Eastern Virginia and eastern North Carolina need more natural gas, and the Atlantic Coast Pipeline is the most cost-effective way to to deliver it, say the four pipeline partners.
by James A. Bacon
Two years ago, four electric and gas utilities announced the formation of a joint venture, the Atlantic Coast Pipeline. The 600-mile project, the partners said, would connect Virginia and North Carolina with the Marcellus and Utica shale basins, tapping abundant natural gas supplies to benefit residential customers, spur economic development, and enable power companies to shift generation from dirty coal to cleaner-burning gas. If all went according to schedule, the pipeline would receive a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission (FERC) in the summer of 2016.
The project is rolling forward but it has encountered delays: A FERC ruling is not expected until next year. Intense opposition has arisen in Virginia mountain communities through which the pipeline would cross. Foes have raised concerns about the threat of gas explosions, harm to rare species, disruption to viewsheds, and pollution of rivers, streams and water supplies.
There is no legitimate public need to build the pipeline, opponents argue. Virginia and North Carolina can get plenty of natural gas through existing gas infrastructure. In their view, the ACP represents a bold play by four monopoly utilities — Dominion Virginia Power, Duke Energy, Piedmont Natural Gas and Southern Company Gas, owner of Virginia Natural Gas — to leverage their buying power to create a captive pipeline that will generate higher investment returns than they could get from their own regulated businesses.
FERC cannot approve any pipeline project “unless it is absolutely necessary,” said Joe Lovett, executive director of Appalachian Mountain Advocates in a press release issued last week in conjunction with a study disputing the need for the pipeline. “In cases like this, where the government allows for-profit companies to take private property — family farms, people’s homes — that protection is especially crucial. … The pipelines are not needed, so there should be no eminent domain for private gain.”
Pipeline foes have been hammering home this message to regulators and the public. ACP officials counter that the argument is based upon a profound misunderstanding of pipeline economics and how the project originated. The four partner companies issued Requests for Proposal in 2014 and compared the proposals — real submissions, not theoretical alternatives thrown out by pipeline foes. Plain and simple, company spokesmen say, the ACP best met the utilities’ needs. The four partners backed the venture because it made the most economic sense.
The story of how the Atlantic Coast Pipeline came to be has never been told to the public. Given the way the debate was focusing increasingly on the pipeline’s public necessity, I thought the public could benefit from a clearer understanding of the thinking behind the enterprise. At my request, Aaron Ruby, a spokesman for Dominion Transmission, managing partner of the ACP, set up a phone-conference interview with executives from the four partner companies. During a 45-minute interview, they made several key points:
- Duke and Piedmont foresaw an increasing demand for natural gas. Totally dependent upon the Transco pipeline, they wanted to diversify their sources of gas supply and transport. In 2014 they issued an Request for Proposal.
- Thinking along parallel lines, Dominion Virginia Power issued its own RFP around the same time.
- Instead of building separate pipelines, Duke, Piedmont and Dominion agreed that joining forces in a single pipeline would be far more economical than any other alternative. By signing up Virginia Natural Gas and Public Service of North Carolina as customers as well, the proposed pipeline would enjoy economies of scale that no one else could match.
The natural gas revolution
The Obama administration has presided over a regulatory makeover of the electric power industry. In March 2011 the Environmental Protection Agency (EPA) proposed regulations designed to reduce electric utility emissions of mercury and other toxic chemicals. The so-called Mercury and Air Toxic Standards (MATS) compelled many power companies to shut down their oldest and dirtiest coal- and oil-fired plants and replace them with generators powered by cleaner-burning gas. By 2014, electric utilities were in the midst of implementing MATS when the EPA rolled out its Clean Power Plan (CPP), which aimed to achieve a major reduction in carbon-dioxide emissions blamed for global warming. The CPP gave state regulators leeway in how to achieve the cuts by means of such strategies as energy conservation and efficiency and switching to natural gas and renewable fuels.
Meanwhile, thanks to the fracking revolution, natural gas production was booming in the Ohio-West Virginia-Pennsylvania area where the Marcellus and Utica shale fields were concentrated. The price of gas had plummeted, and it looked like supplies would stay abundant and relatively cheap for a long time. East Coast markets were served by a relatively small number of gas pipelines, most notably the massive Transco pipeline system that delivered gas from the Gulf Coast to markets as far north as New York. Connecting the Marcellus fields to East Coast populations centers was shaping up as a once-in-a-lifetime business opportunity for the gas industry, and by 2014 FERC was fielding an unprecedented number of pipeline proposals.
As utility planners in Virginia and North Carolina looked into the future, they had to figure out how to do two things: replace the old coal-fired power plants and accommodate economic growth in one of the faster-growing regions of the country. While they saw a role for solar and wind power, electric utilities also were responsible for maintaining the reliability of the electric grid. Because renewable energy sources are intermittent, not always generating electricity to match demand, planners leaned toward natural gas, whose production they could dial up and down as needed.
In the winter of 2013-2014, a North American cold wave known as the polar vortex drove home the urgent need for more gas. A change in the jet stream sent temperatures plunging and natural gas consumption soaring in the East Coast. “We saw winter peaks that were eye-popping to us,” said Greg Workman, Dominion’s director of fuels. “The winter peak eclipsed our previous winter and summer peaks.”
In Hampton Roads the gas supply was put under so much strain that Virginia Natural Gas (VNG) had to curtail supplies to many industrial customers. While those customers had backup sources of power and paid lower prices for their gas in exchange for their interruptible status, the incident drove home how vulnerable the region was to extreme weather events.
The Durham-Piedmont RFP
From Duke Energy’s perspective in mid-2014 as it phased out its coal-fired plants, the future of energy was in natural gas. The utility had four gas-fired facilities at that time, and it was planning construction of two more. “We’ve seen considerable growth in the Carolinas — [utility] gas consumption has grown 26 times over the past 15 years to more than 200 bcf (billion cubic feet),” said Joe McCallister, Duke’s director-natural gas. The forecast is for utility consumption to reach 360 bcf in a decade.
Over and above anticipating the need for more gas, said McCallister, Duke wanted a more reliable, diversified supply. Gas flowed south-to-north on the Transco pipeline system, delivering Gulf Coast gas as far north as New York City. Duke wanted to tap the Marcellus region, which would open up new suppliers, create more competition, and enable the company to take advantage of seasonal fluctuations in gas prices. The utility also wanted to protect North Carolina consumers from supply interruptions in the Gulf, which was vulnerable to disruption by hurricanes or industrial accidents.
Joint planning was a necessity. While Transco delivered gas to North Carolina through its 11 bcf-per-day transmission system, Duke relied upon Piedmont’s distribution system to get the gas from the Transco trunk line to Duke power plants. Conversely, Duke was Piedmont’s largest customer.
Piedmont also was forecasting continued growth in commercial and residential demand for gas in its Carolina markets, said Frank Yoho, chief commercial officer for Piedmont. The company had wanted since the 1980s to bring “strategic pipeline infrastructure” to the eastern part of the state. Piedmont could not generate sufficient demand from residential and commercial customers alone to justify building a major pipeline on its own. But Duke’s shift from coal to gas changed the equation. Said Yoho: “Duke’s power generation got us over the hump.”
In April 2014 Duke and Piedmont broadcast a Request for Proposal (RFP). The RFP specified the delivery of gas to multiple points in Piedmont’s distribution system and specified the delivery of gas within narrow pressure parameters in order to meet the needs of the new generation of highly efficient combined-cycle gas plants.
Duke and Piedmont received multiple proposals. However, they say they cannot discuss the losing bids, the details of which are protected by confidentiality agreements.
One possible bidder is Transco. Supplying 100% of the gas in North Carolina, the Transco “pipeline” is really a massive system of three to four pipelines (depending upon location) running parallel to one another in the same corridor. As competitors build pipelines in Pennsylvania and Marcellus gas began displacing Gulf gas in northern markets, Transco began developing the capability to move gas north to south. Also, recognizing the desire of customers to diversify their gas suppliers, Transco planned the Atlantic Sunrise pipeline, now under construction, to connect with Marcellus gas in northeastern Pennsylvania. That project, which will draw up to 1.7 billion bcf daily from eastern Pennsylvania, is scheduled for completion in 2017.
Despite its massive capacity, Transco’s capacity is fully contracted for, said company spokesman Chris Stockton. Moreover, serving a new customer in Virginia or North Carolina likely would entail adding new pipe and compressor stations, as it did when the company built a $300 million lateral line to reach Dominion’s new gas-fired power plant in Brunswick County.
Could Transco meet the needs of more power plants? It depends on the volume, said Stockton. “If a customer came to us, we would develop a project to meet that need. … Any expansion would require capital investment on Transco’s end.” How much would it have cost to meet Duke’s needs in North Carolina? Stockton was not willing to speculate.
The others come on board
As Duke and Piedmont were analyzing their alternatives, Dominion Virginia Power was just a few months behind in issuing an RFP. Dominion’s appraisal of the future of natural gas as a power source and the longevity of the Marcellus shale play was similar to Duke’s.
“A lot of market influences in the 2013 time period made us think about new gas supply strategies,” said Workman, Dominion’s director of fuels. The company anticipated a need to operate its existing gas plants at higher utilization rates and the need to build new plants. Also, it was clear that the shale revolution was not going away. “The technological barriers had been pierced. Costs made a quantum shift, which would last many years in the future.”
Transco supplied about 90% of the gas to Virginia. Ironically, Transco’s shift to bi-directionality was causing issues for Dominion. As Marcellus gas flowed south in the system and Gulf gas flowed north, the two gas flows bumped heads, so to speak, in Maryland and Virginia, creating a “null point.” The null point was not static but moved about depending on who was taking gas off the system and who was putting it in, but the movement made it difficult to maintain gas pressure nearby within tight parameters. “We saw some operational pressure issues — a real red flag,” said Workman. “It was strategically important to have a pipeline built that we had some say in where it got built and what part of our system it touches.”
In June 2014, Dominion issued its own RFP. One of the companies to respond was Dominion Transmission (DTI), a sister company under corporate parent Dominion Resources. DTI also had responded to the Duke-Piedmont RFP. It soon became apparent that there would be tremendous advantages to combining the two projects, building one larger pipeline instead of two smaller ones. Within short order, the conversation expanded to include Virginia Natural Gas and Public Service of North Carolina, regional gas distributors experiencing similar issues to Piedmont Natural Gas.
“We have been in the market for a couple of decades looking for a chance to bring gas into Hampton Roads,” said Jim Kibler, president of VNG. Hampton Roads is situated in a natural gas cul de sac served by Columbia Gas and Dominion Transmission. A major project, the Hampton Roads Crossing, provided some flexibility by allowing the company to move gas between the Peninsula and south Hampton Roads, but it didn’t address the company’s overall supply constraints. Said Kibler: “Proposals for bringing in more gas were never economic for our customers.”
For the gas distribution utilities, the Atlantic Coast Pipeline was a game changer. Where Transco ran through the Carolina and Virginia Piedmont, west of Charlotte and Raleigh, the ACP route would take it east of those two major metros, and a lateral line would connect with Hampton Roads, bringing additional gas to regions that either have no service or are under-served.
“The beauty of the ACP is that we’re able to aggregate our load with those other customers, and the result is far more economical than any of the alternatives we explored in the past,” said Kibler. “We don’t have any other options. … We’ve explored Columbia and Dominion but those vintage pipelines are not easily expanded. You can’t simply add compressors. You have to twin them” — laying down a parallel pipe — “and those rights of way are too narrow.”
Having access to two pipelines gives Duke, Dominion, Piedmont and VNG access to a greater diversity of gas suppliers, thus giving them an opportunity to buy the gas at lower prices and better terms. The ability to tap both Gulf and Marcellus gas supplies also allows them to play off seasonal variations in prices. In Southern markets served primarily by Gulf gas, demand and prices peak in the summer. In Northern markets served increasingly by Marcellus gas, demand and prices peak in the winter. Located midway between, Virginia and North Carolina are geographically positioned to take advantage of those differentials, Workman said.
Also, the shutdown of the Colonial Pipeline Co. gasoline pipeline due to an accident in Alabama vividly illustrates the economic risk of industrial accident. Experts predicted that the disruption to gasoline prices could send prices 20 percent to 30 percent higher in some Southeastern states.
“Our regulators and customers do not want us to put reliability at risk,” said Yoho with Piedmont. “We run infrastructure so that for the customer at the end of the system on a cold winter day, the heat comes on when they turn on the thermostat.” Two pipelines allows a greater diversity of suppliers. “We’d rather have a portfolio of suppliers, not just from a gas perspective but a pipeline perspective. To ensure grid reliability, we want diversity, we want geographic options. ACP fits perfectly with that overall risk management.”
Workman made the same point: “What we do for our customers is manage risk. One of the key tools of risk management is diversity — of power plants, pipes, and suppliers.”
The nature of the industry is undergoing a tectonic shift, says Kibler. Historically, the people who built pipelines were enterprises who thought they could line up enough customers to cover the cost and make a profit. But that’s changing. “The market was not maturing fast enough for us. We were talking to everyone we could talk to, and no one was coming forward. Today, utilities are the forefront.”There are currently 2 comments highlighted: 126411, 126468.