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Northeast supply, capacity seen keeping summer natural gas prices mostly checked


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Northeast supply, capacity seen keeping summer natural gas prices mostly checked

Recent capacity additions from new pipeline projects in the Northeast are expected to alleviate some but not all of the price volatility for natural gas this summer cooling season.

Across the region, natural gas demand in the summer is expected to be lifted by regional electricity demand, which is being increasingly met by natural gas-fired generators.

In New England, natural gas fuels 44% of all of the region's installed capacity and accounts for 50% of all of the proposed new generating capacity for the region, according to ISO New England.

For New York, today, power plants using natural gas total 57% of the state's generating capability. New York's reliance on natural gas-fired capacity is expected to grow as power projects using natural gas account for 56% of all proposed generating capacity, the New York ISO said in its Annual Power Trends 2017 report.

New England has added 360 MW of new generating capacity since last summer, but it has also seen the retirement of Dynegy Inc.'s 446-MW oil steam turbine-powered Brayton Point 4 and coal-fired 1,083-MW Brayton Point 1-3 plants in Somerset, Mass., resulting in a net loss for New England generation of 835 MW on the year.

New York has seen the retirement of nearly 425 MW of generating capacity since summer 2016, but the state has added nearly 287 MW of generation.

During the summer of 2016, to feed natural gas-fired generators in order to answer consumer demand during the summer cooling season, 44.6 Bcf of natural gas was delivered as fuel to New York electric power plants in June, 59.6 Bcf of natural gas was delivered in July and 64.3 Bcf of natural gas was delivered in August.

In New England's high-demand Massachusetts market for the same June-through-August period, electric power plants saw deliveries of 17.6 Bcf, 21.4 Bcf and 21.4 Bcf, respectively, according to the U.S. Energy Information Administration.

Degree day data outlines the increase in cooling degree days that drove the strong demand.

Degree day data for the summer of 2016 shows that across New England there were 75 cooling degree days in June, nine more than the previous year and 12 more than normal for the month. In New York for the same month, there were 128 cooling degree days, which were 22 above the prior year and 21 more than normal for the state. In July, New England saw 256 cooling degree days, 52 more than the previous year and 76 more than normal, while New York saw 319 cooling degree days, 49 more than the prior year and 86 above the normal. August brought 290 cooling degree days in New England, 90 more than the prior year and 144 more than normal, while New York saw 327 cooling degree days, 87 above the prior year and 132 above normal.

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For the approaching summer of 2017, weather forecasts point to above-average temperatures across the majority of the country through the June-through-August period.

The Weather Channel's forecast for the three-month period shows the best chance for warmer-than-average temperatures this June will be from east Texas through much of the South and up the East Coast, as well as in the Pacific Northwest. In July, temperatures for the East will likely be near to slightly above average. The expanse of hotter-than-average temperatures will grow in August, stretching from the West Coast through the Southwest and into the South and up the Northeast seaboard, The Weather Channel said. Areas from southern California into southern Arizona, as well as from southeastern Louisiana into much of the Southeast, may see temperatures soar well above average.

Heat is expected to drive peak summer load on the New England power grid to 26,482 MW, while the NYISO expects a peak summer load of 33,178 MW, according to the Northeast Power Coordinating Council's reliability assessment for summer 2017, released April 28.

These figures are down from the previous year, with the declines attributed to demand reductions associated with energy efficiency, load management, behind-the-meter photovoltaic systems and distributed generation, the NPCC said.

Although natural gas-fired generating capacity stands at 38,581 MW in New York and 29,412 MW in New England, which is considered adequate to meet regional demand requirements, the regions are not free from risk this summer.

In fact, while the NYISO sees ample supply to meet peak load, the New England grid operator, when accounting for purchases, sales, required operating reserves and planned and unplanned power outages, sees operable capacity margins at negative 521 MW for the historical peak demand week in mid-July, according to the summer trends report. This shortfall could require the New England grid operator to take measures to maintain reliability, including importing natural gas from Canada.

Further, with the regional power generation fleet becoming highly reliant on natural gas, a lack of firm contract gas pipeline capacity leaves the regions, particularly New England, susceptible to price spikes during periods of peak demand, including during the summer season, the Northeast Gas Association said.

"The Northeast spot price volatility reflects delivery constraints during high-demand periods of intense cold (or even hot) weather," the NGA said.

While natural gas utility customers are generally protected from the daily impact of spot prices due to long-term contracts and storage, the power market in the Northeast operates with high levels of interruptible gas capacity subjecting it to spot market fluctuations, the NGA said.

Historically, hubs including Algonquin Citygate, Iroquois-Waddington, Leidy and Transco Zone 6 NY have been subject to significant price volatility during peak demand periods in the summer seasons, according to SNL data.

The shale gas revolution has helped to alleviate a great deal of the volatility with the region's proximity to the abundant supply from the Marcellus and Utica shale plays, and price peaks have been significantly reduced, but not eliminated. Summer peak values have continued to pull above the benchmark Henry Hub price in areas that remain susceptible to pipeline constraints.

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Natural gas pipeline expansion projects that were completed in recent years may have reduced, but did not eliminate, sharp price increases with anticipated cold and hot weather, the EIA said.

Although there are longer-range concerns, for the 2017 summer capacity period, the New England ISO expects limited amounts of natural gas pipeline maintenance and construction to occur for select areas and does not forecast deliverability issues that would affect the installed capacity, according to the summer trends report.

The NYISO also anticipates adequate natural gas pipeline capacity.

The region however, could face a challenging supply situation as a result of fresh competition for Marcellus and Utica shale gas, particularly increased demand to the Southeast due to exports of liquified natural gas as well as coal-plant retirements that have increased regional reliance on natural gas-fired generation.

EIA data shows the rising demand for natural gas from the power-generating sector in Southeast states. In 2016, Virginia, the Carolinas, Georgia and Florida each saw summer demand reach their highest ever levels for the majority of the summer months of June, July and August.

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More than 32 GW of gas-fired power generation units are planned to be added in the South-Atlantic states by 2020 and LNG exports from the Southeast are increasing. Of the 15.5 Bcf/d of takeaway capacity planned for Appalachia, close to 5 Bcf/d is targeting this growing demand, RBN Energy analyst Sheetal Nasta said in a May 21 blog.

Market prices and included industry data are current as of the time of publication and are subject to change. For more detailed market data, including power and natural gas index prices, as well as forwards and futures, visit our Commodities pages.