Natural Gas Pipeline Capacity Raises Concerns
Natural Gas Pipeline Capacity Raises Concerns
Shifting Natural Gas Supplies Adding to U.S. Pipeline Constraints
A prime example of the growing issue of U.S. natural gas pipeline constraints occurred this winter in portions of the U.S. Northeast. Electric power generators in New England and New York relying on the natural gas spot market saw prices spike to up to 10 times higher than the price of gas elsewhere. These prices rose to nearly $40 per million British thermal units (MMBtu), while gas prices remained in the $4 range in other parts of the United States.
While the volatility lasted just a few days, it highlighted a key problem the industry is facing – insufficient pipeline capacity to deliver growing peak demand gas needed for gas-fired electric generators, as well as residential and commercial consumers. Even with large gas projects in the Northeast, like the Appalachian Gateway tapping the booming Marcellus shale gas, pipeline capacity issues raise concerns.
For purchasers of natural gas, the ability of a pipeline to consistently deliver gas to a specific point translates into one word – reliability. And these purchasers tend to bundle the value of pipeline capacity and the cost of their gas purchases into a single unit – evaluating it as the cost to deliver the product to their facility. So it is no surprise that Northeast utility respondents to Black & Veatch’s “2013 Strategic Directions in the U.S. Electric Industry” report rated both pipeline reliability and gas price volatility as their first and second concerns.
Currently, the Federal Energy Regulatory Commission is holding proceedings on the convergence of the natural gas and electric markets. This is a long-term regulatory process that is aimed at addressing issues around capacity, reliability, supply and associated risks in these increasingly interdependent industries.
Reserving Space in Pipelines
This makes it all the more important for electric utilities and other gas purchasers to have a detailed integrated resource plan that considers pipeline capacity and gas pricing issues, as well as the physical location of the gas purchases relative to the desired point of delivery, according to Rick Porter, Director, Natural Gas Pipeline Regulatory Advisory Services for Black & Veatch’s management consulting division.
In the past, pipelines could generally deliver all of the gas that was “nominated” (i.e., requested) at a given period of time by their shippers. This sometimes included peak period nominations, even without a firm contract for gas delivery. Today, Porter noted, when usage spikes, those shippers without a firm capacity contract discover that capacity is more difficult to find when it is most needed.
“It’s like coming into a city and looking for a room when you didn’t know there is a convention in town,” Porter said. “If by habit you planned ahead and reserved a room, then you’re sleeping comfortably that night. It’s essentially the same with pipeline capacity – if you don’t have pipeline space reserved when there is high demand, you’ve got supply and price issues.”
Black & Veatch sees a plausible scenario in which U.S. natural gas-fueled generation more than doubles in the next 25 years. This is supported by its “2013 Strategic Directions in the U.S. Electric Industry” report in which one-third of electric utility respondents expect to increase natural gas demand by more than 25 percent by 2020. With additional gas-fired generation increasing as more coal plants are retired, in certain regions there will be less available gas pipeline capacity and less interruptible gas pipeline capacity, in particular.
“When power generators look at portfolios, they have to be sensitive to the pipeline capacity portion of their supply portfolio, not just the commodity pricing of the gas,” Porter said. “They also need to look at pipeline capacity as a commodity, and all this must be considered when they put their portfolio together.”
Fewer New Miles of Pipelines
The U.S. Energy Information Agency reports that in 2012 new natural gas pipeline construction was at its lowest level on a mileage basis since 1997, with only 367 miles of pipeline additions. There were some capacity additions that targeted the Northeast to help address its need for the Marcellus shale gas production. This resulted in the Northeast accounting for than 50 percent of the new pipeline projects that entered commercial service in 2012.
The reasons for the drop in new pipeline construction are twofold, Porter said. Pipelines operators are currently focusing their limited capital budgets on realigning pipeline operations and capacity to manage the shift of gas supplies from the Gulf Coast to the Midwest.
In addition, pipelines are addressing deliverability by adding capacity through less costly approaches such as “de-bottlenecking” instead of taking on larger pipeline expansions. De-bottlenecking is designed to improve the gas flow capacity within existing pipeline networks, such as the Tennessee Northeast Upgrade Project, Porter said. But it will take time for pipelines to catch up to changing shipper profiles and growth in demand for capacity. Major new pipeline projects can take more than five years to plan, permit, construct and complete.
Pipeline operators need to have more opportunities to recover their investments and make a solid return on their capital before they will build significant pipeline expansions, Porter said. For example, a proposed $1 billion pipeline project for the Northeast was recently cancelled because the operators could not secure enough firm transportation contract commitments from gas users to justify the pipeline’s construction.
“We have tremendous investment needs for new pipelines from emerging supply basins across the country,” said Porter. “At the same time, pipeline companies have numerous competing demands for their capital dollars – from safeguarding the operational integrity of their existing systems to managing stranded capital on pipelines that are no longer being used to their full capacity. For example, the entire High Island and Stingray pipeline systems in the Gulf of Mexico are significantly underutilized.”
As a result, portions of the regulatory framework may need to be redefined to account for growth in some regions such as the Marcellus, Utica and Eagle Ford shales, while acknowledging contraction in others, such as the Gulf of Mexico, San Juan Basin in New Mexico or the Rocky Mountains region.
Impact of Potential U.S. LNG Exports
The possibility of the U.S. becoming an exporter of liquefied natural gas (LNG) could generate funds that companies need to build more pipelines, according to Ann Donnelly, Director of Fuels for Black & Veatch’s management consulting division. Lower natural gas prices in the U.S. are the driver in the strong moves toward U.S. LNG exports into the world regions, where prices can range up to $15 per MMBtu.
“The move of gas supplies into the export market could have the effect of helping stabilize the price of natural gas in the U.S.,” said Donnelly. “This would create a more healthy investment climate for funding needed for natural gas pipelines.”
Black & Veatch studies show that depending on actual levels, U.S. LNG exports could cause the price of natural gas in the U.S. to rise 25 cents to $1 per MMBtu. Nearly two dozen companies have applied to the U.S. Department of Energy for export licenses, and to date, two have been approved.
Story by George Minter, Black & Veatch
Subject Matter Experts:
Rick Porter, PorterRW@bv.com
Ann Donnelly, DonnellyAT@bv.com