Industries

Virginia’s burning question

Virginia is not yet exploring the potential of Marcellus shale-based natural gas, but development across Appalachia is having an impact

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Print this page by Garry Kranz

A glut of natural gas in the U.S. is having a pronounced impact on Virginia’s electricity costs, especially for businesses that consume lots of it. Recently, regulators at the State Corporation Commission cut electric rates for all customers of Dominion Virginia Power. When new rates take effect Sept. 1, organizations that burn 245,000 to 500,000 kilowatt hours — such as rock quarries, department stores, hotel chains and office complexes — could shave $1,400 to $2,900 off their monthly bills. A mega-sized manufacturer that continuously requires 6 million kilowatt hours could save $35,000 a month. 

The lower rates in Virginia reflect seismic changes in the nation’s energy market. Natural gas is cheaper than it’s been in decades — cheaper even than coal — and utilities like Dominion are stocking up. The reason: troves of shale-based natural gas unearthed in several states in recent years, including the Marcellus stratum that includes a sliver in western Virginia. Advances in horizontal drilling and hydraulic fracturing have combined to make it easier for producers to extract shale-based natural gas, experts say. Tougher federal environmental rules on the coal industry also are making natural gas an attractive option.

Natural gas is not about to overtake coal as Virginia’s chief fuel source, but it’s gaining prominence. Fierce opposition by residents and environmentalists has prevented exploration of Virginia’s tiny Marcellus sliver. Still, Virginia has emerged as a top 20 producer of natural gas in the U.S., including the fourth-highest total of methane recovered from coal beds.

Nonetheless, new drilling in Virginia is down dramatically because of an increase in shale-gas production nationally, according to the Virginia Department of Mines, Minerals and Energy.
Still, dynamic developments are reshaping Virginia’s energy profile. That includes plans by Dominion, the state’s largest regulated electricity utility with 2.3 million customers, to build new natural-gas-fired power plants, along with efforts by state officials to make it easier for natural gas companies to add infrastructure to distribute natural gas.

Access to low-cost, reliable electricity is crucial in energy-intensive industries such as technology, shipbuilding, aerospace, and advanced manufacturing. “That’s why we believe it’s important to develop natural gas as part of a balanced energy plan.  We need it to stay competitive,” says Maureen Matsen, deputy secretary of natural resources for Virginia Gov. Robert McDonnell.

Power plants and plant matter
The natural gas market is national in scope. The Natural Gas Policy Act of 1978, a set of byzantine rules that regulate interstate and intrastate production, was passed by Congress in response to domestic shortages of natural gas in the early 1970s. The law sought to decouple production levels from pricing through a series of cost controls. The results were mixed, characterized by periods of low prices that were followed by cutbacks in production, which nudged prices higher.

Until recently, the unpredictable pricing relegated natural gas to a secondary role in domestic generation of base-load electricity. That notion is changing, thanks to sprawling shale basins discovered in Michigan, Montana, North Dakota, South Dakota, Texas, Wyoming and other states. In its Annual Energy Outlook 2012, the federal Energy Information Administration estimates the U.S. sits atop 482 trillion cubic feet of shale-based gas reserves. That includes the Marcellus formation, which originates in southern New York and extends across parts of Ohio, Pennsylvania and West Virginia and a thin portion that runs northwest to southwest in Virginia.

America’s burgeoning shale stockpile is pushing the notoriously volatile price of natural gas below historic norms. Benchmark prices for natural gas are determined by futures contracts sold on the New York Mercantile Exchange, or NYMEX. The price of natural gas settled at $2.50 per million British thermal units (BTUs) for June shipments, according to NYMEX. By comparison, natural gas fetched a price of $10 to $11 per million BTUs for the same time frame in 2008. 

“Producers of natural gas aren’t making as much money, but it is great news for consumers,” who are seeing big savings, says Bruce McDowell, director of policy analysis at the American Gas Association in Washington, D.C. McDowell’s trade group in May released a study, “Identifying Key Economic Impacts of Recent Increases in U.S. Natural Gas Production,” which estimates natural gas customers saved nearly $250 billion during the past three years, as increased shale-gas production prompted a corresponding drop in commodity prices.

A new energy picture
Only California buys more of its electricity off the national spot market than Virginia, leading to gyrating prices during times of peak use. Natural gas will account for 23 percent of Dominion’s fuels mix by 2017, more than double the 11 percent it contributed last year. During the same time period, Dominion should be able reduce the amount of electricity it buys off the national grid from 33 percent to 10 percent, says company spokesman James Norvelle.

The magic number for Dominion is 4,000. That’s how many additional megawatts of electricity it must generate by 2022 to meet accelerated demand, according to PJM Interconnection, a Valley Forge, Pa.-based company that manages the electricity grid for Virginia and 12 other states, plus the District of Columbia. If Dominion has its way, three new natural-gas-fired plants will combine to pump out 3,200 megawatts of the heightened capacity.

Dominion says it will ask state regulators later this year to approve a 1,300-megawatt natural-gas-fired plant in Brunswick County, which would replace coal-fired units in Chesapeake and York­town. In February, regulators approved Dominion’s planned 1,329-megawatt Warren County Power Station, scheduled to begin operating in 2014 or 2015.

“Warren County Power Station is a big part of supplying surging energy demand in Northern Virginia,” producing enough electricity for 325,000 homes, says David Christian, CEO of Dominion Generation, which runs the company’s power plants in 10 states.

The new and pending plants come on the heels of Bear Garden Power Station in Buckingham County, a 585-megawatt natural-gas-burning facility that went into service last year. Combined, the three new plants would help Dominion achieve its statutory obligation of ensuring adequate electricity is available, Christian says.

Even farther down the road, Dominion’s 15-year blueprint outlines another 1,300-megawatt natural gas plant to be built around 2019, at a location yet to be determined. The low cost of natural gas, however, won’t affect Dominion’s decision to add a third reactor at its North Anna Power Station in Louisa County, although the company has no firm timetable for it, Norvelle says.

Dominion’s decision to pursue natural gas is unfortunate, says Glen Besa, director of the Virginia chapter of environmental group Sierra Club. “Natural gas prices have been extremely volatile, and Dominion’s over-reliance on it will expose customers to price swings,” Besa says.

Virginia’s shale: No fracking way?
Meanwhile, the Marcellus formation found in Virginia remains undeveloped. Houston-based Carrizo Oil & Gas Inc. last year proposed drilling an exploratory well in Rockingham County, but the Republican-dominated Board of Supervisors refused to act on the company’s request for a special land-use permit. The company abandoned the idea after stiff public opposition. “We have no plans for any activity of any kind in Rockingham County,” says Richard Hunter, a Carrizo vice president.

The controversy surrounding hydraulic fracturing is “media-generated hysteria” and not grounded in objective science, says George Mason, a Kentucky-based attorney who helped draft the Virginia Gas and Oil Act of 1990. “It’s unfortunate that Virginia will have to sit on the sidelines and not know whether its Marcellus deposit is a viable source of clean-burning natural gas,” Mason says.

However, additional proposals for Marcellus drilling are unlikely in Virginia anytime soon, says Mike Miller, a petroleum engineer and senior vice president with Bluefield-based Marshall Miller & Associates, an engineering and consulting firm. “It’s not the most highly prospective area for Marcellus shale, so it won’t be economical for producers to drill here unless the price of natural gas gets a lot higher,” Miller says.

Even so, rock fracturing has been used to develop wells in Virginia since the 1950s, says Rick Cooper, director of the Division of Gas and Oil at the Virginia Department of Mines, Minerals and Energy (DMME). The practice was used mostly to drill vertical wells to recover conventional gas from limestone, sandstone and shale. Some horizontal wells also have been fracked in recent years as well.

Cooper says there are fewer known environmental concerns associated with hydraulic fracturing in Virginia. It necessitates far less water: about 300,000 gallons vs. 3 million gallons for Marcellus fracking in other states. Most fractures in Virginia use pure nitrogen or a mix of nitrogen and water. Injecting too much water hinders the flow of gas, Cooper says. “We have no documented cases of fracturing having contaminated the water table,” he says.

Nearly 7,500 gas-producing wells were operating in Virginia in 2010, according to the most recent statistics compiled by DMME. That includes 1,800 conventional wells and 5,600 wells used to retrieve methane — listed by the EPA as a greenhouse gas — from coal beds in southwestern counties. The two largest producers of natural gas in Virginia are Pittsburgh-based EQT Corp., with 1,176 wells, and Range Resources-Pine Mountain Inc., of Abingdon, with 382 wells.

Virginia’s production of natural gas has been increasing steadily for two decades. All told, production topped 147 million cubic feet in 2010, ranking 18th in the U.S., according to DMME. Coal-bed methane accounted for the lion’s share of Virginia’s production: nearly 121 million cubic feet, good for fourth in the nation.

Industry observers link the upswing in production to passage of the Virginia Gas and Oil Act of 1990, which eased restrictions on methane recovery. It was the first law of its kind in the nation. Before its passage, mining companies would drill vents in coal beds to prevent explosions from methane buildup.

“Changing the law enabled us to convert a waste product into a valuable resource,” says Benny Wampler, a Tennessee-based energy consultant and deputy director of DMME from 1985 to 2008.
Since the law took effect, Virginia’s natural gas industry has generated annual revenues of $150 million from severance taxes, $630 million from royalties, plus $3 billion in cumulative capital expenditures and more than 3,000 jobs, according to the Virginia Oil and Gas Association, a trade group in Abingdon.

But as shale-gas production in the U.S. has increased, new drilling in Virginia has dropped significantly, Cooper says, with Range Resources and other producers shifting resources to northern Appalachian states. 

State geologists predict production here will peak between 2017 and 2022, then plateau to around 200 million cubic feet annually through 2030. “We don’t have the geology or the space to be like Texas. But we probably have the capacity for another 4,000 to 5,000 wells,” says Cooper, DMME’s current deputy director.

Pipelines and pent-up demand
Even as in-state production drops off, the abundance of shale gas nationally could have a major impact on the commonwealth, says Nino Ripepi, a Virginia Tech professor with the Virginia Center for Coal and Energy Research. “But first we need more pipelines, compressor stations and power plants,” he says.

Pipeline capacity has not kept pace with Virginia’s natural gas production. Until this year, a regulatory quirk prohibited natural gas companies from building new pipeline unless enough customers had signed up to buy the added capacity. The idea was to prevent speculative construction projects that resulted in idle capacity and hiked rates for consumers.

But the measure left some areas of the state underserved and hindered economic development by shipping Virginia’s production to consumers in other states, Matsen says. “We had a map with ‘No Pipeline Zones’ on it. It was crazy. We needed to take steps to encourage a Virginia market for Virginia production,” she says.

To reverse course, state lawmakers this year amended the Code of Virginia to enable natural gas utilities to invest in new pipelines and related infrastructure in anticipation of increased demand. The bill headlined a package of energy-related legislation Governor McDonnell signed into law in April. Adding infrastructure would help Virginia take advantage of the abundance of low-priced natural gas, Ripepi and other experts say.

The change came too late to affect a pipeline project undertaken by Virginia Natural Gas. In 2010, the Virginia subsidiary of Atlanta-based AGL Resources Inc. completed the much-anticipated Hampton Roads Crossing, a 23-mile-long pipeline expansion that spans the Elizabeth River and connects its southern and northern pipeline systems. Previously, the two pipelines had been separated by the Hampton Roads harbor.

Known as the HRX Project, it is the first major pipeline expansion in Hampton Roads in decades.

The $140 million crossing, funded out of operating capital, improves delivery and system reliability, says Ann Chamberlain, Virginia Natural Gas’ manager of gas supply. “It was extremely important to build it, because without it, we weren’t sure how we would supply the growing demand,” Chamberlain says.
Construction included laying nearly 16 miles of onshore pipeline spanning the cities of Hampton, Newport News, Norfolk and Portsmouth, plus six miles of underwater construction crossing the harbor to Craney Island.

In addition, Virginia Natural Gas has signed a contract to receive 100,000 dekatherms of natural gas per day from Dominion’s transmission business. “That’s about 20 percent of our peak-day capacity,” Chamberlain says. (A dekatherm is a measurement of how much gas can be shipped from storage facilities each day. One dekatherm is equivalent to about 1,000 cubic feet).

Dominion is plowing ahead with plans for new natural gas power plants, knowing it faces opposition. The combined cost of its new and proposed units — nearly $3 billion —  is still less expensive than buying and installing pricey pollution-control equipment on coal plants, Christian says. “Natural gas is even more critically important now because of stricter environmental restrictions that essentially take the building of coal plants off the table,” he says.

The battle lines already are being drawn. Besa says Sierra Club will fight Dominion’s plant-building agenda, noting that natural gas is a fossil fuel that emits carbon and contributes to climate change. The dispute between the two sides could get rancorous: Dominion in May sued Sierra Club for trying to block its construction of a terminal in Maryland that would be used to export liquefied natural gas.

There’s little debate that fast-growing Virginia soon will require more and more electricity. With the coal industry under siege, nuclear plants on hold and renewables still emerging, natural gas — now plentiful, cheap and ready to burn — seems poised to take on a greater role in fueling Virginia’s population explosion. 


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