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Coal production opens 2017 on firmer footing, but natural gas competition awaits

With natural gas priced well over $3/MMBtu during January, coal demand remained firm during the month, providing a solid start to 2017. Weekly shipments remained below those of November 2016 on lighter heating demand, but well above the same time last year. Seaborne coking coal prices remain high, and spreads to seaborne thermal coal appeared high enough to support exports for at least the first quarter of 2017. With modest headroom from natural gas, the NYMEX CAPP prompt-month benchmark gained $1.00/ton, or 1.8%, to end January, while the NYMEX PRB gained $0.25/ton, or 2.1%. Physical marker prices made modest gains as spot buying activity remained steady. Among the largest gainers, CAPP 12,500 markers added $2.00/ton, or 4.0%, ILB physical markers gained $0.50/ton, or 1.4%, and PRB physical added $0.80/ton, or 7.3%.

The mid-December 2016 cold spell that eliminated the surplus in natural gas storage gave way to milder weather that blunted upward movement in prices. After opening the month at $3.74/MMBtu, Henry Hub spot prices dropped quickly, moving to a mid-month low of $3.14/MMBtu before closing the month at $3.31/MMBtu. The storage deficit to the five-year average as of Jan. 20 stood at 20 Bcf, essentially at normal levels. While natural gas prices are currently easing, bouts of winter weather will have more upside impact with no storage surplus to buffer supply.

Similarly, coal inventories are also closer to normal. Coal inventories to end September 2016 have been estimated at 159 million tons, approximately 5% above normal levels. Recent higher pricing for natural gas and the prospect of improved heating season demand could reduce inventories by an additional 4 million tons to end January and bring coal stockpiles to normal levels by March. This will improve spot market activity and bring further support to coal prices.

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

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The Powder River Basin has been the most vulnerable to losing volumes to gas switching over the last two years. Penetration of competitive shale gas into the Midwest has further increased the risk of displacement by gas. However, PRB demand can also recover rapidly when spreads to natural gas are favorable, as they have been since the summer of 2016. On a forward basis, the current strip for natural gas is lower than current prices through 2018, keeping a lid on PRB 8800 price levels at just over $12/ton. PRB may have used much of its pricing "headroom" against the natural gas strip, after factoring in transport costs to plants in Texas and the Midwest. Looking further out, coal retirements in the West and Midwest are projected to limit pricing and demand growth past 2018.

Higher natural gas prices at Henry Hub, along with tightening regional-basis relationships in the Northeast shale regions have supported higher bituminous demand through this winter, at least compared to the 2015-2016 winter. Shipments to mid-January indicate continued support, reflecting higher international and domestic demand. The pricing rally in coal has slowed somewhat, potentially indicating that natural gas and coal are back in close competition, with interdependent price/demand affecting both fuels. This is expected to bring Central Appalachian pricing back into line with bituminous markers in Northern Appalachia and Illinois Basin, with sustainable pricing expected in 2018. Price growth beyond 2018 will be limited by more competitive natural gas, intrabasin competition and flat-to-declining steam generation demand through 2021.

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The above chart shows the expected easing of import-driven pricing impacting bituminous markets through 2017, with the physical NAPP and ILB markers seeing price growth in 2017. S&P Global Market Intelligence projects that electric generation demand will come under pressure in 2019, with net demand falling by 22 million tons from 2016 through 2021. This is forecast to be offset by modest growth in export demand of 6 million tons over the same period.

Coal production and demand

For the four weeks that ended Jan. 21, coal shipments averaged 14.7 million tons, counting weekly totals that are typically lower due to the holiday period. Shipments have solid momentum for the first quarter of 2017, although expectations of a milder February may present downside risk to shipments. With inventories at normal levels and firmer natural gas prices in place than last winter, the market is poised for significant production gains and incremental market activity in 2017. The CAPP and NAPP regions are projected to gain a modest 3 million tons of annual production in 2017 from 2016 levels, as improved demand offsets organic production declines. Southern PRB's market is expected to rebound by 47 million tons this year on restored price competitiveness.

The chart below compares the current production forecast with recent history. Electric-sector demand is projected to grow from 653 million tons in 2016 to 688 million tons in 2017, before moderating after 2018. Lower natural gas prices combined with additional coal retirements will tend to keep coal generation demand levels at or below 640 million tons per year through 2023. Accounting for the expected recovery in production and restoration of normal inventories in 2017, the overall coal market (domestic demand and exports) is projected to be essentially flat, at 19 million tons higher in 2023 than in 2016.

Production outlook Powder River Basin

S&P Global Market Intelligence projects 47 million tons of new production in the Powder River Basin compared to 2016, with surplus coal inventories mostly gone by the end of the first quarter of 2017. Normal inventories and firmer natural gas pricing set the stage for improved demand and corresponding production of coal to rebound in 2017. Powder River Basin 2017 production (Northern and Southern) is projected at 358 million tons, 15% higher than 2016. Demand levels for non-PRB western and interior (Texas and Upper Midwest lignite) coal have held firm, limiting growth opportunities for PRB mines.

Production outlook Illinois Basin

Increased availability of Marcellus/Utica shale natural gas into the Midwest is likely to become a more entrenched feature in the years ahead, creating similar conditions to those now faced by coal generators in Appalachian regions. But high natural gas prices to open 2017 should provide relief for tons displaced in 2016. S&P Global Market Intelligence forecasts 2017 ILB production at 119 million tons, 19 million tons higher than 2016. Coal and natural gas prices are expected to realign by 2019, with shale gas deliverability into the Midwest tending to limit further market growth. Growth in Illinois Basin volumes post-2018 will depend principally on displacing Appalachian coal and on export market growth.

Production outlook Appalachian basins

Growth in natural gas takeaway capacity from the Appalachian shale regions is beginning to support higher regional natural gas prices, although significant discounts to Henry Hub prices remain. Much of Appalachian basin coal production has been reduced to core metallurgical, local steam and export steam markets. S&P Global Market Intelligence expects that 2017 production will total 178 million tons, slightly higher than 2016 levels. Reverse-switching due to higher natural gas prices in 2017 is expected to be offset by slightly lower metallurgical exports. By the end of 2018, resumption of natural gas competition is expected to drive 2019 production down to 169 million tons. Metallurgical coal production has generally been firmer than production for domestic steam markets, maintaining a core market of approximately 50 million tons per year. This market could see a boost if increased Chinese imports of metallurgical coal seen over the last six months drives European shippers back to U.S. producers.

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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 3 to 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.