Utility developers planning combined-cycle gas turbine (CCGT) projects in the Marcellus and Utica shales are looking for a “power price appreciation” from excess natural gas, not growing demand, to ensure a fair return on their investments, according to an analysis by Tudor, Pickering, Holt & Co. Inc. (TPH).
It may take more than excess shale gas, however, to ensure that the projects are a success, said analysts Neel Mitra, Brad Olsen and Matt Portillo.
Several proposed CCGT plants are on the drawing board in the PJM Interconnection regional transmission grid (RTO), which includes Marcellus-rich Pennsylvania and West Virginia, and Utica/Marcellus-rich Ohio. PJM is the nation’s largest competitive wholesale electricity market with more than 650 companies, 60 million customers and about 167 GW of generating capacity.
Initially, TPH analysts wanted to see how the most recent PJM capacity auction, completed on Friday, would tilt toward natural gas. It went in a big way, with 95% of the new generation represented, according to the RTO. New CCGT plants with 5,914.5 megawatts (MW) MW of proposed capacity were bid, while 1,382.5 MW of combustion turbine capacity were bid. The auction saw a record amount of new generation for 2015/2016 procured totaling 4,900 MW out of 6,843.7 MW. Only aggregated new installations were offered, not the identities of specific plants.
“PJM is effectively, efficiently and reliably handling a massive shift in generation from coal to natural gas,” said PJM Senior Vice President of Markets Andy Ott. Six Ohio coal plants, he said, are being shuttered in response to environmental regulations and “cheap natural gas.” PJM reported in February that over the past two years almost 70% of new power generation plants proposed for the 13-state grid were to be gas-fired (see NGI, Feb. 18).
TPH analysts looked beyond the auction data to the Northeast’s overall gas supply data and midstream takeaway options to see how they might factor into gas utility development down the road. A total of 11 gigawatts (GW) of new CCGT capacity has been publicly announced for Pennsylvania (7 GW) and Ohio (4 GW). Pennsylvania also has about 1.5 GW in coal-fired power coming offline by 2015, versus 4 GW in Ohio, according to the analysts.
On the face of it, the numbers don’t appear to add up to positives for the utility companies on the proposed generation versus the planned retirements, the analysts said. Even with coal plant retirements, PJM would appear to be moving to an oversupply. Expected demand growth, it would appear, is “uneconomic, yet several private developers see reason to build.” The answer, they found, “has less to do with power markets than access to cheap Marcellus gas.”
The developers appear to be banking on an “advantaged gas price, rather than power fundamentals,” because there’s going to be too much gas and not enough takeaway from the region, suppressing gas prices for a long time. Developers expect to procure gas at a “50-cent discount to Henry Hub and sell power into markets, where positive gas basis sets the price of power for at least five years,” said Mitra.
For instance, Marcellus power developers Moxie Energy LLC and EmberClear Corp. expect natural gas in the region to sell at a “substantial discount to Henry Hub for at the least the next five years,” primarily because of expanding output and limited near-term infrastructure solutions (see NGI, May 20). “At the same time, these plants are able to sell power into markets where premiums to Henry Hub set the price of power,” including Tetco M3, Transco Z6 and Algonquin City Gates.
The “gas procurement arbitrage” effectively would add 2% to a levered investment rate of return (IRR), or a $3.50/MWh spark spread advantage for every 50-cent discount to Henry Hub, according to TPH. “Assuming the discount to Henry Hub persists for five years and a $140 MW/d capacity price in PJM’s MACC area, developers can earn a 12-14% IRR without an improvement in forward power prices or capacity prices.” MACC includes most of Delaware, Maryland, New Jersey and eastern Pennsylvania. In the latest capacity auction, MACC prices hit $167.46/MW/d.
While they likely will be some power price appreciation in the PJM, analysts remain a bit cautious because several one-off opportunities are available to build generation at advantaged economics, but they may lower power prices (i.e., Pennsylvania); coal retirements are large in MW but low in TWh because of low capacity factors; and renewables such as wind have to be factored in, and they have the potential to lower power prices.
The Northeast generally has commanded a premium relative to Henry Hub because it has been long-demand and supply-short. However, with Marcellus output increasing from 1 Bcf/d in 2009 to an estimated 7 Bcf/d today, the “dynamics have changed, with premiums all but evaporating.” The region is on its way to becoming “seasonally oversupplied.”
The Marcellus gas will be trapped and cheap for years, which provides the power investments with “access to lower-cost gas, not increasing demand…We expect prices to be lowest around major supply hubs,” such as Susquehanna County, PA; southwestern Pennsylvania and northern West Virginia, “where pipes struggle to keep up with supply for years to come until major southbound and westbound pipes are constructed or reversed.”
The pipeliners now are focused on penetrating further into the North and East. “Major hubs will begin to feel pressure from pipes expansions in late 2013, but even after buildout, we expect meaningful discounts to persist in areas of growing supply.” Even when premiums decline in these markets, the northeastern and southwestern supply hubs in the Marcellus “must maintain wide discounts for years to come to incentivise further pipe construction to accommodate future supply growth.”
Those PJM coal plant retirements? They’ll only have a minimal impact, according to analysts. Between 2012 and 2016, more than 16 GW of coal plant capacity is being shuttered, with 11 GW from this year to 2016, but there won’t be a lot of power lost from the system. “Given low capacity factors for these plants (25-30%), we expect that this will drive a maximum of 0.8 Bcf/d of incremental gas demand if the generation is replaced with 10-times heat rate peakers. Said another way, seven new gas plants with 800 MW capacity running at 60% capacity factors would need to be built to offset the lost generation from retiring coal plants.”
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