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With summer coal demand pending, exports continue to drive pricing


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With summer coal demand pending, exports continue to drive pricing

Coal prices for export markers surged during June, building on May gains. This contrasted to domestic markers, which traded flat or declined. Natural gas prices moved steadily higher during the month as inventories remained low and markets anticipated summer generation demand.

High-quality bituminous coal made strong gains to the end of June, on continuing strength in seaborne markets, while domestic markers remained mostly unchanged. Physical CAPP 12,500 Btu/lb benchmarks increased more than $3/ton, or 6.2%, while NYMEX CAPP remained flat. NAPP Pittsburgh Seam 13,000 Btu/lb gained nearly $3/ton, or 6.2%, as well. Illinois Basin markers were unchanged on the month, and the NYMEX Powder River Basin benchmark eased an additional 5 cents/ton on weak demand.

Natural gas pushed higher during June, with storage injections again failing to reduce the storage deficit. Henry Hub spot prices opened the month with an 11-cent jump to $2.94/MMBtu and broke the $3 level by midmonth, before settling at $2.99/MMBtu on June 29th.

As in May, storage injections were roughly equal to historical averages, leaving the storage deficit as of June 22 essentially unchanged at 502 Bcf. Part of the month's price rally is attributable to the ongoing storage deficit, although prices are similar to this time last year, when there was 684 Bcf more natural gas in storage. Moreover, the expansion of natural gas supply out of the Permian Basin and continued penetration of shale gas into the Midwest means that most of the country now prices at a discount to Henry Hub, in contrast to 2017. These discounts narrowed during June compared to May, with Chicago 15 cents below Henry Hub and SoCal Border discounted by 25 cents, to go along with much lower natural gas prices in the Marcellus Shale and Permian Basin. S&P Global Market intelligence expects that the expansion of discounted natural gas to regions beyond the Marcellus will pressure domestic coal demand and restrain coal price growth.

Coal inventories grew modestly in April, with the U.S. Energy Information Administration estimating stockpiles at 129 million tons. S&P Global Market Intelligence estimates normal year-end stockpiles at 152 million tons, suggesting ongoing demand pressure to rebuild inventories, independent of natural gas competition.

The chart below shows the current price forecast for the PRB 8800 and 8400 markers.

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Pricing for the PRB is expected to be driven by domestic demand dynamics, with coal retirements and competitive natural gas restraining demand and prices. Flat pricing is expected in the near-term as higher demand from export markets is more than offset by these domestic factors. While long-haul PRB is resilient to gas generation priced from $2.85/MMBtu to $3.00/MMBtu, the current strip for natural gas and associated regional prices trends lower through 2019 putting a hard cap on coal demand. Combined with retirements of Midwestern PRB-burning plants, this creates surplus capacity in the PRB, tending to reinforce current price levels over the next few years.

The need to refill coal stockpiles may support bituminous markets through 2018, along with continuing firm seaborne markets. While seaborne prices eased in April, export volumes have held strong, allowing prices to build in May-June.

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The above chart forecasts flat pricing across all bituminous coal types, as pricing pressure from natural gas builds into 2019, with modest price growth thereafter as natural gas prices again move up. As with the PRB, ongoing low natural gas prices creates a ceiling for coal prices, restricting price growth. S&P Global Market Intelligence projects that the combination of natural gas prices and coal retirements will pressure generation demand through 2021, with overall demand falling by 185 million tons from 2017-2021.

Coal production and demand

For the four weeks ending June 23, coal shipments averaged 14.4 million tons, with volumes growing as shoulder season ends and some regions experience early summertime demand. Exports appear to have sustained eastern volumes in particular. Production levels in eastern bituminous regions — Central, Northern, and Southern Appalachia are forecast lower from 2017 by 6% in 2018. An easing of metallurgical export markets combined with lower domestic steam demand drive this modest decline. Southern PRB is projected essentially flat, with stronger exports offset by lower coal demand from retired capacity and competition from natural gas. Illinois Basin is expected to grow production 5%, due to higher steam coal exports.

The chart below compares the current production forecast with recent history. Electric sector demand is projected to decline from 675 million tons in 2017 to 598 million tons in 2018, and to come under further pressure in 2019. A surge in announced coal retirements over the next four years combined with lower natural gas prices is projected to push coal generation demand to a low point of 487 million tons per year by 2022. Last year's boost in demand will be tested, with the overall coal market (domestic demand and exports) projected to decline by 163 million tons from 2017-2021.

Production outlook — Powder River Basin

Inventories of subbituminous coal at generators started to rebuild in March, providing some demand to offset low natural gas prices. As coal plant demand in Texas rolls off due to deactivation, demand is expected to decline by about 3 million tons during the second quarter, with another 3 million tons of displaced demand due to competitive natural gas. Exports and re-stocking are projected to offset these losses; S&P Global Market Intelligence projects modestly higher production in the PRB compared to 2017, with total PRB production (Northern and Southern) projected at 341 million tons. Exports remained firm through March. However retirement of coal generation in the Midwest and Texas, along with lower natural gas prices, is projected to shrink the market through 2021. Modest growth opportunities include displacement of smaller western coal producers, along with further expansion in export markets. Overall, PRB is forecast to increase production by 4 million tons in 2018, before losing 66 million tons in 2019.

Production outlook — Illinois Basin

Increased availability of Marcellus/Utica shale natural gas into the Midwest has maintained downward pressure on spot coal prices, and has cut into domestic demand for ILB coal. This demand pressure has been offset by export volumes, keeping overall production levels stable. S&P Global Market Intelligence forecasts 2018 ILB production at 107 million tons, nearly 4% higher than 2017. Export markets are helping to drive this modest growth, although recent seaborne prices have been weaker for lower-quality coal. As in other coal regions, natural gas prices are expected to move further downward by 2019, with shale gas deliverability into the Midwest driving Illinois Basin coal volumes down modestly. With low natural gas prices persisting beyond 2018, Illinois Basin production is projected fall below 100 million tons per year, and remain relatively flat thereafter.

Production outlook — Appalachian basins

Appalachian basin coal production has increasingly shifted to metallurgical and export steam markets, with long-haul thermal domestic markets continuing to erode. Going into the third quarter, there are no scheduled coal retirements, and higher natural gas prices should ease displacement. Overall though, production levels in 2018-2019 are projected to decline by 18 million tons and 8 million tons respectively due to lower natural gas prices, intra-basin competition with the Illinois Basin, and further coal retirements in the region. The growth in 2017 metallurgical exports is forecast to hold firm in 2018, before easing by 2019 as competition from international producers cuts U.S. volumes.

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Coal forecast methodology overview

Market-indicative coal forecasts produced by S&P Global Market Intelligence represent forward curves for spot-traded instruments, analogous to a strip of contracts, with the shorter tenors (current year, prompt year, plus additional years if available) driven by the observed/assessed market and the longer tenors (typically years three-20 for physically assessed markers and NYMEX futures) driven by fundamental estimates of cash costs of production, accepted returns to capital, regional productive capacity, and forecast supply and demand. For the long-tenored portion of the curve, S&P Global Market Intelligence forecasts prices for specific coal markers, and defines the remaining markers via historical spreads.