Thursday, April 12, 2012

PA Marcellus News Digest 4/12/12

PA Marcellus News Digest
April 12, 2012


Comparative Data Now Available to Track Any Future Water Quality Changes
April 12
HARRISBURG, Pa. – The Susquehanna River Basin Commission (SRBC; today released a data report ( on existing or baseline water quality conditions in small watersheds in the Marcellus shale region of the Susquehanna River Basin.  Prior to 2010 when SRBC began collecting the data through its state-of-the-art Remote Water Quality Monitoring Network (RWQMN), little to no water quality data existed for many smaller streams in northern Pennsylvania and southern tier New York.

DEP to Discuss Lathrop Compressor Station Explosion
DEP Newsroom
April 12
WILKES-BARRE -- The Department of Environmental Protection announced today that it will hold a public briefing on Tuesday April 17 to discuss the circumstances surrounding the Lathrop compressor station explosion that occurred March 29 in Springville Township, Susquehanna County.


Fracking's collateral damage
News Item
Walt Brasch
April 8
[...]On Feb. 18, after reading a story in a local newspaper, the residents found out their landlord had sold the park. Four days later, they received certified letters making it official. The owner sold the park to Aqua PVR, a division of Aqua America, headquartered in Bryn Mawr. Sale price was $550,000. It may have been a bargain - land and industrial parks that have been vacant for years are going for premium sales prices as the natural gas boom in the Marcellus Shale consumes a large part of Pennsylvania and four surrounding states.

Doctors say Pa. gas-drilling law hurts health
York Daily Record
Michael Rubinkam and Kevin Begos
April 11
PITTSBURGH -- Public health advocates and doctors on the front lines of Pennsylvania's natural gas-drilling boom are attacking the state's new Marcellus Shale law, likening one of its provisions to a gag order and complaining that vital research money into health impacts was stripped at the last minute.

Judge halts zoning limits in Pa. gas drilling law
Times Leader
Marc Levy
HARRISBURG, Pa. — A judge on Wednesday ordered a temporary halt to the sections of Pennsylvania's new Marcellus Shale law that put limits on the power of municipalities to regulate the booming natural gas exploration industry, a victory for the seven municipalities that sued.

PIPELINES: A proposed Marcellus Shale gas line seeks utility customers
E&E News
Energy Wire
Peter Behr
April 12
(full text below)
The developer of a proposed $1 billion, 195-mile gas pipeline from the Marcellus Shale gas region in western Pennsylvania to the Eastern Seaboard is counting on new gas-fired electric power plants to take up a crucial share of the pipeline's future deliveries.

"We're chasing that opportunity, and the opportunity that exists there is to burn clean natural gas and convert it into electricity," said Bill Moler, chief operating officer of Inergy Midstream. Kansas City-based Inergy says it hopes to have the Commonwealth pipeline operating by 2015.

Just under half the capacity of the planned 30-inch-diameter pipeline has been subscribed to by two major gas distribution companies in the region -- UGI Corp., serving Pennsylvania, and WGL Holdings Inc., parent of Washington Gas. But as much as a quarter of the pipeline's deliveries could go to gas generators, said Tony Cox, manager of midstream business for UGI Energy Services.

"This will provide not only a consistent, reliable supply to the area, but also competitively priced gas vis-à-vis other supplies" traveling over several thousand miles from the Gulf of Mexico or midcontinent regions, he said.

The proposed pipeline addresses an issue that has seized the attention of federal and state grid regulators: how to ensure a future adequate supply of natural gas for new power plants or old ones that convert to gas from coal or oil.

The Federal Energy Regulatory Commission has solicited comments from both gas and power industries on the challenges of aligning their two very different infrastructures and markets.

"The two industries have become more intertwined than ever before, yet the terminology and cultures of the two industries have not progressed as far so as to ensure the level of reliability coordination that will be needed in the future," the PJM Interconnection said in its comments to FERC. Indeed, the FERC filings document in detail how far apart the two industries are at a time of profound change in the gas and electric power markets.

Testing pipeline capacity

The emergence of the Marcellus and Utica shale gas deposits around the Appalachian region has created a potentially vast new supply of natural gas for the northeastern United States. The gas boom has dropped natural gas prices to 10-year lows, making power from new gas plants cheaper than comparable coal-fired generation, Charles River Associates noted in its comments to FERC. Tight new federal environmental regulations on coal plant emissions are also accelerating the shift to gas generation from coal and oil.

Around 100 gigawatts of new gas-fired generation is expected to be added nationwide to the grid over the next decade, and the projected addition of 80 GW of wind power would also swell demand for gas generators to back up wind farms, the North American Electric Reliability Corp. noted in its filing with FERC. As a result, gas demand for the electric sector could grow by between 2 percent and 3.6 percent annually over the next two decades, NERC said.

But the expansion of gas demands coming from gas-fired generating plants will strain the existing pipeline network, particularly in the Northeast, which lies at the end of the big interstate pipeline network, according to a consensus of electric power and gas pipeline experts.

The Commonwealth project is one of a number of new pipeline ventures that could relieve strains on gas delivery for generating plants along the East Coast.

UGI's Cox said a modern 800- to 900-megawatt combined cycle gas generating plant would consume about 150,000 decatherms of natural gas a day if used for baseload supply. (A decatherm is a unit of heat value equal to 1,000 cubic feet of gas.) The Commonwealth pipeline would move between 800,000 and 1 million decatherms daily. "I expect there ought to be several hundred-thousand decatherms to offer to large power plants," Cox said.

"We have talked to power plants, existing industries and forecasted industry and power plant loads," Moler said. He and other project backers are asking how much gas those potential customers need, what it would cost to supply them and what rates would be required to make the project work, he said.

"Right now, it is a significant iterative process," he added. "While we're trying to get people signed up, the route moves one way or the other daily, and the costs and revenues adjust accordingly. We intend to have an open season [to solicit customer bids] in the second or third week of April. That will bring the parties to the table in a more formal matter."

Bridging the gap

A fundamental challenge Commonwealth faces is the marked differences in the way gas and electric power markets operate. That is the divide the Commonwealth pipeline project hopes to cross as it seeks business from both gas distributors and generators.

The pipeline industry notes that pipeline developers like Inergy don't build $1 billion projects on the come: They typically line up long-term "firm" contracts from local gas distribution utilities that have "duty to serve" requirements to deliver gas to homes and businesses.

Electricity markets like those in the Northeast operate on a completely different timetable. Grid operators decide hourly on which power plants will run based on the amount of power required each hour and the prices the generators bid.

Gas generators in these markets want to buy gas close to when it will be needed to lessen the risk that they will wind up paying for gas they cannot use if it turns out their plant isn't called on to produce power. That strategy, however, could leave them unable to operate on the coldest winter days when demand for both heating gas and gas-fired power peak: Heating customers backed by firm pipeline supply contracts will have priority.

"At present, there is no mechanism to bridge the gap between the collective need for new gas pipelines and the (commercially sensible) reluctance of individual [electric power] companies to commit to long-term gas contracts," Charles River Associates said.

The simple answer proposed by the pipeline industry is for generators to get their own long-term contracts, PJM said, but much of the power industry has lined up against that option in comments to FERC.

"Any focus on deliverability issues should not be limited by the paradigm of today's definition of what constitutes 'firm' [gas] transportation service," PJM said. Gas-fired power plant operators face complexities that don't exist in the stable world of heating gas delivery, it said. These include environmental rules that may determine when power plants can run and the uncertain timing of shutdowns at coal-fired generators in the face of costly new environmental regulations and competition from cheaper gas plants.

The New England Power Generators Association, whose members have a combined 27,000 MW of generating capacity in the region, said it "does not support mandates that natural gas-fired generators enter into firm supply contracts with gas pipelines."

The Ohio Public Utilities Commission noted to FERC that generating companies in the PJM system need to give grid managers only a 90-day advance notice of plans to retire plants and that is not enough time for new gas generation facilities to be built to replace the shuttered coal plants. The notification period should be extended to a year or two years, the commission said.

The Edison Electric Institute and many other commentators in the FERC proceeding urged the commission instead to take an active lead in seeking regional solutions to the gas-power infrastructure alignments, beginning with careful assessments of where gas shortages or bottlenecks could lead to blackouts.

FERC also should act to align gas and power markets so that pipeline developers have strong incentives to build more lines and power companies have more flexible opportunities to buy gas close to when they need it, some commentators said.

PJM said FERC should consider making generators responsible for assuring the deliverability of gas that would be needed to produce enough power to keep the grid operating reliably.

While reliability plans should reflect different regional needs, PJM said, FERC should ask whether some "overarching national criteria" on assuring gas deliveries are needed, either because current energy markets are not providing adequate incentives to get more pipelines built or because one region decides to "lean on" a neighbor and let it bear the majority of new pipeline investment costs.

PJM said FERC should investigate whether gas distributors should offer the same kind of demand response programs that give electricity consumers incentives to cut back their power requirements when demand peaks. FERC should look into turning such consumer programs into a kind of "spot market" for gas that power companies could use on short notice to meet unexpected demands, PJM added.

Inergy's Moler said the Commonwealth project will explore ways to line up utility industry support for its new pipeline and will talk to potential customers about how the gas and utility sectors can work together more effectively. One strategy is to seek to locate new gas-fired power plants closer to transmission lines and underground gas storage reservoirs. (Gas utilities can build in price and supply flexibility by calling on gas supplies stored in underground rock formations.)

"I do think there are opportunities for those two industries to have better planning and communications up front," he said. "There are ways to fix this."
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