas of demand in the Mid-Atlantic States and the Northeast. This allows additional supply from the Marcellus to flow southward to serve Virginia and the Carolinas by reversing the flow of pipelines no longer being used to move gas from south to north in the Transco corridor. This scenario makes optimum use of existing pipelines, which have plenty of available capacity to handle this flow of gas, as described by the Department of Energy, in their “Natural Gas Infrastructure” report issued in February 2015.

The existing network of Transco and Columbia Gas pipelines that spreads throughout Virginia has access to gas supply from the Transco corridor and can easily and inexpensively distribute it to wherever it is needed in Virginia. North Carolina can also access this supply of additional gas either from the Transco spur corridor which parallels the Virginia – North Carolina border, where the ACP is proposed to enter North Carolina; or directly from the main Transco corridor in the west-central portion of the state. This allows North Carolina users the ability to select connections which have the lowest costs and least impacts.

Failure to utilize existing pipelines with adequate capacity to carry the volume proposed for the Atlantic pipeline would under utilize a low-cost resource, overbuild new capacity, and cause unnecessary disruption to landowners and sensitive environmental, recreational, and historic areas and cause the taking by eminent domain from landowners who would otherwise not voluntarily grant the right for a pipeline to exist on their property. This is definitely an adverse effect associated with the ACP that can be avoided by using existing pipelines.

Clean Power Plan

In its response to Interveners, Dominion makes the assertion that the “construction of ACP is essential to these states’ ability to comply with the Clean Power Plan”. This is not supported by independent studies. The Advanced Energy Economy Institute (AEE Institute) contracted with ICF International (a firm hired by Dominion for the ACP) to perform an assessment of the potential impacts of the Clean Power Plan (CPP) on required gas pipeline capacity. Three scenarios were assessed including: the Reference Case, which is a business-as-usual future without the CPP; the basic CPP Case, which assumes each state will meet its emissions target by 2030; and the Low Gas Price Case CPP Case, which assumes the same emissions target as the basic CPP Case, but with natural gas prices 20% lower than expected.

Modeling results show that under the Reference Case, natural gas demand continues to grow through 2030. Under the CPP Case, there is a temporary increase in natural gas demand above the Reference Case as a result of the shift from coal to gas-fired power plants. Incremental demand then declines over time as additional renewable energy and demand-side resources become available. Because this incremental demand is small, even if coal to gas switching occurs at a higher rate, such as under the low future gas prices case, the modeling shows that it would not cause a significant increase in new pipeline requirements.
This report further finds that compliance with the CPP, even under an unlikely scenario of unexpectedly high gas usage, would only modestly increase gas infrastructure needs, in the range of 3% to 7% nationwide.

Gas consumption in the South is projected to increase in both CPP cases. This area (including Virginia) is relatively close to the Marcellus and Utica shale gas production areas. The study notes that most of the pipeline capacity needed to get Marcellus/Utica supply to southern markets (South Atlantic, Gulf Coast industrial facilities, and LNG export terminals) can be met by reversal of existing pipeline capacity, which can be done at a relatively low cost. The study references plans that are in place to repurpose much of the Northeast’s existing inbound pipeline capacity to transport gas out of Marcellus/Utica. The repurposing of existing pipelines reduces the amount of new pipeline construction required to meet market growth, according to the study.

The CPP Case requires an additional 4% in pipeline expansion beyond what is already added in the Reference Case between 2016 and 2020 and no incremental requirement beyond the Reference Case additions after 2020. The first power plant for which Dominion requires gas service is proposed for operation in 2022. The only other new baseload power plant requiring new gas supply is proposed for 2030.

In the past ten years new natural gas pipelines constructed in the U.S. have totaled about 487,000 inch-miles, costing approximately $56 billion. Previous studies by the EPA and the Department of Energy (Natural Gas Infrastructure Report), as well as the AEE Institute study, suggest that the need for new natural gas pipelines required over the next 15 years (2016-2030) will be less than what was added in the past ten years, with or without the CPP.

All of these studies support the conclusion that sufficient natural gas can be supplied to the Virginia region by reversing the flow of existing pipelines, without the need for the construction of a new gas supply pipeline to serve Virginia. Independent studies confirm that the Atlantic pipeline is not required for Virginia and North Carolina to have sufficient supplies of natural gas in order to meet the requirements of the Clean Power Plan.

Alleged Economic Benefits of the ACP

Dominion has stated that no intervener “has provided any basis to challenge the fundamental conclusions of these studies that ACP will create enormous monetary benefits.” We have some experience preparing similar studies and guiding the efforts of nationally renowned experts in the assessment of the socioeconomic effects on communities from the construction of multi-billion dollar utility projects. Below is a summary of the major shortcomings that exist in the studies performed by Dominion’s consultants.

ICF Study

ICF International was retained by Dominion to identify potential economic advantages related to the Atlantic Pipeline. Our main objection concerns the fundamental assumption that supports the economic benefits described in the study. ICF assumes that a temporary lower price at the Dominion South Hub would apply over the life of the pipeline. All evidence suggests this price differential will not exist by the time the Atlantic pipeline is projected to begin operation.

The essential premise that drives all of the ICF cost savings calculations is that the price of natural gas from the Dominion South Hub in the western Marcellus would be $1.61 /MMBtu cheaper than gas sourced from other locations, represented by the price at Henry Hub; and the cost differential would grow steadily over the 20 year period of the study.

Henry Hub is a distribution hub in Louisiana which interconnects with nine interstate and four intrastate pipelines. 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. The Dominion South Hub is near where thousands of 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, which are also owned by Dominion.

A lower price has existed at Dominion South over the past few years compared to Henry Hub. This is due to overproduction in the Marcellus and the lack of sufficient takeaway pipelines to get the Marcellus production into the nationwide natural gas pipeline system.

Drilling in the Marcellus began in the early 2000’s when natural gas prices were high and capital was inexpensive and easy to get. Drillers, accustomed to the long slow decline of production in conventional gas wells, were surprised to find that production declined significantly within the first few years with shale gas wells. Saddled with debt and with lower than projected revenues, drillers kept drilling just to create cash flow to pay their loans. Over 1000 new wells must be drilled in the Marcellus each year to maintain production levels. Technology advanced so more wells could be drilled from a single drilling rig, making drilling more productive and less expensive. This high level of drilling activity expanded supply by 5.2 billion cubic feet per day (Bcf/d) in the past year, while 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.

This oversupply brought down natural gas prices nationwide, but especially in the Marcellus. The rapid increase in production outran the volume of existing takeaway pipelines to bring the Marcellus supply into the gas transmission system. The Marcellus production area became an island in the national gas system and this “stranded” gas could only find a market if sold at a substantial discount to the national (Henry Hub) price.

Pipelines are being developed to connect Marcellus production to existing transmission pipelines, so this situation is expected to be remedied before the Atlantic Coast Pipeline is in operation. Over 18 Bcf/d of additional takeaway capacity is expected to be in service in the Marcellus by the end of 2017, according to the Oil Price Information Service. Producers are eager to get a higher price for their gas and are embracing plans to reverse flows in existing pipelines which will move their gas to markets that will support a higher price, such as areas in the Southeast. Adequate access to the existing national transmission system will bring prices in line with prices at other locations such as Henry Hub.

ICF mistook the lower price of the Marcellus gas due to oversupply and transportation constraints as a characteristic of Marcellus gas – as if it were cheaper to produce compared to gas from other sources (it is not). In fact, independent studies expect that production of affordable gas in the Marcellus will peak in 2018. Additional gas will be available only at higher prices. So rather than selling at less than Henry Hub prices, it is quite possible that price increases in Marcellus gas will begin a national trend of higher natural gas prices.

Since the fundamental premise of the ICF study has been invalidated, there is no need to discuss other flawed assumptions in the study. We recommend that the Commission consider that none of the economic benefits described in the ICF study apply to the Atlantic pipeline since the calculations of those benefits rest on an assumption that has been shown to be incorrect.

If the Commission chooses to accept that a price advantage exists for natural gas produced in the Marcellus, there is no reason to conclude that the ACP must be constructed in order to take advantage of this price differential. Access is being developed to existing pipelines which are being repurposed to reverse flow and move gas to serve markets in Virginia and North Carolina. The same price advantaged Marcellus supply can move through these existing pipelines at a lower cost to customers than would be provided by the ACP. Any economic advantage that would be assigned to the Atlantic pipeline would be even greater for the alternative of using existing pipelines, without the attendant environmental disruption.

Chmura Study

Chmura Economics & Analytics was retained by Dominion to identify potential benefits of construction of the Atlantic pipeline. The project includes the construction of over 550 miles of natural gas pipeline, three compressor stations and related facilities, at an estimated cost of $4.6 billion (now $5.1 billion). The Chmura study identifies three main contributors of economic benefits: 1) one-time effects of pipeline construction, 2) benefits from ongoing pipeline operation, and 3) ripple effects – indirect and induced effects resulting from the direct effects of construction and operation.

One-Time Impact from Construction

Eight percent of the total cost of the pipeline will be used to acquire access to land for the right-of-way. The remaining 92% will be spent on materials and labor for constructing the pipeline, compressor stations and other related facilities. A pipeline requires specific materials for its construction. The pipe, special valves, compressors, the monitoring equipment and most of the other material needed to build the pipeline will be provided by suppliers outside the states in the construction area. Only 5% of the equipment needed for compressor and M&R stations will be purchased from within the three-state region affected by construction, according to Chmura.

Chmura does estimate that 50% of the construction labor will come from inside the states affected by construction. This assumption is 500% higher than the number estimated by another pipeline developer in the region (10% of the workforce to be hired locally for a West Virginia to Virginia pipeline project). Pipeline crews are typically hired from a national base of skilled employees experienced in handling the specialized tools and equipment needed to build the pipeline. Dominion has admitted that the ACP is the largest pipeline with which it has been involved. It is understandable that they would be heavily reliant on experienced subcontractors from outside the region to insure proper and timely construction of the pipeline. Workers from outside the region will spend the minimum necessary to meet their daily expenses and send the rest back home to their families in the states where they have their permanent residence. Therefore, only 10% of the monies spent on construction labor and perhaps less than 5% of the amount sent on equipment for the pipeline will actually benefit people in the construction zone of the project.

There is likely to be very little indirect and induced benefits from pipeline construction. The models such as the one used by Chmura typically utilize a multiplier to calculate the overall benefit of new jobs in a region. The models assume that if a local business were to hire a new employee, they expect the salary would be spent mostly in the local area for food, housing, transportation and at local stores, banks, restaurants, etc. The models project that each dollar of the new employee’s income might move through the local economy and generate an extra dollar or two of benefit to other businesses and their employees, and indirectly cause creation of new jobs. But Dominion’s jobs aren’t like a new local job, although the high estimates for indirect and induced local economic activity stated by their consultants seem to assume they are.

The construction process will consist of the following: construction surveying, clearing, grading, topsoil segregation (if applicable), trenching, pipeline stringing, welding, x-raying and weld repairs (if necessary), coating (if needed), lowering in, back-filling, hydrostatic testing, clean-up and surface restoration and reseeding, if appropriate. The bulk of construction activity occurs over a 6-8 week period in any particular location. The group responsible for each phase of construction would stay in a town only for a few days paying for hotels, gas, bar tabs, groceries and fast food – then move on; replaced in a few days or a few weeks by the crews for the next phases. This is hardly a bonanza for a local economy and local employers are unlikely to add staff to serve a group that stays in town for such a short time. Therefore, the actual value of the indirect and induced economic benefits of construction could be closer to 5% or so of the values identified by Chmura. Few if any additional jobs are expected to result from indirect or induced effects of pipeline construction.

Impacts from On-Going Operations

Again, it is difficult to make specific comments and a proper restatement of the numbers produced by Chmura because the precise methodology and assumptions used are not identified. However, general comments can guide the Commission in recognizing that the economic benefits described are far overstated.

We do not dispute that 24 people in West Virginia, 39 in Virginia, and 18 in North Carolina will be permanently employed to operate the pipeline. This is the primary direct benefit of pipeline operation.

Chmura claims $69.2 million per year in total annual economic benefits from the operation of the pipeline. Nearly all of this benefit is created using by the value of the gas in the pipeline (gross sales of the ACP) which is then run through the magic multiplier to create extra multiple millions of indirect benefits and added jobs. The only true value provided by the pipeline is its transportation service. The value of the gas is independent from the pipeline. This same gas can be transported without the ACP in existing pipelines. Its value is only realized when it is used to create electricity or heat a home.

Tax Payments

The tax benefit calculations appear to assume that the entire construction payroll will be susceptible to personal income tax in the states of West Virginia, Virginia, and North Carolina. This overstates the tax benefit by perhaps as much as 900%. When an employee works part of the year in a state outside of their permanent residence, most states have reciprocity agreements whereby the individual pays the entire tax on their income in their home state. Given that only about 10% of the workers employed during construction will reside inside the three-state region, the tax benefits to those states are significantly overestimated.

Chmura assumes that the corporate income tax will be paid on the full amount of ACP profits. Corporate profits are reduced by adjustments such as depreciation, which will be substantial for the $5 billion ACP, so that little or no corporate income tax will be paid at least for the first 30 years or so.

Dominion has also touted its significant amount of property tax payments that will flow to counties in the pipeline corridor. The method of calculation used to estimate these amounts is not clear, but they are presumed to be accurate. However, they are communicated as if they are a net benefit. These payments could be offset to large degree by reductions in tax payments from property owners due to their lowered property values because they are located on the pipeline right-of-way or close to it. Additional public expenditures for police protection, road repairs, damage to public water supplies and a host of other issues could be associated with pipeline construction. So it is not clear that there will be a net economic benefit in many communities along the construction corridor.

Chmura Study Summary

Our comments regarding this study are not aimed at criticizing the modeling tool used by Chmura. It and others like it have been refined over time based on research and professional practice. Our main criticism is that it was used inappropriately in this instance. The tool was designed to estimate the effects of development in a specific location, such as a “big box” store, a new factory, or forest service activities. In these cases, much of the material is purchased locally, the local trades are involved using local labor, and the long-term workers are drawn from the surrounding area. Construction occurs over months or years, all in the same location. The multipliers for indirect and induced benefits are well researched and usually provide a fairly reasonable estimate of what might result from a typical new development.

The moving carnival of pipeline construction has little resemblance to this type of construction. Most of the materials and labor come from outside the area. Activity occurs in short bursts and lasts but a few weeks. There is little reason for most existing businesses to increase staffing to accommodate pipeline construction activities. A few types of businesses will experience short periods of higher business activity. But the communities will not see the extended benefits and multiplier effects experienced with other types of new development.

Friends of the Central Shenandoah believe that the economic benefits purported for the Atlantic pipeline are based on flawed assumptions, as we have identified, and as a result, are vastly overstated. We hope the Commission and staff will use our comments and their experience with other projects to gather more specific information from Dominion so that a much more accurate evaluation of the potential benefits of the Atlantic proposal can be developed to compare against its significant impacts.

B. Other Existing and Proposed Pipelines Cannot Replace the Need for ACP

In Part A we questioned the need for ACP. The residential and commercial demand for natural gas in Virginia is expected to be flat (0.1%/yr) for the next 25 years. Additional gas supply to the state is not required until a power plant is proposed to go online in 2022; the next major plant is not scheduled until 2030. Many factors are at work, including low cost energy efficiency measures, better means for demand response, and more rapid development of solar generation, which could postpone or erase the need for this new gas-fired generation and therefore the need for more gas supply.

In this section, we must consider the best way to supply additional gas, if that need exists. Dominion advises us not to second-guess their commercial decisions. We understand that the 100-year old utility business model is eroding because of the decoupling of energy use from economic growth. Advances in energy efficiency, renewables, distributed generation, and advanced grid technologies are making it difficult for utilities to meet a changing environment that could challenge their ability to maintain an adequate return to shareholders. Some utilities are seeking to adapt to this 21st century environment, while others are extending the 20th century habits that have made them successful. One of the primary methods is to invest in capital intensive projects that have a long-term revenue stream. Especially if that project yields a higher rate of return, such as is offered by FERC, compared to the lower returns granted by state regulators. Once a project receives regulatory approval, long-term returns are essentially guaranteed; particularly if your affiliates are your customers. This is good fortune for shareholders even though the higher costs must be borne by ratepayers.

It might make commercial sense to locate a supply header in an area where Dominion-owned gathering pipelines terminate in Dominion-owned storage facilities and for gas to be transported over a Dominion-owned pipeline to be used in Dominion-owned power plants. Many intelligent, capable people are on Dominion’s staff. They have likely optimized the choices for commercial gain. However the question before us is – does this option best serve the public convenience and necessity?

The issue of eminent domain is also somewhat reduced. In 2013, Virginia added an amendment to its state constitution regarding eminent domain. This change was intended to limit the abuses of the law for the forced taking of private property solely for commercial gain. The barriers to obtaining the right to exercise eminent domain are lower at the federal level.

As identified earlier, the Commission noted in its 1999 Policy Statement, that in the course of its deliberation about whether a project fulfills the public’s convenience and necessity, the “Commission’s goal is to appropriately consider the enhancement of competitive transportation alternatives, the possibility of overbuilding, the avoidance of unnecessary disruption of the environment, and the unneeded exercise of eminent domain.” We ask that the Commission bears these issues in mind when evaluating alternatives to the ACP.

In our Petition to Intervene submitted November 3, 2015 we identified an alternative to ACP that provides a greater supply of natural gas, has far less disruption of the environment, no need for pipeline construction in Virginia, three miles of new pipeline in West Virginia, and a significantly lower cost than the Atlantic pipeline.

The 18 Bcf/d of new takeaway pipelines proposed to be in place by 2017 will allow Marcellus production to access the existing national gas transmission system. As this occurs, much of the Marcellus production will travel directly to markets in the Mid-Atlantic and Northeast. This major shift in the flow of natural gas will free up pipeline capacity in the Transco corridor that has been dedicated to moving gas from south to north. These pipelines are being repurposed so they can facilitate the flow of gas southward from the Marcellus to supply gas to Virginia, North Carolina and elsewhere. The Department of Energy, in its Natural Gas Infrastructure Report (February 2015), recognizes this plan and documents that there is sufficient capacity in existing pipelines to meet the projected needs in Virginia and the Carolinas. Reversing flow in existing pipelines gives the security of sourcing gas from both the Marcellus and the Gulf Coast, saves money and avoids environmental impacts. This option also avoids overbuilding new pipelines when the long-term need for them is uncertain.

Dominion recognizes that such flow reversals are occurring but they state that existing pipelines do not replace the need for the Atlantic pipeline. Their reasoning is that their customers (their affiliates) support the need for ACP as evidenced by their contracts. It is understandable that Dominion prefers a project which yields them much higher profit and makes use of their existing gathering pipelines and storage facilities in West Virginia. If Dominion could identify a pipeline corridor where all existing landowners would voluntarily accept the pipeline right-of-way, Dominion’s commercial interest might win out. However, on the identified corridor for the ACP numerous landowners oppose the disruption of their property by the pipeline, as do many public stewards of recreational, historical and cultural areas affected by construction. To gain the right to access the property of unwilling owners Dominion must show that the Atlantic pipeline best serves the public convenience and necessity. We believe the public interest is far better served by using existing pipelines.

Dominion argues that Atlantic Sunrise has its own customers. If Dominion’s easily discarded 20-year commitment for gas supply via the new Southside Transco spur is any indication, promises made to gain approval for pipeline construction are not ironclad. We identified the Atlantic Sunrise project to show that capacity greater than ACP was being brought into the existing Transco system. This project also has its supply header in the highest production area of the Marcellus (northeastern Pennsylvania). Billions of cubic feet per day of production traveling via new takeaway pipelines will be transported from the Marcellus, much of which will supply the Transco system. The Leidy extension and other projects will also be bringing greater volumes of natural gas into the Transco system. Gas developers in the Marcellus are suffering from low prices and overproduction. This is a perfect time for customers to negotiate firm long-term supply agreements on favorable terms.

It is very likely that firm contracts for natural gas are available using existing pipelines, but Dominion is reluctant to abandon the commercial advantage of building its own pipeline. Only a comprehensive, even handed review by the Commission will reveal what is in the public’s best interest.

The WB Xpress project was identified because it adds 1.3 Bcf/d of additional capacity in 2018 to the Columbia Gas transmission system in West Virginia and Virginia. This additional capacity is gained by installing a new compressor station and other upgrades and just 2.9 miles of new pipeline and 26 miles of replacement pipeline in existing corridors. Adding capacity to the Columbia Gas system would provide greater supply to the overall Virginia natural gas network and to the Chesapeake, Virginia region as well. The main Columbia Gas line feeds the existing AGL (Virginia Natural Gas) line which supplies the Chesapeake/Norfolk area. Using the greater capacity in the Columbia pipeline avoids the need to construct a 77 mile 20” pipeline on new right-of-way that is part of the ACP project.

Using the additional capacity in the Transco and Columbia gas pipelines serves Virginia better than the ACP. These existing pipelines cover most of the state. The locations of the two new gas-fired power plants which are prompting the need for the ACP in Virginia have not been identified. If the need for them is approved by the SCC they can be located wherever in the state they best serve the load and grid reliability. The ACP limits this flexibility and could increase costs for transmission and gas supply spurs compared to the option of using existing pipelines. Gas for commercial and industrial expansion in Virginia is far easier to access using existing pipelines. Dominion has set an extremely costly threshold for tapping into the ACP, making it uneconomic for most businesses except utilities and very large industries.

Virginia and West Virginia are better served by accessing more natural gas supply using existing pipelines. West Virginia has no access to gas in the ACP; but it is exposed to the disruption of construction. With additional existing Columbia Gas pipeline capacity, West Virginia gains greater supply with minimal disruption. Using existing pipelines avoids construction of nearly 300 miles of pipeline and the cost of transporting gas to the final customer is less than using the Atlantic pipeline.

The interests of customers in North Carolina are also benefited. The additional natural gas provided by reversing flow in the Transco system is easily accessible to North Carolina customers. They can connect to the Transco supply via the right-of-way in southern Virginia that roughly parallels the North Carolina border near where the ACP is proposed to cross. Or they can link to the main Transco corridor in west-central North Carolina. They can choose the options with the lowest costs and fewest impacts. The choices for North Carolina customers are as good as or better than those offered by ACP. There is no need to build the Atlantic pipeline to properly serve the requirements for additional gas supply in North Carolina.

Using existing pipelines meets the projected needs for additional gas supply in Virginia without requiring additional investment and environmental disruption. We have identified the possibility for much higher gas prices and the many factors such as energy efficiency and more rapid solar development that could postpone or perhaps entirely eliminate the need for more gas-fired baseload power plants in Virginia after 2020. Existing pipelines adequately deal with both the higher and the lower demand scenarios. If the Atlantic pipeline were to be approved, we would be exposed to the disruptions from construction and the cost of the pipeline whether or not it was needed in the future. Developers invest in pipelines, but the residents who are electric and gas customers pay for them. The Atlantic pipeline involves higher costs, far greater environmental impacts, the unnecessary use of eminent domain, and greater risks than supplying future gas demand using existing pipelines in Virginia.

C. Increased Development of Renewable Energy Cannot Replace the Need for ACP

The U.S. energy industry is entering a period of fundamental change. 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. 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.”

A report by the AEE Institute, “Competiveness of Renewable Energy and Energy Efficiency in U.S. Markets”, investigated the contribution of these new technologies to future load growth and energy use. One of the first points the study raised is that we are very bad at forecasting how quickly renewable generation and energy efficiency will grow. The U.S. Energy Information Administration’s Annual Energy Outlook (AEO) is a widely used source of information on U.S. energy market projections. In the 2015 AEO, it was forecasted that the installed solar capacity in the U.S. would double by 2026. Based on actual projects already in the pipeline, nationwide solar capacity will double by 2016. Many have read the AEO projections and are acting on the assumption that renewables will not make a major contribution for years. In the past year, 50% of all additions to U.S. generating capacity have been from renewable sources. Solar and wind generation make economic sense today and will be used to an even greater extent in the future.

In order to compare the cost competitiveness of various generation technologies, Lazard, a financial advisory firm, developed a measure called the Levelized Cost of Energy (LCOE), which measures the average cost of electricity over the life of a project, including the cost of initial capital, operations and maintenance, fuel and financing. From 2009 to 2014 the LCOE of utility scale solar power fell by 78%. Solar power at utility scale (LCOE of $0.05-0.075 /kWh) is already cost competitive with natural gas combined cycle plants without any incentives factored in. Many experts predict that solar prices will fall by at least 50% more in the next 5-6 years.

Energy efficiency is clearly the lowest cost way of providing more energy, with an LCOE of $0.00 – $0.05 /kWh). Most commercial and industrial efficiency projects have a cost of $0.02-$0.03/kWh. Projecting the growth in energy efficiency is difficult because you need to measure something that is avoided (the energy you would have used without the efficiency measures). Many are becoming aware of the low cost and many benefits of energy efficiency. The Department of Defense has an aggressive program to improve energy efficiency and integrate solar generation into the energy plans for their bases around the world. Numerous military bases are in Virginia and the DOD programs will gradually reduce energy demand in the state. Massachusetts has recognized the benefits of efficiency and has established a plan to provide 30% of the state’s energy using energy efficiency by 2020. Similar savings are possible in Virginia with appropriate leadership.

We have already addressed that the CPP is not expected to require the construction of more pipelines in our region. Any additional gas required in the Southeast is expected to be provided by the reversal of flow in existing pipelines. In fact the CPP could result in less gas being used. Natural gas is only “less bad” compared to coal, as about 50% of the CO2 is emitted in a natural gas-fired plant compared to an equivalent size coal plant. Solar is cost competitive with natural gas power plants and energy efficiency options are much less expensive. Both have no carbon emissions. Since renewable generation and energy efficiency can be used as CPP credits, it is quite possible that the CPP will encourage more rapid adoption of these technologies and reduce the use of natural gas for power generation.

Many large companies are pursuing energy efficiency and renewable generation outside of the typical utility channel, so significant reductions in load growth may come as a surprise to utility planners. IKEA and Staples are cutting energy use and procuring renewable power. WalMart intends to meet all of its power needs with renewable energy by 2020. Technology companies such as Apple, Microsoft, Amazon and Google are moving quickly to power their data centers and the remainder of their organizations with renewable energy, as well as improving energy efficiency. Owners of commercial and industrial buildings are also making rapid strides using these technologies to lower their cost of doing business.

We have seen how far off the Annual Energy Outlook estimates are, despite the best intentions. Dominion’s plans are no different, colored by past experience and created by a certain viewpoint of how the future is likely to unfold. Certain trends are emerging, however. First, the cost reductions and adoption of solar is happening much faster than most people expected only a few years ago. Second, there is a greater realization of the benefits of energy efficiency. Experts have found that by spending more on efficiency, substantial cost savings occur by downsizing heating, cooling and pumping systems. As more successes are reported, more projects will be initiated. Third, over time natural gas prices are likely to increase, making electricity generated in gas-fired plants more expensive. As the prices of zero carbon alternatives such as renewables and energy efficiency continue to fall, gas-fired power plants become less competitive.

The first new power plant requiring additional gas supply to Virginia is proposed for 2022. In the next seven years, the results of these trends will be much more apparent. It is very possible that greater energy efficiency and more rapid adoption of solar generation could postpone or replace this new power plant and thus delay or eliminate the need for the Atlantic pipeline. Dominion is asking the Commission to hurry a decision, bypassing thorough procedures, so that they can begin construction soon. We counsel the opposite approach. Because the future is unclear and much is likely to change within the next 5-10 years, we recommend that the Commission select the option of using existing pipelines which requires the least investment, the least environmental impact, the least disruption of people’s lives and property, yet still provides adequate gas supply should the high gas use estimates prove to be correct. If a lower need for gas comes to pass, the use of existing pipelines is also the best solution, since it easily allows surplus supply to be routed elsewhere, wherever there is a greater need. If the Atlantic pipeline is built and the demand for gas diminishes – then the investment is wasted, individuals pay for the mistake, the disturbance of the land and the anguish of unwilling landowners will be for naught. You cannot easily remove an unnecessary pipeline once it is constructed.

D. ACP’s Adverse Effects versus its Benefits

We believe that the benefits of the ACP do not outweigh its substantial impacts. The benefits have been erroneously and substantially overstated and its effects have been minimized and undervalued. A superior option exists to serve the same purpose which far better serves the public convenience and necessity.

Adverse Effects on Existing Customers

As we have previously discussed, the ACP is a new development and as such has no existing customers. However, Dominion and the other ACP partners have used their affiliates (subsidiaries of the same parent companies) to justify the need for the Atlantic pipeline. They speak with the same voice. These affiliates have existing customers who are adversely affected by the Atlantic pipeline. Transporting natural gas with the ACP is more expensive than using existing pipelines. This higher cost will be automatically passed on to the captive customers of the affiliates, without notice or an opportunity to object. Approval of the ACP is under federal jurisdiction and the state agencies normally charged with consumer protection are foreclosed from this proceeding. We recommend that the Commission calculate the difference between the higher gas transportation charges that will exist for the ACP compared to the lower transportation charges using existing pipelines, multiply this times the volume of gas that will be transported over the life of the Atlantic pipeline and add this substantial cost to the adverse effects of the ACP.

Adverse Effects on Existing Pipelines and Subsidies

The substantial extra cost paid by existing customers of the affiliates to transport gas via the Atlantic pipeline instead of lower cost existing pipelines amounts to an involuntary subsidy of the ACP.

Transco is building a new spur to serve the new gas-fired power plants being built by Dominion in Southside Virginia. Phase I of the pipeline is expected to begin operation in late 2015 to provide for pre-commercial testing of the Brunswick plant scheduled to begin service in 2016. Phase II makes a 4 mile connection in late 2017 to the Greensville plant that is under development. Dominion proposes to connect these two power plants to the ACP in 2018 and revoke its 20-year Transportation Service Agreement it made with Transco to secure approval to build the new pipeline. The Commission should consider that Dominion’s share of the capacity of the pipeline (96%) be multiplied times the $490 million (plus interest) that it cost to build the spur and consider this total as an adverse effect on an existing pipeline and an overall adverse effect of the Atlantic pipeline.

Pipelines in the Transco corridor are expected to be repurposed to move gas from the Marcellus to serve markets in Virginia and the Carolinas as identified by the Department of Energy in their Natural Gas Infrastructure Report (February 2015). The ACP proposes to usurp this intended role of the existing pipelines, and as such they will be underutilized. The economic loss from poor utilization of this existing resource should also be considered an adverse effect of the ACP.

Adverse Effects on Landowners and Communities

The Commission has a difficult task attempting to characterize the many varied and substantial impacts of ACP construction. Attempting to represent environmental impacts in a monetary fashion in a cost/benefit analysis has been a challenge ever since the National Environmental Policy Act was enacted many decades ago. Calculations are further complicated by the fact that there is no settled route for the Atlantic pipeline. So many options have been identified it is difficult to understand how to make the tally of the impacts.

Developers typically greatly underestimate the true nature of the impacts. They usually say they have minimized the adverse effects and the impacts are identified in the prices paid for land and easements obtained from landowners whether voluntarily or involuntarily.

The Commission has a multitude of responses from landowners and communities in public forums and comments sent to the Commission indicating the extent of disruption expected to be caused by construction of the ACP.

Even if a considerable effort is made to express the damages and disruptions caused by constructing and operating the Atlantic pipeline, we believe that a monetary amount can never fully express the value of the loss. Can a landowner whose family has been stewards of the land for generations, the character or access to which has been altered for the next 100 years, be properly compensated? What about communities that lose their cultural or historical heritage? How can the effects on an internationally known meditation center be expressed in economic terms when they are exposed to the sounds of compressors thumping away 24 hours a day? We have spoken to the managers of our municipal water supply. They express how fortunate we are to have such a reliable, high quality source of fresh water. When asked if the blasting or other effects of construction could affect the ancient aquifer, they respond that it is possible because it is such a complex system. If so, there is likely to be no way to remedy the damage and the valuable water source could be irretrievably affected. Many of the things that sustain us and make our lives meaningful cannot be expressed in monetary terms.

Purported Benefits of the ACP

ICF Study

All of the $377 million of net energy savings supposedly originating from the price difference between the Dominion South Hub compared to the national price at Henry Hub is based on an incorrect assumption, as previously discussed. The current lower price at Dominion South results from overproduction in the Marcellus and the shortage of takeaway pipelines to bring the gas to market. This stranded gas can only find a market at a significantly lower price than Henry Hub. By 2017, before the ACP is proposed to begin operation, adequate takeaway pipelines will be available to move the Marcellus production into the existing gas transmission system and the price differential will disappear. Therefore, there is no economic advantage related to this issue for the ACP and the indirect effects on employment, labor income, and state economic activity should be dismissed as well.

This removes $724 million and 2,225 indirect jobs from the benefits of the ACP. If for any reason, a price advantage is presumed to exist in the Marcellus, the same advantage would be available for gas moved by existing pipelines.

Chmura Study

It is difficult to recast a more accurate statement of benefits identified in the Chmura report because the data and methodology used to calculate the benefits is not clearly identified. However, general comments can be made that could help the Commission’s staff create a more realistic tabulation of these benefits.

One-Time Impact from Construction

Chmura assumes that 50% of the average of 1,557 people employed per year during the 2014-2019 period of construction will be hired locally. Another developer for a 42” pipeline between West Virginia and Virginia expects to employ just 10% of the workers from local sources. The 500% higher assumption for local labor greatly inflates the amount of local benefits.

Only 5% or less of the material used for construction will be obtained locally.

We believe the models used to generate indirect and induced benefits do not apply to the short-term transient nature of the pipeline workforce. The models usually assume that a new worker resides full time in the area of construction so that their entire paycheck will circulate throughout the community and have secondary benefits to other businesses and perhaps help create additional jobs. Workers from outside the area will send most of their paycheck home to their families. We suggest that very few indirect and induced benefits will accrue from one-time construction.

These more reasonable assumptions result in a few hundred local jobs coming from pipeline construction, with the indirect benefits limited to short bursts of additional sales for gas stations, grocery and convenience stores, motels and local bars that benefit from the temporary stays of the construction crews. This is in stark contrast to the thousands of jobs and hundreds of millions of dollars that Dominion claims will benefit the region that must suffer the impacts and disruption of construction.

Economic Impact of On-Going Operation

Twenty-four workers in West Virginia, 39 in Virginia and 18 in North Carolina will be permanently employed by the pipeline. We expect these workers to come from widely dispersed areas so that there is no concentration of new spending to create any appreciable indirect or induced effects.

Chmura assumes $69.2 million of annual benefits will result from pipeline. This huge sum results almost entirely from the value of natural gas in the pipeline (gross sales of ACP). This is an imaginative leap. The value of the gas is independent of the pipeline. The value of the pipeline is that it provides transportation services.

Tax Revenue

In its calculations, Chmura appears to have assumed that all construction workers will pay income tax to the states in which construction occurs. Typically, people who work part of the year in another state will pay all of their income tax to the state where they permanently reside. Again, flawed assumptions create exaggerated estimates of the benefits accruing to the region of construction.

The corporate income tax paid by ACP appears overestimated. It seems the entire amount of profits are assumed to be taxable. The amount of depreciation is deducted from profits before taxes are paid. ACP is unlikely to pay very much tax on their profits for the first 30 years or so of pipeline operation.

Property taxes paid to local governments by the Atlantic pipeline are likely to be greatly offset by lower taxes paid by landowners because the value of their property has declined because of the presence or proximity of the pipeline.

Summary

We are concerned that the benefits of the Atlantic pipeline have been greatly exaggerated due to faulty assumptions. We encourage the Commission to evaluate the calculations carefully to arrive at figures which more accurately represent what is likely to happen.

It is one thing to use inflated figures to drum up political and popular support. But numbers created for PR purposes should not be used as the basis for decision making for a $5 billion project that has significant impacts. The applicants’ process appears to have gone something like this: we make much more profit if we transport the gas in a pipeline that we own (even if it costs the ratepayers more); let’s get the subsidiaries of our parent companies (our affiliates) to say they need the pipeline and they can be our customers; when they agree to a contract we can show the Commission that there is a demand for the pipeline; we will create such large numbers to show the benefits of the project that no matter how great the impacts of the pipeline, the benefits will always appear to be greater; the Commission will approve our project because they usually do; then we can put it on people’s property who don’t really want it there; if our customers don’t actually need the gas, they can back out of their commitments; but by that time we will have built the pipeline and will have a long term stream of revenues – someone will have to pay for it.

We do not mean to be impertinent. These are serious issues. But earnest attempts at gaining more information or proposing alternatives for evaluation are dismissed out of hand with responses such as, “there can be no question that the ACP is needed”. Well, there are questions. That is why so many concerned citizens are involved in this process.

We believe there is a way to resolve the question. Choose a better option. The goal is to supply additional natural gas to where it is needed. The question is – whether the Atlantic pipeline is the best way to accomplish that. We propose a better way to serve the public’s convenience and necessity.

The ACP requires the construction of nearly 300 miles of 42” pipeline and 77 miles of 20” pipeline in West Virginia and Virginia. Doubling the amount of gas supplied using existing pipelines requires 3 miles of new pipeline and 26 miles of upgraded pipeline in West Virginia and no new construction to serve the needs in Virginia. North Carolina customers have as good as or better choices using existing pipelines than are offered by the ACP. Gas transportation charges will be lower with existing pipelines. And by choosing not to overbuild new capacity, the risk is reduced and we have maintained a much more flexible response to an uncertain energy future while preserving the ability to meet both high and low gas demand scenarios.

E. Programmatic or Regional EIS

Whether an EIS is prepared or not, the several proposals for delivering natural gas to the Virginia and North Carolina markets should all be considered in the context of the themes we have developed in these comments. The rush to develop new pipelines in this region is in response to an apparent abundance of low cost natural gas and an expected rise in gas demand.

We have identified that the apparent abundance is an artifact of the developers in the Marcellus drilling more wells in order to stay in business. Many of these companies have already declared bankruptcy because of lower than expected yields from shale gas wells and low market prices. There will be more to come. Independent studies performed by a University of Texas team and others show that the production of affordable natural gas ($4 mcf) will likely peak in 2018-2020.

Overproduction in the Marcellus brought down natural gas prices nationwide. The shortage of takeaway capacity to bring Marcellus gas to market lowered the price (at Dominion South) even more compared to the national price (Henry Hub). The current development of more takeaway pipelines by 2017 will bring the full Marcellus production into the existing gas transmission system and prices will equalize. None of these new pipeline proposals should be approved, including the ACP, by assuming that the unusual gas supply circumstances of the past five years will apply over the 60-80 year existence of these projects.

Dominion argues that the Mountain Valley Pipeline (MVP) and the Appalachian Connector have their own customers and will not compete with the ACP. That might be so on paper. However, the demand for traditional uses of natural gas in this region is expected to be flat for at least the next 25 years. The only need for more natural gas supply is to fuel power plants. The developers of the ACP are affiliates of the largest electric utilities in Virginia and North Carolina. What is the true market for the MVP or the Appalachian Connector if not the same one proposed for the ACP?

The predicted long-term increase in demand for natural gas to fuel power plants is an illusion similar to that of long-term supplies of low cost gas. It is based on a five-year long phenomenon that has been assumed to remain long into the future. Over the next five years, many aging coal-fired power plants will be retired because they are too expensive to retrofit to bring them into compliance with new air quality regulations. In many cases, the best replacements for these retiring units will be new natural gas fired units or conversions of coal plants to burn natural gas.

Beyond 2020, the need for additional natural gas combined cycle units will be to meet projected increases in electrical demand. But what if the increase in demand never occurs or there are better options to fulfill it. Trends in energy efficiency show that the low cost and many benefits of this option could substantially lower load growth or perhaps even cause it to decline. Rapid cost reductions in solar and the speed at which it can be deployed make solar particularly well suited to respond to the growth in peak loads which is the primary factor requiring more generation. Traditional utility planners continue to project the need for more gas-fired baseload power plants, but developments in the next few years may change their approach. The rapid evolution of our energy system is an issue we should be mindful of when making long-term choices for developing natural gas infrastructure.

When the Commission chooses to use existing pipelines for their lower cost, flexibility in meeting a wide range of demand, and far less environmental impacts compared to the ACP; this conclusion also should apply to the Mountain Valley Pipeline and the Appalachian Connector.

F. Analysis of Gas Production

If the Commission chooses not to consider the environmental effects of shale gas development, they should still carefully consider its geology and the prospects for long-term natural gas production at affordable prices. 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. His findings regarding Marcellus production 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.

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.

The main difference between the Texas study and Energy Information Administration (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”.

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 industrial plants and vehicles 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.”

Energy industry leaders and government policy makers have been swayed by the inaccurate statements about the size of the shale gas resource. They have also been misled by the temporary low price for natural gas and have accepted the notion that we will have an abundant, long-term supply of affordable natural gas. That’s a benefit if it happens, but what if it doesn’t? High natural gas prices would reduce the need for more gas-fired power plants, as they are replaced by lower cost alternatives or not needed at all. High gas prices would also promote greater energy efficiency and reduce the need for more electricity generated by gas-fired plants and the traditional uses of gas for space and water heating.

Decisions about the development of natural gas pipelines have long term consequences. We recommend a choice that considers this long view and best accommodates the many different possibilities.

G. Need for Hearing

Our experience with the public review of multi-billion dollar utility projects in other states and at the federal level always involved an Administrative Law Judge from the appropriate agency and allowed the parties access to all of the information and the right to cross examine witnesses. This led to an expensive and time consuming process, but it usually did illuminate the issues for final determination by the responsible agency.

Our concern is two-fold. First, is the Commission’s history of approving applications for projects because the developers say they are needed. This is usually supported by “long-term contracts” from customers (often affiliates of developers) that are supposed to signify that there is a “need” for the project. We hope that our comments and those of others, plus Dominion’s behavior regarding the Transco spur, raise questions as to whether such “contracts” should be used as the primary means of establishing need. We believe that the identified customers’ need for additional gas supply could be served at a lower cost and with far fewer impacts using existing pipelines. The existence of “contracts” does not prove that the ACP is the best available method to meet the need.

Second, adjudicatory hearings require the applicant to actually answer questions. Many of the questions regarding assumptions and alternatives that have been posed have not been met with information that more fully explains Dominion’s conclusions and how they arrived at them. Rather, some of the responses have been “there can be no question that . . .”, “obviously”, etc.

Perhaps a paper exchange can uncover adequate information to allow the Commission to reach a knowledgeable conclusion about the best means to serve the public convenience and necessity. But all parties must be committed to an open and objective exchange of information for that to work. Thus far in the proceeding that has not been the case.

H. Issues Raised by the North Carolina Utilities Commission

This section is most illustrative of what the ACP is all about. It is about money. It makes business sense for Dominion to own the pipeline they hope will supply its power plants. The same applies to Duke Energy. Together they own 85% of the pipeline. It is a competitive advantage to control their natural gas infrastructure and they prefer to pay themselves rather than someone else to transport the gas.

The North Carolina Utilities Commission (NCUC) is saying that pipeline developers are expecting to be paid too much. Dominion is asking for a 14% return on equity for the 50% of the pipeline that will be funded in this manner. The state approved rates of return for utility projects are usually about 10-11%. This 14% rate is a very attractive rate of return when investments backed by the U.S. government yield less than 2%. And the interest rates on the bonds for the remaining 50% of the capital necessary to fund the pipeline will yield in the mid-single digits. The Commission has limited the developers equity share to 50% of the pipeline expense because otherwise it would be too expensive for rate payers.

The developers of the ACP consider their utility affiliates to be the customers of the pipeline, but in reality it is the utilities’ customers, the ratepayers, who will pay more. Transporting gas in the Atlantic pipeline will be more expensive than transporting the gas in existing pipelines (that have already been mostly paid for). These higher transportation costs will be automatically passed through to ratepayers without regulatory approval or customer consent via the fuel cost adjustments on monthly utility bills.

Normally we encourage corporations to look out for their own best interests. That is how our economy runs. However, in this case the developers are asking others to sacrifice in order for them to gain. In our market economy we support transactions between a willing buyer and a willing seller. If Dominion could arrange a transaction that satisfied the ratepayers and the landowners whose property they want to use, the project would be supported. But the ACP as proposed will infringe on many areas where the landowners and communities don’t want it because it degrades their way of life and the area in which they live. The ratepayers don’t know they will pay more for it and no agency is involved in the federal process that will represent their interest.

Because the Commission can grant ACP the right to disrupt property without the owner’s consent, the Commission must carefully deliberate to determine if this proposal serves the public’s convenience or necessity; or if another alternative serves that in a better way.

III. Conclusion

We believe that a portion of the 18 Bcf/d of Marcellus gas supply that will gain access to the existing gas transmission network by 2017 can be transported southward using existing pipelines. The Department of Energy reports that pipelines in the Transco corridor can be repurposed to move gas from the Marcellus to markets in Virginia and the Carolinas. This also affords the opportunity to provide gas from the Texas and Gulf Coast production regions to offer a backup source of supply.

With an upgrade to the Columbia Gas system which requires only three miles of new pipeline, an additional 1.3 Bcf/d can be brought into the existing West Virginia and Virginia pipeline system. The statewide network of Transco and Columbia Gas pipelines in Virginia provides far more flexibility for utility and commercial and industrial expansion than is offered with the ACP, without requiring any new pipeline construction to serve the needs of Virginia.

Customers in North Carolina also benefit. The additional natural gas provided by reversing flow in the Transco system is easily accessible to North Carolina customers. They can connect to the Transco supply near where the ACP is proposed to cross, or they can link to the main Transco corridor in west-central North Carolina. They have the choice of options with the lowest costs and fewest impacts. The choices for North Carolina customers are as good as or better than those offered by ACP. There is no need to build the Atlantic pipeline to properly serve the requirements for additional gas supply in North Carolina.

Failure to utilize existing pipelines with adequate capacity to carry the volume proposed for the Atlantic pipeline would under utilize a low-cost resource, overbuild new capacity, and cause unnecessary disruption to landowners and sensitive environmental, recreational, and historic areas and cause the taking by eminent domain from landowners who would otherwise not voluntarily grant the right for a pipeline to exist on their property. A lower cost, lower impact, lower risk option to the Atlantic Coast Pipeline exists by utilizing existing pipelines. We strongly urge the Commission to accept it in place of authorizing the ACP.

 

Superior Alternative to Atlantic Coast Pipeline

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.

Alternatives

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.

Summary
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.

Atlantic Coast Pipeline: Executive Summary

The Atlantic Coast Pipeline and Cheap Natural Gas

The Early Days
• 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; prices rose to over $13.50 mcf in 2008. We started to import natural gas.

• With high prices it made sense to use an expensive technique called “fracking” to get at the hard to extract gas in shale formations across the U.S.

• The U.S. Energy Information Administration (EIA) reported that there was an abundance of shale gas available.

• Developers took the easy money and started drilling in the major shale gas formations (“plays”).

• Drillers 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 and demand sank; prices began to fall.

Wall Street Steps In
• When the housing bubble burst, Wall Street investment banks went looking for new money-making opportunities.

• The investment bankers saw the dire situation the shale gas developers were in. 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.

The Majors Move In
• As the second group of developers looked for a way out of their failing investments, major oil companies stepped in and acquired the leases.

• For a number of years, major oil companies had not fully replaced the resources they sold and their share prices suffered for it.

• After heavy lobbying, the SEC had passed a ruling which allowed higher undeveloped reserves to be reported on companies’ books. This new ruling saved many shale gas developers from financial ruin.

• By buying into the shale gas plays, major oil companies could report higher resource reserves and improve their share prices.

• Politicians wanted the U.S. to exert more worldwide influence using the new found energy resources and recommended exporting liquefied natural gas (LNG) to foreign markets.

• Energy companies often deal with projects that take a long time to develop. They made the same assumptions as everyone else – that there was a long-term source of inexpensive natural gas and the companies began making plans to exploit it.

• Dominion had several goals:
o Build pipelines, gas storage facilities, and natural gas liquids plants in the Marcellus formation.

o Develop new gas-fired power plants to replace highly polluting coal plants and aging nuclear plants.

o Build a pipeline from the Marcellus to Virginia and North Carolina to bring gas to the new power plants.

o Develop an LNG export facility in Cove Point, MD to make money from the export of gas overseas.

 

Reality Sets In
• A University of Texas team of petroleum engineers, geoscientists and resource economists conducted a three year study of the U.S. shale gas plays.

o The EIA study used entire counties (hundreds of square miles) as the size of the parcels they studied.

o The EIA assumed results from the best wells would be replicated all over the county.

o The University of Texas study reviewed one square mile parcels and used well data for each parcel.

o The Texas team discovered that there are “sweet spots” with high production and large areas with unproductive wells.

o The Texas team concluded that the EIA estimates were far too optimistic regarding the amount of affordable gas (using EIA’s $4 mcf figure) that could be produced in the Marcellus. The UT scientists estimated that at this price, production from Marcellus would peak about 2020 and rapidly decline thereafter. More natural gas would be available only at a much higher price.

What is Going on Now?
• Over the past several years drillers have become very efficient at working the “sweet spots”.

• Technology has advanced so more wells are drilled from a single drilling rig, making drilling more productive and less expensive.

• 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.

• Energy companies and the media used the surplus gas selling at low prices to reaffirm the notion of a large amount of cheap shale gas; rather than noting the true causes of the lower price.

• 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.

• An expert geoscientist has studied the 2014 well data from the Marcellus and concluded the following:

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

o 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.

o 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.

o 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 Marcellus gas at a significant discount to national gas prices.

o 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).

o As for the massive investments in infrastructure on the assumption of cheap and abundant gas for the foreseeable future – CAVEAT EMPTOR.
Years of actual drilling experience in the Marcellus and in-depth studies by independent analysts revealed a far different picture for the long-term U.S. gas supply than what was originally assumed. Yet energy companies, regulators and policymakers are moving forward with their projects and programs heedless of the new information.

 

Dominion Claims Benefits from the Pipeline
To make their case to the public and in order to obtain the right to use eminent domain, Dominion has claimed that several benefits will accrue as a result of the pipeline. They are as follows:

Jobs
• One of the most popular claims for any new development is that it will create jobs.

• Dominion foresees that many of the workers needed to construct the pipeline will come from Virginia and North Carolina and their incomes and economic activity during the project will benefit the locations through which the project passes.

• A pipeline project proceeds in phases, with different crews doing different types of jobs. Although the total construction time for the project is approximately two years, each type of crew would be employed for a shorter period.

• Skilled employees needed for the specialized work of building a pipeline will be drawn from a regional and national labor pool as opposed to primarily from general laborers available in Virginia and North Carolina.

• Other than daily expenses for food, gas and motels, most of the workers’ paychecks will be sent home to another state.

• The intermittent influx of crews staying for a few days to accomplish various phases of the pipeline work will not likely prompt any new hiring in the locations in which they stay.

• The number of direct short-term construction jobs that will go to Virginians and any indirect economic benefits deriving from them will likely be far less than what has been claimed.
In fact, there could be a net loss of jobs.

• The CEO of Dow Chemical and an industry group representing U.S. manufacturers with a combined $1 trillion of annual revenue have argued that the energy policy which gives rise to the pipeline will cost Virginia thousands of its 231,000 long-term manufacturing jobs.

• They have opposed the rush to burn more gas in power plants and the export of LNG, saying that those policies will cause a substantial rise in natural gas prices.

• U.S. manufacturers are beginning to return jobs to this country because our affordable prices for natural gas and natural gas liquids give them an advantage over their overseas competitors.

• These large corporations argue that using up our affordable gas for exports or to fuel power plants will raise our domestic gas prices 2-3 times higher than if we maintained our traditional uses of gas.

• Australia has already experienced the path being mapped out by Dominion and other energy companies. They have had to close many manufacturing plants and lay off employees because of rising gas prices.

• 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 says the Department of Energy, “while the vast majority of the people in the country will lose economically”.

• Using renewable sources would provide many more jobs than those created by building more gas-fired plants because more workers are needed to build renewable facilities. The overall cost is about the same; higher labor costs are offset because wind and sunlight are free.

• A more thorough analysis should be conducted that would take into account more realistic assumptions.

• Increased prices for natural gas could cause a large scale loss of jobs in the manufacturing sector in Virginia and throughout the U.S. As a result of the announced projects, Dominion may cause a net decrease in jobs in the state of Virginia.

Savings and Jobs from Pipeline Operation
• In a report commissioned by Dominion, ICF International of Fairfax, VA and Houston TX, has claimed substantial economic benefits to derive from the Atlantic Coast Pipeline.

• 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. 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.

• The surplus supply in the Marcellus and the lack of connections to the existing pipeline system backed up supply in the Marcellus and lowered prices with gas selling at a discount of $1.50 compared to Henry Hub.

• This was five times larger than the discount from a year earlier.

• ICF used this largest historical price spread and assumed that it would last the life of the pipeline.

• Lack of sufficient connections to the existing pipeline network to get the gas out into the general market strands supply in the Marcellus and lowers its price. This situation is expected to be remedied by 2017 before the Atlantic Coast Pipeline is in operation.

• Two independent studies confirm that original estimates of the size of the affordable gas reserve ($4 mcf) in the Marcellus have been significantly overstated.

• An in-depth independent study performed using 2014 drilling records in the Marcellus revealed:

o 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.

o 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 Marcellus gas (from the Dominion South Hub) at a significant discount to national gas prices.

o Marcellus production (at $4 mcf) is projected to peak in 2018, followed by a terminal decline (more gas could be available at higher prices).

• The long term savings projected by ICF is only a temporary phenomenon; expected to disappear even before the Atlantic Coast Pipeline is projected to be in service.

• ICF’s assumptions of a prolonged price advantage for Marcellus gas appears to be based on the EIA’s original hopeful but inaccurate forecasts. In the long run, 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 which conducted a three year study of major U.S. shale gas plays, says that after the peak of production, “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.

Are There Alternatives to Building the Atlantic Coast Pipeline?
• Dominion has three new gas-fired power plants: one which began operation in December 2014, one under construction scheduled to open in 2016, and a third under development, planned for 2019.

• Traditional residential, commercial and industrial uses of natural gas are expected to grow very little in Virginia over the next 15-20 years.

• The main growth in gas demand will be for power plants.

• All three new plants will connect to existing pipelines.

• AGL is a five percent partner in the Atlantic Coast Pipeline. Its subsidiary, Virginia Natural Gas, in the Norfolk area, is already connected to a major Columbia Gas pipeline which enters the state from West Virginia.

• The population in the Norfolk area is expected to increase only 0.2% per year over the next several years, assuming no major military base closings. It seems unnecessary to bring a pipeline in from North Carolina to provide gas to area that is already well served.

• Some suspect that it is in preparation to serve a potential LNG facility in the Hampton Roads/Newport News area. But Dominion emphatically claims that no gas traveling in the Atlantic Coast Pipeline will end up at an LNG facility. In any case, does it make sense for AGL to make a major investment in a connection to Marcellus gas which could well be more expensive than the gas it already has available through its connection with Columbia Gas?

• A study by the Department of Energy, “Natural Gas Infrastructure”, states that sources of natural gas supply and demand are not concentrated in any particular part of the U.S. which reduces the need for new pipelines.

• They conclude that a superior choice is to utilize unused capacity in existing pipelines to meet increased needs in most locations; especially since building new pipelines is so expensive and creates many environmental, social and economic impacts.

• 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.”

• 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 existing Transco pipeline also has a leg which extends into North Carolina very near where the Atlantic Coast Pipeline is proposed to enter.

• An extension to the Transco pipeline is proposed to access the Marcellus production.

• Overall, a 1.7 Bcf/d expansion of the Transco pipeline (larger than the 1.5 Bcf/d proposed for the ACP) is expected to be in service in 2018 according to the DOE model.

• Clearly, a pipeline that already exists with sufficient capacity to serve the needs projected for the Atlantic Coast Pipeline would be far superior to building a new pipeline which requires a $5 billion investment; creates substantial adverse impacts on fragile geological areas and water supplies, sensitive habits, unique cultural, recreational and historic areas; and requires the forced taking of property from landowners who choose not to offer Dominion an easement for the construction of a pipeline which would damage their property and alter its character.

 

Who Pays? – When the Pipeline is built and it proves to be a Bad Decision
FERC does not have a good history of successfully determining if a project is truly needed.

The People Of Virginia
• Local residents and the land in the pathway of the pipeline would suffer the greatest impacts from its construction.

• Virginians would gain little benefit from pipeline construction whether by adding jobs or significant new economic activity in their community.

• High gas prices brought on by decline in gas production in the Marcellus and added demand for gas-fired power plants and LNG exports will disrupt Virginia’s economy. Homeowner’s will have higher utility bills and less disposable income.

• Their employers will also face energy price increases and will either have to increase prices of their goods and services or reduce payroll to keep costs in line.

• Manufacturers in Virginia may lose their competitive advantage as higher prices for energy and raw materials (natural gas liquids) increase their costs.

• Access to affordable gas and gas liquids are helping U.S. manufacturers return jobs to America. Higher costs could reverse that trend.

• If there are any savings from the pipeline Dominion’s customers will not see it. Dominion’s rates are now fixed until 2022. No savings will be refunded to the customers; increases in fuel costs will pass through to customers as usual; and so will charges for putting the new gas-fired power plants into operation.
Dominion Shareholders

• Dominion is risking $5 billion on the Atlantic Coast Pipeline and $3.8 billion on the Cove Point LNG facility, both of which are based on the assumption that the U.S. will have a long term supply of affordable natural gas (about $4 mcf).

• The LNG scheme would ship a large amount of affordable gas to other countries. This would raise our domestic prices and shorten the time that we could rely on having our own supply.

• U.S. policy seems questionable, as it relies on using natural gas to politically outmaneuver other countries that have a much larger supply compared to the U.S. gas reserves.

• Our companies could get financially overextended then undercut by foreign suppliers wishing to create economic havoc in the U.S.

• Saudi Arabia has already accomplished this in the shale oil market. It could easily happen with shale gas as well.

• The Department of Energy has concluded that there is enough capacity in existing pipelines to serve Virginia and the Carolinas.

• Dominion could build the pipeline and not have enough customers to pay for it. Then who pays?

• If Dominion’s prices get too high, customers will look to energy efficiency or self-generation to reduce their costs. This would further cut Dominion’s revenues and weaken them financially.

• We need healthy utilities, but if the problems have been all of Dominion’s own making, regulators might seek other ways to meet Virginia’s energy needs.

• Both customers and stockholders suffer if these risky decisions harm Dominion financially.
The Virginia Business Climate

• The biggest loser from the decision to build the pipeline and the Cove Point facility could well be the Virginia business climate.

• With a utility that is choosing to continue an outmoded business model, we are likely to see much higher energy costs in the future.

• Of the 32 largest investor-owned utilities in the U.S., although 12th in size, Dominion ranked last in innovative programs such as renewable energy sales and energy efficiency savings.

• Other states are developing 21st century energy economies and could attract the leading companies to their states as a result.

• Dominion could be a leader in creating a statewide business climate filled with vitality. Imagine if Virginia was the east coast’s least expensive energy provider.

• This would create jobs and attract promising new companies and highly skilled workers. We can maintain the character of our communities and still prepare them for the 21st century.

• Making a transition to this new energy economy needs no new inventions and no new national taxes, mandates, subsidies, or laws. The United States could get completely off oil and coal by 2050, five trillion dollars cheaper than our business-as-usual scenario, with no Act of Congress, led by business for profit.

 

The only thing needed to embark on this path is a change in our mindset and a revision in our regulatory system which rewards a utility for providing energy services.

How nice would it be to have your utility prosper when it finds ways to lower your bill?

This can be accomplished if the customers and the voters of Virginia ask for it. Become informed and speak up for what you want.

 

In the following posts, in-depth articles explain the points summarized here and include references for your own investigation.  The articles follow in the order that the points are presented in this executive summary.

 

Please feel free to make comments and add information to improve everyone’s understanding of the topic.

The Atlantic Coast Pipeline and Cheap Natural Gas – Summary

The Early Days
• 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; prices rose to over $13.50 mcf in 2008. We started to import natural gas.

• With high prices it made sense to use an expensive technique called “fracking” to get at the hard to extract gas in shale formations across the U.S.

• The U.S. Energy Information Administration (EIA) reported that there was an abundance of shale gas available.

• Developers took the easy money and started drilling in the major shale gas formations (“plays”).

• Drillers 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 and demand sank; prices began to fall.
Wall Street Steps In

• When the housing bubble burst, Wall Street investment banks went looking for new money-making opportunities.

• The investment bankers saw the dire situation the shale gas developers were in. 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.

The Majors Move In
• As the second group of developers looked for a way out of their failing investments, major oil companies stepped in and acquired the leases.

• For a number of years, major oil companies had not fully replaced the resources they sold and their share prices suffered for it.

• After heavy lobbying, the SEC had passed a ruling which allowed higher undeveloped reserves to be reported on companies’ books. This new ruling saved many shale gas developers from financial ruin.

• By buying into the shale gas plays, major oil companies could report higher resource reserves and improve their share prices.

• Politicians wanted the U.S. to exert more worldwide influence using the new found energy resources and recommended exporting liquefied natural gas (LNG) to foreign markets.

• Energy companies often deal with projects that take a long time to develop. They made the same assumptions as everyone else – that there was a long-term source of inexpensive natural gas and the companies began making plans to exploit it.

• Dominion had several goals:
1. Build pipelines, gas storage facilities, and natural gas liquids plants in the Marcellus formation.
2. Develop new gas-fired power plants to replace highly polluting coal plants and aging nuclear plants.
3. Build a pipeline from the Marcellus to Virginia and North Carolina to bring gas to the new power plants.
4. Develop an LNG export facility in Cove Point, MD to make money from the export of gas overseas.

Reality Sets In
A University of Texas team of petroleum engineers, geoscientists and resource economists embark on a three year study of the U.S. shale gas plays.

o The EIA study used entire counties (hundreds of square miles) as the size of the parcels they studied.

o The EIA assumed results from the best wells would be replicated all over the county.

o The University of Texas study reviewed one square mile parcels and used well data for each parcel.

o The Texas team discovered that there are “sweet spots” with high production and large areas with unproductive wells.

o The Texas team concluded that the EIA estimates were far too optimistic regarding the amount of affordable gas (using EIA’s $4 mcf figure) that could be produced in the Marcellus. The UT scientists estimated that at this price, production from Marcellus would peak about 2020 and rapidly decline thereafter. More natural gas would be available only at a much higher price.

What is Going on Now?
• Over the past several years drillers have become very efficient at working the “sweet spots”.

• Technology has advanced so more wells are drilled from a single drilling rig, making drilling more productive and less expensive.

• 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.

• Energy companies and the media used the surplus gas selling at low prices to reaffirm the notion of a large amount of cheap shale gas; rather than noting the true causes of the lower price.

• 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.

• An expert geoscientist has studied the 2014 well data from the Marcellus and concluded the following:

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

o 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.

o 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.

o 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 Marcellus gas at a significant discount to national gas prices.

o 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).

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

Years of actual drilling experience in the Marcellus and in-depth studies by independent analysts revealed a far different picture for the long-term U.S. gas supply than what was originally assumed. Yet energy companies, regulators and policymakers are moving forward with their projects and programs heedless of the new information.

 

The full article follows in the next post. It provides more in-depth explanations and references for your own investigation.

The Atlantic Coast Pipeline and Cheap Natural Gas – Full Article

The driving force behind the Atlantic Coast Pipeline and the Cove Point LNG facility is Dominion’s belief that the U.S. has an abundant long-term supply of affordable natural gas which they can profitably exploit using their unregulated subsidiaries. If that premise turns out to be false, it fundamentally changes the business case for these projects.

The Early Days
In the 1990’s natural gas was cheap, selling for $2 per thousand cubic feet (mcf). Then our supplies of conventional gas began to decline. In the easy money days of the early 2000’s people borrowed money to start new businesses and expand existing ones. Demand for natural gas began to exceed supply. We started to import more expensive gas to make up the shortfall in supply causing natural gas prices to rise to over $13.50 mcf by 2008.

A process was originally developed by the Halliburton Company in the 1940’s but was considered too expensive for use while gas prices were low. With high gas prices it made sense to use this expensive technique called “fracking” to get at the hard to extract gas in shale formations across the U.S. Eventually, output from the Marcellus formation in Pennsylvania and West Virginia exceeded the others.

Initial assessments of the shale gas resource by the Energy Information Administration (EIA) indicated that there was an abundance of shale gas available.

Developers were encouraged by the early estimates of the potential amount of gas and were able to attract investors and started drilling in the major shale formations (“plays”). Drillers soon discovered that the shale gas wells declined significantly within the first few years of production. Their experience with conventional gas was that wells would decline slowly over several decades. Now the developers 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 new drilling activity greatly increased supply, the economy crashed after the housing crisis and demand sank. With greater supply and lower demand, prices began to fall.

Wall Street Steps In
When the housing bubble burst, Wall Street investment banks went looking for new money-making opportunities. The investment bankers saw the dire situation the shale gas developers were in. They repackaged the drilling leases in much the same way they had repackaged mortgages and resold them for a profit. In this case the seal of approval was the short history of the best wells which were assumed to represent the potential of the entire parcel (pronouncing the field “proved up” and therefore a “safe” investment).

This quickly drove prices up for those looking to cash in on what the press was calling the “next energy bonanza”. Leases were bid up to outrageous prices with signing bonuses reaching nearly $30,000/acre and leases on unproven fields being flipped for as much as $25,000/acre, many times more than the original investment. There seemed to be an insatiable appetite for these deals. Aubrey McClendon, CEO of Chesapeake Energy, stated in a financial analyst call in 2008: “I can assure you that buying leases for x and selling them for 5x or 10x is a lot more profitable than trying to produce gas at $5 or $6 mcf.” (1)

Why would apparently sophisticated investors be misled into purchasing under-performing assets? The lack of well performance information masked the problems in shale production. States did not release well performance data on a timely basis, which made it very difficult to get a true picture of actual well history. Speculators given just a hint of what might be possible from the data describing the profitable wells rushed into the buying frenzy. Leases were bundled and flipped on unproved shale fields in much the same way as mortgage-backed securities had been bundled and sold on questionable underlying mortgage assets.

In January 2012, Bloomberg noted the surge of interest in these plays: “Chinese, French and Japanese energy explorers committed more than $8 billion in the past two weeks to shale-rock formations from Pennsylvania to Texas after 2011 set records for international average crude prices and U.S. gas demand. As competition among buyers intensifies, overseas investors are paying top dollar for fields where too few wells have been drilled to assess potential production…” (2)

Eventually, this second group of developers repeated the experience of the first. Rapid decline in production and too few wells were actually profitable. They also 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 drillers looked for areas which produced natural gas liquids as well as gas, in an attempt to create more cash flow to deal with their shortfalls. Many others pursued the same strategy; eventually supply spiked and prices plummeted in this arena too.

Pressure on the balance sheets of these operators had presented a new opportunity for the bankers. The number of mergers and acquisitions (M&A) within the shale market began to explode. Initially, many transactions involved foreign investors such as Chinese, Korean, French and Norwegian companies looking to purchase U.S. shale assets. The banks earned large fees for the transactions.(3)

A large Australian multinational, BHP Billiton, acquired Petrohawk Energy Corp, for approximately $15.2 billion, a considerable premium of approximately 65% over their stock price. (4) BHP also paid Chesapeake Energy about $4.75 billion for its Fayetteville shale gas assets only to write off over 50% of their value just 18 months later. (5) By mid 2012, shale asset write-downs were widespread.

During this time, banks who were generating large fees off shale company transactions were still rating these same companies as “buys” to the average investor. For example, Chesapeake Energy announced the sale of assets and a notes offering. Bank of America/Merrill Lynch, Morgan Stanley, Deutsche Bank, Goldman Sachs, Jeffries and Royal Bank of Scotland were the banks involved in the deals. (6) In the days and weeks leading up to the announcements, these same banks made favorable recommendations about Chesapeake Energy. Other analysts at banks which would not receive fees from these transactions had an opposite view of Chesapeake Energy’s prospects at the time.

In 2011, shale gas accounted for $46.5 billion in deals in the U.S. alone, as reported by KPMG. (7) The mergers and acquisitions market for shale assets had exploded in the prior two years directly in sync with the downward descent of natural gas prices. According to PriceWaterhouseCoopers, companies with acreage in the Marcellus had enjoyed approximately $32 billion in merger and acquisition deals since the beginning of 2010.(8) In much the same way as mortgage backed securities bolstered the banks’ profits before the downturn, energy M&A had become the new profit center within the investment banks.

In the New York Times, October, 2012, Ralph Eads of Jefferies, one of Chesapeake Energy’s primary investment banks, was quoted admitting to talking up prices and perhaps even misleading the Major Oil companies who bought shale assets: “Typically we represent sellers, so I want to persuade buyers that gas prices are going to be as high as possible…the buyers are big boys—they are giant companies with thousands of economists who know way more than I know. Caveat emptor.” (9)

If the big boy Major Oil companies knew more, why would they be interested in paying inflated prices for these shale gas plays? In 2012, 40 members of Congress urged President Obama to move forward with development of shale gas and LNG export terminals citing the benefits of free trade and the prospect of creating more jobs as demand for exports would lead to growth in gas production. (10)

In February, 2012, Lee Raymond, former CEO of ExxonMobil stated: “Even if you get past the politics, you have to test whether or not the resource base is sufficient [for exportation]…It’s going to be a little while before people are really confident that there is going to be a sufficient amount of gas for 30 years…I’m frankly not sure that we have enough experience with shale gas to make the kind of judgment you’d have to make.” (11)

It turns out that the Major Oil companies did know about the overstated promise of the shale gas plays. Yet several of them moved forward with acquisitions in the main shale gas formations. Why?

In 2010, the Securities and Exchange Commission (SEC), after heavy lobbying, changed its rules to allow for a significant increase in proven undeveloped reserves to be included on a company’s books. Without this change in how shale gas reserves were booked in 2010, most shale operators would have been forced to take large write-downs rather than booking increases in reserves. Many believe this rule change by the SEC grossly distorts the value of a company’s reserves since it allowed for a large increase in the booking of proven undeveloped reserves.

Economical reserves of hydrocarbons have proven harder and harder to replace. For more than a decade the largest oil and gas producers have not been able to materially expand their reserve replacement ratios. (12) In 2010, Chevron replaced less than one fourth of the oil and gas it had sold the prior year. (13) This is highly challenging for the future share price of these companies and explains their active share repurchase programs, buying back shares in excess of $5 billion a quarter in the case of ExxonMobil. (14) In a savvy move, several majors have purchased shale gas assets in order to show higher reserves on their books and thus bolster their share price as now allowed by the revised SEC requirement. Perhaps they also have the experience to foresee that with a relatively steady state long-term supply of domestic natural gas, the rush to add many more gas-fired power plants and the political and profit imperative to export LNG will put heavy pressure on the price. With a much higher price, costly to remove shale gas will become more economical to extract.

In the days of optimism about the abundance of affordable natural gas, Dominion established several goals:
• Build pipelines, gas storage facilities, and natural gas liquids plants in the Marcellus formation.
• Develop new gas-fired power plants to replace highly polluting coal plants and aging nuclear plants.
• Build a pipeline from the Marcellus to Virginia and North Carolina to bring gas to the new power plants.
• Develop an LNG export facility in Cove Point, MD to make money from the export of gas overseas.

Reality Sets In
The short history of the U.S. shale gas plays has been a roller coaster ride: beginning with exuberance, followed by wells that decline in a few years instead of decades, Wall Street bankers churning several rounds of consolidation to reap big payoffs, and the remaining developers are left to drill more wells to create cash flow to service debt even if it’s not profitable. Such activity created a surplus of gas which lowered prices. What is the truth about shale gas production?

First of all, the EIA is excellent at collecting data, but notoriously bad at making accurate forecasts with it. 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 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 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.”

Shale gas wells behave quite differently from conventional gas wells. A December 2012 report by the Oil and Gas Journal confirmed that the recovery efficiencies of shale plays are substantially lower than originally projected. The article states: “The recovery efficiency for the five major [shale gas] plays averages 6.5% and ranges from 4.7% to 10% …this contrasts significantly with recovery efficiencies of 75-80% for conventional gas fields. Yields in shale gas wells usually decline rapidly within the first few years compared to conventional wells which gradually decline over several decades. (15)

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. (16) 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.

What is Going on Now?
Developers are continuing to drill in the Marcellus. They have done it by being very selective in where they drill and by being very productive. Current jargon calls it “the factory approach” or “manufacturing-style development”. (17) Productivity has improved by drilling multiple wells from a single pad site. At first, three lateral wells, then six, now 10 lateral lines are drilled for each drilling rig. Such productivity gains have kept drilling rigs going despite low gas prices. Thanks to production in the Marcellus, domestic natural gas output has averaged 72.4 billion cubic feet per day (Bcf/d) an almost 8% increase from a year ago. Henry Hub spot prices in June have averaged $2.65 mcf, 40% lower than a year ago, when the June 2014 price average month-to-date was $4.59 mcf. 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.) (18)

Prices have fallen so low that there is little room for a significant price differential between Henry Hub and Dominion South prices. Excess supply created by drillers needing cash flow to pay off debts (even when producing at a loss), has caused production to outstrip demand. Although supply expanded by 5.2 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.

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.

Energy industry executives, politicians and policymakers have made policy and business decisions based on the forecasts from the DOE’s Energy Information Administration (EIA). At the beginning of shale development there was a general assumption that we will have decades of affordable, plentiful natural gas. Current experience doesn’t match the forecasts. What has gone wrong?

The Marcellus is currently the largest natural gas production area in the U.S. and is being counted on to supply abundant cheap gas for decades to come. It has been difficult to obtain current accurate information about the field’s production. Data for 2014 are now available. 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: (19)

• 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 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 production of affordable natural gas is only a temporary phenomenon; expected to disappear even before the Atlantic Coast Pipeline is projected to be in service.

Unbiased data such as this should cause the re-evaluation of projects which depend on the assumption of abundant affordable gas being true. To continue them risks the financial health of Dominion and of Virginia.

 

References
(1) Earnings Call Transcript, Q3 2008
http://seekingalpha.com/article/100644-chesapeake-energy-corporationq3-2008-business-update-call-transcript

(2) Joe Carroll and Jim Polson, “U.S. Shale Bubble Inflates After Near-Record Prices for Untested Fields”, Bloomberg, January 2003
http://www.bloomberg.com/news/2012-01-09/shale-bubble-inflates-on-nearrecord-prices-for-untested-fields.html

(3) Shale and Wall Street,http://shalebubble.org/wp-content/uploads/2013/02/SWS-report-FINAL.pdf

(4) BHP Billiton, “BHP Billiton and PetroHawk announce Merger Agreement”, July 2011,
http://www.bhpbilliton.com/home/investors/news/Pages/Articles/BHP-Billiton-and-Petrohawk-Energy-Corporation-Announce-Merger-Agreement.aspx.

(5) OGJ Editors, “BHP Billiton writes down Fayetteville shale values”, Oil and Gas Journal, August 2012,
http://www.ogj.com/articles/2012/08/bhp-billiton-writes-down-us-shale-values.html

(6) Juan Lopez, “Bank of America Maintains Buy on Chesapeake Energy”, Benzinga, February 2012,
http://www.benzinga.com/analyst-ratings/reiteration/12/02/2339282/bank-of-america-maintains-buy-onchesapeake-energy

(7) KPMG, “Shale Gas M&A Activity in US, Argentina and China on the Rise: KPMG Report”, June 2012,
http://www.kpmg.com/global/en/issuesandinsights/articlespublications/press-releases/pages/shale-gas-maactivity-in-us-argentina-and-china.aspx

(8) AP, “Marcellus Shale Merger Activity Slows”, October 25, 2012,
http://baltimore.cbslocal.com/2012/10/25/marcellus-shale-merger-activity-slows/

(9) Clifford Krauss and Eric Lipton, “After the Boom in Natural Gas”, New York Times, October 21, 2012,
http://www.nytimes.com/2012/10/21/business/energy-environment/in-a-natural-gas-glut-big-winners-andlosers.html?pagewanted=all&_r=0

(10) Michael Levi, “The Case for Natural Gas Exports”, New York Times, August 16, 2012,
http://www.nytimes.com/2012/08/16/opinion/the-case-for-natural-gas-exports.html

(11) Kari Lundgren, “U.S. Shale Gas Exports Face Hurdles, Former Exxon CEO Says”, Bloomberg, February 10, 2012,
http://www.bloomberg.com/news/2012-02-10/u-s-shale-gas-exports-face-hurdles-former-exxon-ceosays.Html

(12) Seeking Alpha, “Oil and Gas Exploration Costs Rise Again for the Majors”, March 2011,
http://seekingalpha.com/article/259687-oil-and-gas-exploration-costs-rise-again-for-the-majors

(13) Joe Carroll, “Chevron’s Reserve-Replacement Ratio Falls to Eight-Year Low”, Bloomberg, January 2011,
http://www.bloomberg.com/news/2011-01-28/chevron-s-reserve-replacement-ratio-falls-to-eight-yearlow.html.

(14) Angel Gonzalez, “Exxon Mobil: Share Repurchases to Reach $5Billion in 1st Quarter”, Wall Street Journal, February 2013,
http://online.wsj.com/article/BT-CO-20130201-707645.html.

(15) Rafael Sandrea, “EVALUATING PRODUCTION POTENTIAL OF MATURE US OIL, GAS SHALE PLAYS”, IPC Petroleum Consultants, 12/03/2012
http://www.ogj.com/articles/print/vol-110/issue-12/explorationdevelopment/evaluating-production-potential-of-mature-us-oil.html

(16) http://www.nature.com/news/natural-gas-the-fracking-fallacy-1.16430

(17) Focus on well efficiency keeps Marcellus Shale pumping despite low prices
http://www.eenews.net/stories/1059994007 Energy & Environment Publishing February 5, 2014

(18) http://peakoil.com/consumption/oh-us-gas-demand-where-art-thou June 11, 2015

(19) Marcellus Production Outlook, David Hughes April 28, 2015
http://www.postcarbon.org/marcellus-production-outlook/
http://www.postcarbon.org/publications/drillingdeeper/

Atlantic Coast Pipeline: More Jobs or Less? – Summary

• One of the most popular claims for any new development is that it will create jobs.

• Dominion foresees that many of the workers needed to construct the pipeline will come from Virginia and North Carolina and their incomes and economic activity during the project will benefit the locations through which the project passes.

• A pipeline project proceeds in phases, with different crews doing different types of jobs. Although the total construction time for the project is approximately two years, each type of crew would be employed for a shorter period.

• Skilled employees needed for the specialized work of building a pipeline will be drawn from a regional and national labor pool as opposed to primarily from general laborers available in Virginia and North Carolina.

• Other than daily expenses for food, gas and motels, most of the workers’ paychecks will be sent home to another state.

• The intermittent influx of crews staying for a few days to accomplish various phases of the pipeline work will not likely prompt any new hiring in the locations in which they stay.

• The number of direct short-term construction jobs that will go to Virginians and any indirect economic benefits deriving from them will likely be far less than what has been claimed.

o In fact, there could be a net loss of jobs.

• The CEO of Dow Chemical and an industry group representing U.S. manufacturers with a combined $1 trillion of annual revenue have argued that the energy policy which gives rise to the pipeline will cost Virginia thousands of its 231,000 long-term manufacturing jobs.

• They have opposed the rush to burn more gas in power plants and the export of LNG, saying that those policies will cause a substantial rise in natural gas prices.

• U.S. manufacturers are beginning to return jobs to this country because our affordable prices for natural gas and natural gas liquids give them an advantage over their overseas competitors.

• These large corporations argue that using up our affordable gas for exports or to fuel power plants will raise our domestic gas prices 2-3 times higher than if we maintained our traditional uses of gas.

• Australia has already experienced the path being mapped out by Dominion and other energy companies. They have had to close many manufacturing plants and lay off employees because of rising gas prices.

• 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 says the Department of Energy, “while the vast majority of the people in the country will lose economically”.

• Using renewable sources would provide many more jobs than those created by building more gas-fired plants because more workers are needed to build renewable facilities. The overall cost is about the same; higher labor costs are offset because wind and sunlight are free.

• A more thorough analysis should be conducted that would take into account more realistic assumptions.

• Increased prices for natural gas could cause a large scale loss of jobs in the manufacturing sector in Virginia and throughout the U.S.

• As a result of the announced projects, Dominion may cause a net decrease in jobs in the state of Virginia.

Atlantic Coast Pipeline: More Jobs or Less? – Full Article

A major benefit of the Atlantic Coast Pipeline claimed by Dominion is that it will provide jobs to Virginia and other states along the pipeline route.(1) However, Dominion has not spelled out the details of their job and income claims, as noted by Synapse, a Cambridge, Massachusetts, energy economics think tank hired by the Southern Environmental Law Center. (2)

If the pipeline is approved, a contract would be awarded to a contractor experienced in developing large pipeline projects. Firms such as this typically hire from a regional and national base of skilled employees experienced in handling the specialized tools and equipment needed to build the pipeline. Constructing a pipeline is not like building your local big box store, where local trades are capable of providing the necessary skills. The pipeline general contractor knows that only experienced help can be trusted with the most crucial functions.  Only a fraction of those qualified are likely to live in Virginia.  The pipe, special valves, the monitoring equipment and most of the other material needed to build the pipeline will be provided by suppliers outside the states in the construction area.

If a local laborer had the necessary skills, they wouldn’t be local for long.  A pipeline project is developed in phases and the crew for each phase moves along the pipeline route like a carnival troupe moving from town to town. Each group would stay in a town only for a day or two paying for hotels, gas, bar tabs, groceries and fast food – then move on; replaced in a few weeks or a few months by the crews for the next phases. This is hardly a bonanza for a local economy and local employers are unlikely to add staff to serve a group that stays in town for such a short time. Rather than the income staying in the community, most pipeline workers send their paychecks home to wherever they might have their permanent residence.

Consultants often use a multiplier to calculate the overall benefit of new jobs in a region. If a local business were to hire a new employee, they assume the salary would be spent mostly in the local area for food, housing, transportation and at local stores, banks, restaurants, etc. Each dollar of the new employee’s income might move through the local economy and generate an extra dollar or two of benefit to other businesses and their employees. But Dominion’s jobs aren’t like a new local job, although the high estimates for local economic activity stated by their consultants seem to assume they are. Without an explanation of their assumptions it is difficult to tell.

If pipeline construction provides just a series of small upticks of economic activity for Virginia towns along the pipeline route, what about long-term employment? Thirty-nine full time jobs will be added in Virginia for the compressor station slated for Buckingham County, according to Dominion. The inspection of the pipeline regarding impacts such as sedimentation and erosion seems to be left up to Dominion. Whether this requires any new employees is unclear. Dominion’s procedures appear to require waiting to respond to complaints after damage has occurred rather than preventing problems from occurring.

But it is long-term employment that has many of the nation’s largest employers concerned. The Atlantic Coast Pipeline is part of the natural gas industry’s plan to expand sales to gas-fired power plants and to export Liquefied Natural Gas (LNG). Dominion has three new large gas-fired power plants opening over a 5-year span. A 1329 MW unit went into service December 2014 in Warren County; a 1358 MW facility is under development in Brunswick County (Southside VA) scheduled for operation next summer; and a 1600 MW facility is planned just 4 ½ miles away in Greensville County, with operation to begin in 2019. All of these units will initially be connected to existing pipelines.

Dominion is opening its Cove Point, Maryland, LNG facility next year; one of five export terminals currently approved and under construction in America. (3) A total of 29 LNG export facilities are either under development; have pending applications; or are under consideration in the U.S. (4)

Although these projects might be profitable for energy companies, it’s bad business for the rest of us. As reported by US News, exporting our natural gas will reduce the amount of affordable gas left in the U.S. and drive the price up. (5) This will increase costs to consumers and their employers.

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. (6)

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.” (7)

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. 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”.

Much has been publicized about the significant, affordable natural gas resources we have in America. Yet the standard national price (at Henry Hub) is forecasted to rise 134.5% by 2025, compared to 2012, according to the U.S. Energy Information Administration (EIA). 8 Independent surveys of the likely production potential of the shale gas fields do not support the Department of Energy’s rosy projections for our future gas supply. Tad Patzek, head of the University of Texas at Austin’s department of petroleum and geosystems engineering, was a member of a multidisciplinary team that conducted an in-depth analysis of the nation’s shale gas producing areas. 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”. (9)

An article in Nature summarized the in-depth, refined analysis conducted by the University of Texas team. “If natural-gas prices were to follow the scenario that the EIA used in its 2014 annual report, the Texas team forecasts that production from the big four (natural gas) 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. “Obviously they do not agree very well with the EIA results,” says Patzek.” (10) If the affordable gas was burned to produce electricity or sent overseas, to meet our domestic needs we would have to extract much harder to get and therefore, much more expensive shale gas.

Burning more natural gas in power plants or exporting it overseas does not create many more jobs. Even with the dramatic increase during the last few years in shale oil and gas exploration, only 59,527 new jobs were created between 2010 and 2013. During this same period, 528,108 new manufacturing jobs were created, partly in response to lower natural gas prices.(11) A dramatic increase in natural gas and electricity prices could put these jobs at risk. Supplying new generating requirements from renewable sources would provide many more jobs than those created by building more gas-fired plants because more workers are needed to build renewable facilities.(12) The overall cost is about the same; higher labor costs are offset because wind and sunlight are free.

Conclusion
Dominion has heavily promoted the number of jobs and indirect effects that might be gained from them in order to prove that construction of the pipeline is a benefit to the residents of Virginia. The studies upon which the numbers are based are very general in nature and appear to make assumptions which do not fit the reality that is likely to occur when the pipeline is built. Given that these assumed benefits have been widely reported, a more thorough analysis should be conducted that would take into account more realistic assumptions.

Leaders of major manufacturers and manufacturing trade associations are concerned about the policies of burning more natural gas to produce electric power and exporting our affordable gas to other nations, as Dominion is proposing. These new uses will increase our domestic prices of natural gas. Increased prices for natural gas could cause a large scale loss of jobs in the manufacturing sector in Virginia and throughout the U.S. As a result of the announced projects, Dominion may cause a net decrease in jobs in the state of Virginia.

 

References
(1) The Economic Impact of the Atlantic Coast Pipeline in West Virginia, Virginia, and North Carolina, Chmura Inc.,

https://www.dom.com/library/domcom/pdfs/gas-transmission/atlantic-coast-pipeline/acp-chmura-report-091014.pdf

(2) Opponents’ report casts doubt on pipeline benefits, Patricia Borns, News Leader, July 8, 2015 http://abralliance.org/wp-content/uploads/Synapse_Report_ACP_June_2015.pdf

(3) http://www.ferc.gov/industries/gas/indus-act/lng/lng-approved.pdf

(4) http://www.ferc.gov/industries/gas/indus-act/lng/lng-export-proposed.pdf

(5) http://www.usnews.com/opinion/economic-intelligence/2014/06/20/exporting-natural-gas-ignores-global-warming-and-energy-challenges

(6) http://www.roanoke.com/opinion/commentary/cicio-gas-exports-threaten-virginia-manufacturing-jobs/article_2d4339a4-cbfb-11e3-80e5-001a4bcf6878.html

(7) http://oilprice.com/Energy/Natural-Gas/Dow-Opposes-US-Natural-Gas-Export-Plans.html

(8) http://www.eia.gov/forecasts/aeo/pdf/0383%282015%29.pdf EIA Annual Energy Outlook 2015

(9) http://www.nature.com/news/natural-gas-the-fracking-fallacy-1.16430

(10) Ibid.

(11) http://pipelineandgasjournal.com/why-manufacturers-oppose-unfettered-lng-exports?page=4

(12) http://www.usnews.com/opinion/economic-intelligence/2014/06/20/exporting-natural-gas-ignores-global-warming-and-energy-challenges

Pipeline Benefits Based on Flawed Assumptions – Summary

• According to Atlantic Coast Pipeline Benefits Review, the long term benefits of the pipeline accrue primarily from one item: cheaper shale gas from the Marcellus.

• ICF projects that this price differential translates into price savings for both natural gas and electric consumers; and that this savings could also trigger stimulus effects that create long-term jobs, although the report never explains how this would occur.

• Many have been led to believe that gas is cheaper from Marcellus because it is an abundant long-term source of affordable gas.

• The drillers quickly discovered that unconventional gas wells in shale formations such as Marcellus decline substantially within the first few years compared to conventional gas wells which declined over several decades.

• Developers borrowed a great deal of money during the easy money days of the early 2000’s and were strapped for cash due to lower than expected revenues.

• In order to have the cash to cover their loan payments, drillers kept drilling more wells even though they lost money on many of them.

• Wall Street investment banks repackaged mortgages and passed them on to investors with a seal of approval. In the same way, the financial wizards repackaged shale gas leases and sold them off at a tidy profit.

• The seal of approval was the short history of the best wells which were assumed to represent the potential of the entire parcel (pronouncing the field “proved up” and therefore a “safe” investment).

• This quickly drove prices up for those looking to cash in on what the press was calling the “next energy bonanza”.

• Eventually, this 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.

• Today, using “the factory approach”, productivity has improved by drilling multiple wells from a single pad site.

• Prices have fallen so low that there is little room for a substantial price differential between Marcellus and the standard national price.

• An in-depth study of 2014 drilling records in the Marcellus revealed:

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

o 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.

o 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.

o This declining well productivity is significant, as top counties become saturated with wells, and will degrade the economics which have allowed operators to sell Marcellus gas at a significant discount to national gas prices.

o Current drilling rates are sufficient to keep Marcellus production growing until its projected peak in 2018.

o 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).

o 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 is only a temporary phenomenon; expected to disappear even before the Atlantic Coast Pipeline is projected to be in service.

• A University of Texas team spent more than three years on a systematic study of the major shale plays, assuming 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 EIA breaks up each shale play by county, calculating an average well productivity for that entire area.

• 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 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, of the University of Texas 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.”

 

The full article follows in the next post. It provides more in-depth explanations and references for your own investigation.

 

Pipeline Benefits Based on Flawed Assumptions – Full Article

In a report commissioned by Dominion, ICF International of Fairfax, VA and Houston TX, has claimed substantial economic benefits to derive from the Atlantic Coast Pipeline. (1) Since these presumed benefits are a substantial part of the rationale Dominion is using to gain the right to “take” from unwilling sellers, they should be carefully examined. An independent assessment of the ICF conclusions states that it is difficult to analyze them because the assumptions used to develop the stated benefits are not clearly identified. (2)

In a previous article, it was shown that the employment benefits of pipeline construction promoted by Dominion in press releases and brochures will likely be quite different from what will be experienced if the pipeline is actually constructed. Rather than thousands of new short-term jobs for Virginians and an economic windfall for towns along the construction route, there will possibly be a net loss of jobs in Virginia as a result of the projects that Dominion is undertaking.

If potential long-term job losses are larger than the short-term construction jobs projected by Dominion, what benefits do they foresee? 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. (3)

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. (4)

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”. (5) Wall Street investment banks continued to promote shale gas plays, despite the experience of developers. (6)

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. (7)

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. (8)

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. (9)

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: (10)

• 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 is 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. (11)

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.” (12) Or for Virginia’s economy.

 

References:
(1) https://www.dom.com/library/domcom/pdfs/gas-transmission/atlantic-coast-pipeline/acp-icf-study.pdf

(2) For a copy of the Synapse report questioning the Atlantic Coast Pipeline Benefits Review, see

http://abralliance.org/wp-content/uploads/Synapse_Report_ACP_June_2015.pdf

(3) Joe Carroll and Jim Polson, “U.S. Shale Bubble Inflates After Near-Record Prices for Untested Fields”, Bloomberg, January 2012,

http://www.bloomberg.com/news/2012-01-09/shale-bubble-inflates-on-nearrecord-prices-for-untested-fields.html

(4) OGJ Editors, “BHP Billiton writes down Fayetteville shale values”, Oil and Gas Journal, August 2012,
http://www.ogj.com/articles/2012/08/bhp-billiton-writes-down-us-shale-values.html

(5) KPMG, “Shale Gas M&A Activity in US, Argentina and China on the Rise: KPMG Report”, June 2012,

http://www.kpmg.com/global/en/issuesandinsights/articlespublications/press-releases/pages/shale-gas-maactivity-in-us-argentina-and-china.aspx

(6) Juan Lopez, “Bank of America Maintains Buy on Chesapeake Energy”, Benzinga, February 2012,
http://www.benzinga.com/analyst-ratings/reiteration/12/02/2339282/bank-of-america-maintains-buy-onchesapeake-energy

(7) Focus on well efficiency keeps Marcellus Shale pumping despite low prices http://www.eenews.net/stories/1059994007 Energy & Environment Publishing February 5, 2014

(8) http://peakoil.com/consumption/oh-us-gas-demand-where-art-thou June 11, 2015

(9)Ibid.

(10) Marcellus Production Outlook, David Hughes April 28, 2015

http://www.postcarbon.org/marcellus-production-outlook/

http://www.postcarbon.org/publications/drillingdeeper/

(11) http://www.nature.com/news/natural-gas-the-fracking-fallacy-1.16430

(12) Ibid.

Government Study Says Virginia Pipeline is Unnecessary – Summary

• Is there another way to serve Virginia’s needs without the expense, environmental degradation, seizure of private property, and economic dislocations related to development of the Atlantic Coast Pipeline?

• With the 1329 MW Warrenton VA gas-fired plant opened in December of 2014, the 1358 MW facility under construction in Brunswick Co. due to begin service in 2016 and the 1600 MW plant proposed for Greensville Co. in 2019, Dominion is definitely planning to increase the amount of natural gas used to generate electricity in Virginia. All of these plants will connect to existing pipelines.

• Dominion’s own information shows that the traditional residential, commercial and industrial use of natural gas in Virginia is expected to be essentially flat over the next 15-20 years. The only significant increase in demand is expected from the use of natural gas in electric generating plants.

• AGL, a five percent partner in the Atlantic Coast Pipeline, wants to use the new pipeline to supply the customers of its subsidiary, Virginia Natural Gas, in the Norfolk area. Virginia Natural Gas is already connected to a major Columbia Gas pipeline which enters the state from West Virginia. A recent University of Virginia Demographics Research Group study predicts only a 0.2% per year increase in the population of this area over the next several years, assuming no major military base closings. What would justify the expense of adding another pipeline to an essentially stable natural gas consuming region?

• Some suspect that it is in preparation to serve a potential LNG facility in the Hampton Roads/Newport News area. But Dominion emphatically claims that no gas traveling in the Atlantic Coast Pipeline will end up at an LNG facility. In any case, does it make sense for AGL to make a major investment in a connection to Marcellus gas which could well be more expensive than the nationally priced gas it already has available through its connection with Columbia Gas?

• As confirmed by Dominion’s own plans to connect its two new gas-fired power plants to the Transco pipeline, sufficient capacity exists in our nation’s current pipeline system to handle the projected increase in natural gas production. A study by the Department of Energy, “Natural Gas Infrastructure”, states that sources of natural gas supply and demand are not concentrated in any particular part of the U.S. which reduces the need for new pipelines. They conclude that a superior choice is to utilize unused capacity in existing pipelines to meet increased needs in most locations; especially since building new pipelines is so expensive and creates many environmental, social and economic impacts.

• 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.”

• The existing Transco pipeline also has a leg which extends into North Carolina very near where the Atlantic Coast Pipeline is proposed to enter. So the North Carolina needs can be supplied by existing pipelines as well.

• An extension to the Transco pipeline is proposed in Pennsylvania to access the Marcellus production. Overall, a 1.7 Bcf/d expansion of the Transco pipeline (larger than the 1.5 Bcf/d proposed for the ACP) is expected to be in service in 2018 according to the DOE model. Clearly, a pipeline that already exists with sufficient capacity to serve the needs projected for the Atlantic Coast Pipeline would be far superior to an alternative which requires a $5 billion investment; substantial adverse impacts on fragile geological areas and water supplies, sensitive habits, unique cultural, recreational and historic areas; and requires the forced taking of property from landowners who choose not to offer Dominion an easement for the construction of a pipeline which would damage their property and alter its character.

• Since this is known to the Department of Energy, the supervising agency for FERC; further consideration of the Atlantic Coast Pipeline should be halted immediately before more time and money is wasted on an unnecessary proposal.

 

The full article follows in the next post. It provides more in-depth explanations and references for your own investigation.

Government Study Says Virginia Pipeline is Unnecessary – Full Article

Dominion is willing to invest $5 billion for the Atlantic Coast Pipeline (ACP) and $3.8 billion for the Cove Point LNG facility to see its energy vision fulfilled. Is there another way to serve Virginia’s needs without the expense, environmental degradation, seizure of private property, and economic dislocations associated with these projects? Even some of Dominion’s stockholders are concerned about taking such a large risk that is not supported by the evidence. (1) Several options exist as alternatives to the Atlantic Coast Pipeline.

Dominion is definitely planning to increase the amount of natural gas used to generate electricity in Virginia. The 1329 MW Warrenton VA gas-fired plant opened in December of 2014, a 1358 MW facility is under construction in Brunswick Co. due to begin service in 2016, and a 1600 MW plant is proposed for Greensville Co. in 2019, All of these plants will connect to existing pipelines. The Atlantic Coast Pipeline is proposed to pass through the Greensville Site on its way into North Carolina. Presumably, Dominion would connect both new Southside power plants to the ACP if it was available.

Dominion’s own information shows that the traditional residential, commercial and industrial use of natural gas in Virginia is expected to be essentially flat over the next 15-20 years. The only significant increase in demand is expected from the use of natural gas in electric generating plants.

AGL, a five percent partner in the Atlantic Coast Pipeline, wants to use the new pipeline to supply the customers of its subsidiary, Virginia Natural Gas, in the Norfolk area. The construction of an extension of the pipeline from North Carolina all the way to the Norfolk area is a bit puzzling. Virginia Natural Gas is already connected to a major Columbia Gas pipeline which enters the state from West Virginia. A recent University of Virginia Demographics Research Group study predicts only a 0.2% per year increase in the population of this area over the next several years, assuming no major military base closings. (2) What would justify the expense of adding another pipeline to an essentially stable natural gas consuming region?

Some suspect that it is in preparation to serve a potential LNG facility in the Hampton Roads/Newport News area. But Dominion emphatically claims that no gas traveling in the Atlantic Coast Pipeline will end up at an LNG facility.

Without a new large demand in the area, does it make sense for AGL to make a major investment in a connection to Marcellus gas which could well be more expensive than the nationally priced gas it already has available through its connection with Columbia Gas?

As confirmed by Dominion’s own plans to connect its two new gas-fired power plants to the Transco pipeline, sufficient capacity exists in our nation’s current pipeline system to handle the projected increase in natural gas production. A study by the Department of Energy, “Natural Gas Infrastructure”, revealed the following major findings: (3)

Key Finding 1: Diverse sources of natural gas supply and demand will reduce the need for additional interstate natural gas pipeline infrastructure.

Key Finding 2: Higher utilization of existing interstate natural gas pipeline infrastructure will reduce the need for new pipelines.

The study notes that given the high costs of building new pipelines, finding alternative routes that utilize available existing pipeline capacity is often less costly than expanding pipeline capacity. A new pipeline requires a long-term stream of sufficient revenues over its operating lifetime to justify the significant upfront capital investment ($5 billion for the ACP).

The need for new facilities is often difficult for the Federal Energy Regulatory Commission (FERC) to determine before granting the approvals for natural gas developments. For example, 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. (4) 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.

New natural gas pipeline development is driven by market supply and demand, often identified by the difference in natural gas prices between two locations or “hubs”. These “basis differentials”, and how the captured revenues compare to the cost of constructing pipelines, largely determine how much and in which locations pipeline capacity is likely to be added. As has been established, the tantalizing lower costs offered by sources in the Marcellus will not last. Affordable supplies of gas from the Marcellus will decline between 2018 and 2020, just when the Atlantic Coast Pipeline is scheduled to begin its 80-100 years of service. As the DOE study identifies, “As the lowest cost Marcellus resources are depleted over the course of the Reference Case projection, only higher-cost Marcellus supplies remain available for incremental production in the increased demand cases. Incremental Marcellus production is also likely to require additional infrastructure to bring production to market, diminishing the attractiveness of Marcellus production relative to other basins.” (5)

The DOE report goes on to say, “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.” (6)

The report explains, “Another reason that pipeline capacity additions in the Reference Case are not greater is that, in many regions, existing pipeline capacity is not fully utilized during many parts of the year. Average capacity utilization between 1998 and 2013 was 54%.” “For comparison, projected pipeline utilization for the top 200 pipeline segments by projected flow volume in the Reference Case in 2030 is 57%.” (7)

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”. (8) One of the pipelines referred to is the Transco pipeline to which Dominion will connect their two new gas-fired power plants; hoping later to connect them to the Atlantic Coast Pipeline. The Transco pipeline also has a leg which extends into North Carolina very near where the Atlantic Coast Pipeline is proposed to enter. So the North Carolina needs can be supplied by existing pipelines as well.

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.” (9)

An extension to the Transco pipeline is proposed in Pennsylvania to access the Marcellus production. Overall, a 1.7 Bcf/d expansion of the Transco pipeline (larger than the 1.5 Bcf/d proposed for the ACP) is expected to be in service in 2018 according to the DOE model. Clearly, a pipeline that already exists with sufficient capacity to serve the needs projected for the Atlantic Coast Pipeline would be far superior to an alternative which requires a $5 billion investment; substantial adverse impacts on fragile geological areas and water supplies, sensitive habits, unique cultural, recreational and historic areas; and requires the forced taking of property from landowners who choose not to offer Dominion an easement for the construction of a pipeline which would damage their property and alter its character.

Since this is known to the Department of Energy, the supervising agency for FERC; further consideration of the Atlantic Coast Pipeline should be halted immediately before more time and money is wasted on an unnecessary proposal.

 

References:

(1) Economics of the Atlantic Coast Pipeline Considered,A White Paper for Dominion Shareholders by Doug Hornig

http://friendsofnelson.com/wp-content/uploads/2015/04/Shareholder-letter-with-summary-revision-4.1.pdf

(2) http://www.coopercenter.org/demographics/virginia-population-estimates

(3) The U.S. Department of Energy, “Natural Gas Infrastructure”

http://energy.gov/sites/prod/files/2015/02/f19/DOE%20Report%20Natural%20Gas%20Infrastructure%20V_02-02.pdf

(4) Ibid.

(5) Ibid.

(6) Ibid.

(7) Ibid.

(8) Ibid.

(9) Ibid.

« Older posts

© 2016

Theme by Anders NorenUp ↑