Virginia imports over 50% of its natural gas via pipeline from out-of-state sources. Some natural gas is produced in southwestern Virginia, including methane from coal beds in the Appalachian Plateau and natural gas from shale formations, extracted after fracking. In addition, a tiny amount of methane is captured at landfills and even at wastewater treatment plants.
In Virginia, two commercial oil fields produce gas as well as fluids. In reverse, when natural gas is brought to the surface and pressure is lowered, some hydrocarbon molecules condense into liquid - so oil fields produce some gas, and gas fields produce some oil. The condensates or natural gas liquids extracted from the Marcellus Shale gas in western Pennsylvania/Ohio provide raw material for refineries around Pittsburgh and Philadelphia, while the gas itself provides energy for refinery operations as well a shipment to the East Coast.
Natural gas from a well (or a landfill) includes unwanted gases, such as water vapor and hydrogen sulfide, in addition to valuable hydrocarbons. The vapor and hydrogen sulfide must be stripped out near the well before natural gas can be shipped far in a pipeline, to avoid rust and other damage to the pipes and valves.
Coal bed methane is different. It includes roughly 10% carbon dioxide, but lacks much of the water vapor and other contaminating components found in "conventional" natural gas wells. Virginia's coal bed methane wells also lack the valuable liquid condensates, but require less processing before the gas can be transported via pipelines.1
Only a few urban areas in Virginia used natural gas until after World War Two. Most natural gas extracted with oil at wells in Texas/Louisiana was being flared off at the wellhead, burned as a waste product, because there were no the pipelines to transport it to where energy costs were high. Urban areas on the East Coast generated methane locally in "gas works," manufacturing methane by heating coal in a retort without oxygen. The methane manufactured at gas works was used for industrial operations as well as residential purposes (especially lighting/heating).
During World War Two, the Federal government built two pipelines to bring oil from Texas to factories manufacturing industrial products in the Ohio River Valley, Philadelphia region, and ultimately New York/New Jersey. Pipeline transport was more expensive than shipping oil in tankers, but an inland route was needed to avoid the threat of German U-boats along the Atlantic Ocean coast.
German U-boats stimulated development of pipeline technology, leading to transport of natural gas under high pressure through Virginia
Source: National Park Service, Torpedo Junction
The 24-inch wide "Big Inch" pipeline carried crude oil to Illinois, Pennsylvania, and then to New York; the 20-inch wide "Little Inch" pipeline carried refined oil products (kerosene, diesel, etc.) on a parallel path. The successful construction of Big Inch and Little Inch demonstrated that modern steel and welding techniques could handle high pressure in large-diameter pipelines.
After the war, the oil companies returned to shipping their products from the Gulf Coast by tankers, and the Federal government auctioned off the Federally-owned Big Inch and Little Inch pipelines. Oil companies supported conversion of those two pipelines to transport natural gas rather than oil. Converting the pipelines to transport gas would reduce the risk that a new competitor could acquire and sell oil independently from the existing major oil companies.
Coal companies and railroads objected to Federal plans to convert the oil pipelines to move natural gas. Natural gas from the Gulf Coast, delivered through the two pipelines, could disrupt the railroad's shipment of coal to the New York area, where it was used to manufacture "coal gas" by heating the coal without oxygen to create methane.
A short strike of unionized coal workers in 1946 made clear the advantages of having an alternative energy source in the Northeast. Sale and conversion of the two oil pipelines in 1947 initiated large-scale use of Gulf Coast natural gas in the Northeastern states.
After Texas Eastern purchased the Big Inch and Little Inch pipelines, a competitor emerged. Transcontinental Gas Pipe Line (Transco) built a new distribution system on the eastern side of the Appalachian Mountains to carry Gulf Coast gas north to service cities on the Piedmont (such as Atlanta and Charlotte) and ultimatey the New York market. Thanks to pipelines built on both sides of the Appalachians, natural gas from the Gulf Coast finally could replace higher-priced methane manufactured from coal ("coal gas").
Texas Eastern was required to sell gas to existing customers along its route through Illinois to New York. As a new pipeline, Transco had no existing customers along the eastern side of the mountains. Transco signed contracts with some customers in Virginia such as Danville, but the company reserved enough volume so Transco could become the dominant supplier in New York. There, it could earn higher profits by selling gas to utilities.2
The Transco pipeline today is owned by Williams Companies. It is still the primary trunk pipeline that carries natural gas from the Gulf of Mexico and adjacent states to Virginia, but the direction of flow is being reversed.
After development of the Marcells Shale gas fields through fracking, that pipeline now brings gas from West Virginia, Ohio, and Pennsylvania south to Virginia. The company will expand pipeline capacity across Pennsylvania (the Atlantic Sunrise Project) and push gas in the main pipeline towards the south. The company's proposed Appalachian Connector project would provide a new link bringing Appalachian gas to the existing Transco pipeline in Virginia, joining at the Transco Station 165 compressor station in Pittsylvania County.
Two other companies, Spectra and Columbia Gas (NiSource), own the other two major interstate pipelines bringing natural gas into Virginia. Both of those trunk lines bring Gulf Coast and Appalachian gas eastward into Virginia.
Texas Eastern still uses the former Big Inch and Little Inch pipelines to deliver natural gas to New York City and New England; an extension from those historic pipelines, the East Tennessee Natural Gas pipeline, serves southwestern Virginia. The East Tennessee Natural Gas pipeline also transports coal bed methane generated in the coal fields of southwestern Virginia. Both Texas Eastern and East Tennessee Natural Gas are subsidiaries of Spectra Energy now.
the first Transco natural gas pipeline connected the Gulf Coast with the Northeast, but now can bring gas from Pennsylvania/Ohio south to Virginia
Source: Williams Company, Gas Pipeline Asset Map
In addition to Transco (Williams) and the East Tennessee Natural Gas pipeline (Spectra Energy), Virginia receives large supplies of natural gas from two other interstate pipeline companies. Columbia Gas Transmission has two major pipelines that cross into Virginia from its western border to supply both Northern Virginia and Hampton Roads.
Dominion Transmission, a subsidiary of the same company that dominates the electricity market in Virginia, built a pipeline to carry natural gas from Maryland to the Possum Point electricity generating plant in Prince William County. That pipeline was planned to carry Liquefied Natural Gas (LNG) from the Cove Point LNG terminal in Maryland to Possum Point. After the success of fracking in the Appalachian Basin, Dominion decided to reconfigure the Cove Point terminal to export, rather than import, LNG. The primary supply for Possum Point will be shale gas delivered via pipeline from Pennsylvania, Ohio, and West Virginia.
Transco, Spectra and Columbia Gas own the major interstate trunk pipelines bringing natural gas to Virginia
Source: 2010 Virginia Energy Plan, Section 5 - Natural Gas
Spectra's East Tennessee Natural Gas pipeline carries gas into southwestern Virginia
Source: Spectra Energy, East Tennessee Natural Gas
Within Virginia, Virginia Natural Gas owns the largest intrastate gas pipeline, carrying gas from the Transco system in Northern Virginia to Richmond and Hampton Roads.
transmission companies deliver natural gas to Local Distribution Companies, which have their own network of intrastate pipelines to distribute the gas to end users (investor-owned LDC's are utilities regulated by the SCC, while municipal LDC's are outside of SCC jurisdiction)
Source: State Corporation Commission, Map of Service Territories
Natural gas is pumped through underground pipelines with compressor stations every 40-100 miles to maintain pressure. Trunk lines may be under as much as 1,000 pounds/square inch pressure, while distribution line pressure is 60-150 pounds/square inch.
Virginia has almost 2,000 miles of high-pressure natural gas "trunk" pipelines, plus 20,000 miles of lower-pressure, smaller-diameter distribution pipes connecting to 1.2 million customers, plus about 10 miles of "gathering lines" that connect gas-production wells to the pipeline network.3
The price of conventional natural gas and coal bed methane produced in Virginia, and the cost of natural gas used by Virginia customers, is shaped by an international energy market. Supply and demand are affected by international events, with intermittent crises triggering spikes in prices. International agreements based on policy, such as the volume and prices of gas sales from Russia to European countries, warp the way prices could have been established through the standard laws of supply and demand. Increases in supply require more time to affect prices than interruptions that political/military/terrorist actions that block deliveries, since massive investments in infrastructure are required to move additional natural gas through Liquefied Natural Gas (LNG) tankers or through pipelines.
LNG, cooled to -260°F to compress the gas into liquid form, can be imported into Virginia via the Cove Point LNG facility in Maryland, or exported through that same location. The Cove Point facility was built after the 1973 energy crisis, when the oil cartel increased prices after the Yom Kippur war in the Middle East. Existing pipelines could not ship a sufficient supply of natural gas from Texas to the Northeast. After a great deal of debate, the LNG terminal was constructed in Maryland to import natural gas from Algeria.
Following completion, the economics of the energy business changed again. After passage of the Natural Gas Policy Act of 1978, prices for natural gas were deregulated in the US. Energy companies developed more of the resource, especially shale gas reservoirs starting with the Barnett Shale in Texas during the 1980's. The shale reservoirs had been classified as unconventional sources of natural gas, because the low porosity of the shale formations blocked gas molecules from migrating to a wellbore. Fracturing the shale with water under pressure, then propping open the fractures with sand particles injected in the hydraulic fracturing process, created artificial pathways through the rock formations and made it economical to recover the gas.4
After the cost of US natural gas dropped below the cost of imported LNG, the Cove Point terminal was idled between 1988-2003 until rising demand exceeded domestic supply again. At the start of the 21st Century, demand for natural gas outstripped supply again, and new focus was placed on LNG ports. Dominion Resources purchased the facility in 2002, and since 2003 Cove Point has imported LNG from Trinidad, Nigeria, Norway, Venezuela and Algeria.5
Future imports may be few and far between. The development of shale gas through horizontal drilling and "fracking" shifted the industry's economics again. Drilling in the Marcellus and Utica shales in the Appalachian basin, and other strata elsewhere in the United States, dramatically increased supply of natural gas.
While all that gas could be used within the United States, foreign customers are willing to pay more for the gas than domestic customers - especially when political disputes in Europe affect the willingness and ability of Russia to export its gas to Germany, Poland, and Ukraine.
A barrel of oil has roughly six times the energy of 1,000 cubic feet of natural gas, so when the price of oil is more than six times the price of gas (a 6:1 ratio), customers seek to shift to gas. With the new supply of shale gas, the price of gas in the domestic US market has dropped far below the 6:1 ratio. When oil was close to $100/barrel and gas was less than $4.00 per thousand cubic feet, the ratio was 25:1. Not surprisingly, the Federal government received proposals to export 30 billion cubic feet/day, as much as 1/3 of domestically-produced gas, to foreign customers.6
Long-operational pipelines to Mexico and Canada can not reduce the domestic surplus sufficiently. In particular, gas from the North Slope of Alaska could be exported overseas, rather than shipped by pipeline or tanker to markets in the Lower 48.
An Energy Information Administration study calculated that authorizing LNG exports could increase the price of natural gas in the United States by 3-9%, but gas prices still were predicted to be low enough to spur a dramatic increase in the chemical industry as plants were built to use gas as a raw material for manufacturing plastics and other products. The cost differential between US-produced gas and foreign gas/oil makes LNG transport to Korea, Japan, China, India, Great Britain, and other customers via tankers very attractive. In 2013, the key statistics were:7
Based on those numbers, Virginia's chemical plants concentrated in Hopewell should anticipate prices for feedstock will be determined by demand in Asia as much as by increased shale gas supplies. (Though permit applications were received to export 1/3 of domestic supply, Algeria, Russia, and other producers will meet much of that demand.)
The US Department of Energy authorized Dominion to use Cove Point to export gas in 2011. Dominion later requested expansion of that authority to export LNG to countries not part of a free trade agreement - including Japan and India, with which Dominion already had signed contracts for 100% of the export capacity. Dominion insulated itself against potential changes in gas prices and guaranteed itself a profit by contracting only to provide terminal services at Cove Point; customers will purchases the natural gas in separate contracts, and Dominion will get paid not matter how energy prices fluctuate. As a Dominion official noted:8
In 2013, Dominion formally obtained Federal Energy Regulatory Commission (FERC) approval to modify Cove Point so the utility could export US-produced LNG, as well as import LNG if the market shifted again in the future.
Cove Point was not the only LNG terminal on the East Coast that was repurposed for export. The Elba Island terminal near Savannah, Georgia was also approved for conversion from an import into a LNG export facility. Because of its location, Cove Point had a competitive advantage for exporting gas produced in the Marcellus shale, but the Savannah facility has a shorter pipeline path for Gulf Coast gas - and other LNG export terminals in Texas are even closer to that gas. The US Department of Energy did not approve/reject facilities based on the economics of gas transport; it allowed the market to determine which facilities would ultimately become successful.9
Exporting Liquefied Natural Gas (LNG) from Cove Point required upgrading compressor stations in Loudoun/Fairfax counties to increase pipeline capacity.10
The gas pipeline system consists of expensive, fixed infrastructure, but the movement of gas can still be revised to reflect changes in supply (as at Cove Point, or in newly-developed shale gas basins) or in changes in demand. In 2003, Dominion converted Units 3 & 4 at the Possum Point power plant in Prince William County from coal to natural gas, and added a 550-megawatt combined-cycle Unit 6 (with two conventional combustion turbines and a steam turbine) that can burn either natural gas or #2 fuel oil. The conversion helped meet air pollution mandates required to settle a lawsuit between EPA and Dominion in 2000 regarding emissions from Mount Storm, as well as take advantage of the relatively low price of gas.11
That altered demand for gas in the area. The units, generating 336 megawatts, are now supplied with natural gas through a 14-mile pipeline extension that provided access to LNG imported at Cove Point - though for the moment, it appears domestic sources rather than Algeria, Nigeria, etc. will provide the fuel for Possum Point.12
Before natural gas pipelines brought gas from the Gulf Coast, local municipalities and some industries in Virginia manufactured methane from coal. The second demonstration in the United States of how methane could be generated from coal was in Richmond, in 1802. Starting in the 1850's, the Fulton Gas Works operated for nearly 100 years.13
Arlington, Danville, Fredericksburg, Lynchburg, Norfolk, Newport News, Portsmouth, Richmond, Roanoke, and Suffolk produced methane from coal gasification plants ("gasworks"), for local use. When the Transco pipeline was constructed through Virginia in 1950, the municipal Water and Gas Distribution Department of Danville and other cities in Virginia switched from manufacturing methane to using pipeline-supplied natural gas.14
Natural gas is a high-volume, low-energy product, so storage is difficult. To ensure adequate supplies during the winter, Spectra Energy transports natural gas during the summer via the East Tennessee Natural Gas pipeline to Saltville, where it stores the gas in salt beds. Spectra injects gas underground when demand is low and extracts gas when demand increases during the winter. The underground storage uses caverns that were excavated when Olin Corporation pumped salt brine to the surface for its chlorine and caustic soda business, plus additional caverns created by solution mining since 1994 just to store natural gas.15
Cove Point Liquefied Natural Gas facility, on the Chesapeake Bay where ocean-going tankers can dock
Map Source: US Fish and Wildlife Service, Wetlands Mapper
Propane and butane, forms of natural gas with higher energy than methane, are shipped as compressed natural gas in rail cars. Those who have barbecue grills are familiar with carting empty metal tanks to a nearby local store to switch for a tank filled with compressed natural gas, while some homeowners get one or more visits each winter from a large truck to refill the propane tank that supplies the furnace and kitchen.
Gas terminals do not need to be located on a pipeline. Propane has traditionally been trucked to the city of Roanoke from North Carolina, but in 2013 a company proposed building a gas terminal that would be supplied by two rail deliveries daily during the heating season. The area was zoned for industrial use, but neighbors in the Morningside community quickly expressed concern about constructing three 60,000-gallon propane tanks and two 90,000-gallon butane tanks within a quarter-mile of housing.16
Distribution and retail sales of natural gas are separate businesses. Trunk lines such as Transco are common carriers. They transport gas for a fee to utilities, which then sell the gas directly to retail customers. Homeowners pay their gas bills to utilities, not to pipeline companies.
The State Corporation Commission (SCC) defines the boundaries of exclusive service areas for gas distribution companies in Virginia. The rates for natural gas service are established by the SCC, and companies must obtain state approval before raising or lowering rates. Eliminating competition for gas distribution reduces the cost of building the pipeline infrastructure to service customers. In exchange for the monopoly, distribution companies must accept state regulation.17
The exclusive service areas are easy to see when examining maps of service areas in Tidewater Virginia for Virginia Natural Gas and Columbia of Virginia, especially in the cities of Suffolk, Chesapeake, and Virginia Beach in Hampton Roads:
The Virginia Natural Gas pipeline is an intrastate system (within the borders of just Virginia), distributing gas to customers on the Middle Peninsula, the Peninsula, and in Hampton Roads. In 2010, Virginia Natural Gas connected its separate networks of pipelines in Hampton Roads, located on opposite sides of the James River. The underwater Hampton Roads Crossing linked the south side of Hampton Roads, supplied from the Columbia Gas Transmission pipeline, with the Peninsula side (north of the river) supplied by Dominion Transmission.
The project set a world record for length of continuous underwater horizontal directional drilling, which was used to install pipe under the shipping channel in the Elizabeth River and between Craney Island-Hampton. (The less expensive technique of trenching-and-filling, which creates more environmental impact on the clam/oyster beds due to suspended sediment, was used in places.) Horizontal directional drilling was also used when Washington Gas installed a new distribution line under the Occoquan reservoir, to supply customers in Prince William County.18
A Federal agency, the Federal Energy Regulatory Commission (FERC), must issue a "Certificate of Public Convenience and Necessity" to approve new transmission pipelines. For example, when Dominion decided to build a new 1,300 megawatt electricity generation power plant in Brunswick County and use natural gas as the fuel source (while shutting down two older coal-fired power plants), the existing pipeline to the region was already operating at full capacity. Both FERC and the SCC had to approve the Virginia Southside Expansion of the Transco pipeline and must approve proposed competitors, such as the Atlantic Coast Pipeline.
The safety of gas pipelines depends upon the maintenance of the infrastructure. Metal pipe corrodes in the ground, and the high-pressure gas can break through at welds or thinned sections of pipe. Transmission lines must be inspected by a variety of techniques (including "smart pigs" that move inside the pipes to test wall thickness).
In 2008, the Transco pipeline exploded dramatically near Appomattox. Williams, owner of the pipeline, was fined nearly $1 million by the US Department of Transportation for failure to monitor corrosion adequately. A hydrostatic test of the Virginia Southside Expansion revealed a leak before the pipeline was put into service. The leak created only "a small hole in the ground where the water escaped," revealing a weak pipe joint that was quickly replaced.19
Leaks can also be revealed by odor. Natural gas is naturally odorless. A chemical with a pungent odor, mercaptan, is added so gas will be easier to smell if it is leaking in a building. Mercaptan is added when it enters the distribution network; it is not added to all trunk lines, so a leak in a major pipeline could be odorless.
Transco started to add mercaptan at the northern end of its trunk line. By 2015, the added pressure from shale gas produced in the Marcellus/Utica formation of Pennsylvania/Ohio/West Virginia forced the "null point" in the Transco mainline from New Jersey to the south, where the system lacked ventilation and other facilities to deal with the odorized gas.
As part of its proposed Atlantic Sunrise Project and Leidy Southeast Expansion Project, Transco proposed to deliver more Marcellus Shale gas to Virginia and other Mid-Atlantic states. The Phase II Virginia Southside Expansion would upgrade compressor stations and other facilities to "odorize" that gas in Transco pipelines as far south as South Carolina.20
due to additional suppliess of natural gas from fracking in the Marcellus Basin, the Transco pipeline could deliver gas to power plants in Brunswick and Greensville counties from Pennsylvania/Ohio/West Virginia rather than from the Gulf Coast
Source: Williams Gas Pipeline Update & Strategies
In addition to breaks caused by corrosion in pipes after decades underground, pipeline leaks and explosions can also triggered by nearby construction projects that accidentally cut into gas pipelines (and other utilities). All regulated utilities in Virginia are required by the Virginia Underground Utility Damage Prevention Act to join the Virginia Utility Protection Service ("Miss Utility") system.
Since 2007, anyone planning to dig underground can call 811. Owners of underground infrastructure - including the gas pipeline companies - get notified, and must mark the location of their facilities within three business days.21
In 2013, utilities such as Verizon and Virginia Natural Gas could contract with United States Infrastructure Corp (USIC), UtiliQuest, or S&N Locating Services to mark the locations. When excavators realize the marking is incomplete and their workers are exposed to potentially hazardous situations, they complain to the State Corporation Commission (SCC), which can impose fines on the three companies. According to the SCC, its efforts since the state agency gained enforcement authority in 1995 has resulted in a 68 percent decrease in damage to gas lines.22
Source: US Department of Transportation, Pipeline & Hazardous Materials Safety Administration