Coal2Gas0213 Pro

Prospects for coal-to-gas switching in 2013Jesse Gilbert, Analyst Energy Markets

FEbruAry 2013

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Prospects for coal-to-gas switching in 2013

Dispatch competition between u.S. coal and natural gas plants has been a prominent feature of power markets since 2009. The industry witnessed high coal-to-gas switching levels in 2012 proving the market’s ability to offset oversupplied gas markets through incremental power-driven gas demand, albeit with natural gas prices dropping to levels not seen in a decade. The natural gas market has tightened since early 2012 working to take pressure off of coal plants particularly in Western and Midwestern markets. Natural gas prices, however, remain within ranges conducive to some economic switching, particularly in Eastern markets. SNL Energy explores coal and natural gas market fundamentals to estimate potential displacement for 2013.

Natural gas market environmentCoal-to-gas switching is particularly sensitive to natural gas market prices which exhibit significant volatility, as well as seasonality and regional variations. unlike coal which is typically delivered under long-term contracts, natural gas is largely procured through spot purchases or contracts indexed to spot prices. For these reasons, the environment for coal-to gas-switching can evolve rapidly with changing market conditions. Further complicating the switching analysis is the impact that switching itself has on gas market prices which creates feedback effects.

Figure 1 - Henry Hub spot prices

Natural gas prices began to fall in 2011 after the summer heat subsided, a trend which strengthened in the winter and spring months of 2012 as unseasonably mild weather set in across much of the country. Prices at the Henry Hub broke a key support of $2.00/MMbtu in early April dropping to as low as $1.85/MMbtu.

The natural gas storage surplus over the 5-year average peaked at over 900 bcf at the end of March prompting fears by some in the industry that a storage breach was possible by the end of the injection season. However, power markets reacted strongly to the record-low natural gas prices prompting a move toward market rebalance with gas storage levels dropping to just 168 bcf over the 5-year average at the end of November. The last week of November saw natural gas prices briefly top $3.70/MMbtu before falling on mild early-winter weather.

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Figure 2 -Natural gas storage vs. 5-year max, min, avg and prior year levelsSource: EIA

Since November, natural gas prices have seesawed in the low-to-mid $3 range lacking clear direction in the face of mixed weather signals. Gas storage surpluses climbed back up to 413 bcf in the third week of December falling slightly to remain at roughly 320 bcf for most of January. As we enter the second half of the gas heating season, the potential for significant weather-driven drawdowns of the current gas surplus are becoming less likely, opening up the potential for a modest drop in gas prices to encourage incremental switching.

The 2013 Henry Hub forward strip has seen some weakening since the fall when it reached $3.94/MMbtu on October 1. The 2013 strip as of December 27, 2012, which is used in SNL Energy’s base case, dropped to $3.58/MMbtu with monthly prices ranging from a low of $3.35/MMbtu for January to $3.98/MMbtu in December.

Figure 3 - NYMEX Henry Hub forward curve

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The level of natural gas production from shale regions as well as associated gas from oil drilling continues to underscore the breakdown of the traditional rig count to production relationship. Total rig counts (oil and gas) peaked at 2,026 in November 2011 but have fallen to 1,763 as of the end of December 2012. Much steeper declines in rig counts have come from gas-directed rigs which totaled over 900 in November of 2011 but dropped to 431 in the last week of 2012. Over the same period, oil-directed rigs have increased by over 200. Despite the large drop in gas rigs, natural gas production has proven resilient and has yet to see significant declines as the result of the drop in rig counts. According to the EIA, in December, total marketed natural gas production was just over 70 bcf/d. This looks to remain strong in 2013 with the EIA projecting natural gas production to average 69.8 bcf/d in 2013, up from 69.2 bcf/d in 2012.

Figure 4 - Marketed gas production versus Baker Hughes rig counts Source: Baker Hughes Inc. and EIA

With production remaining at elevated levels in 2013, gas markets will again be pressured to find demand. With its greater relative short-term price elasticity, power-sector gas demand remains an important balancing force to keep gas surplus levels in check in 2013, though not to the degree that was seen in 2012. EIA projections show natural gas consumption from the commercial and residential sector growing 2.31 bcf/d year over year in 2013 while industrial demand grows by .14 bcf/d stemming from a return to closer-to-normal weather and a strengthening economy. The increased consumption from other sectors should alleviate some of the need for coal-to-gas switching in 2013 but this effect may be balanced to some degree by lower weather-related power-sector gas demand compared to 2012.

Coal market environment2012 was a tumultuous year for coal markets marked by steep production cuts and a number of coal-company bankruptcies. A November, 2012 analysis by SNL found that nearly a dozen companies, primarily small Appalachian producers, had filed for protection from creditors in 2012, a list which included publicly traded coal producer Patriot Coal Corp. Persistently low natural gas prices in 2012 led to a double blow of weak pricing and low volumes for coal producers and analysts expect 2013 to remain a difficult year.

Coal market prices fell sharply in the spring of 2012 as natural gas prices dropped to 10-year lows. While coal prices generally bottomed out from the lows of the spring in June of 2012, recovery has been slow and held in check by

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stubborn gas surpluses that have persisted into 2013 thus far. Physical market prompt-quarter prices for Central Appalachia 12,500-btu coal have fallen 13% off of 2011 levels to $2.72/MMbtu as of Jan. 25, 2013. Northern Appalachia 13,000-btu coal prices have fallen nearly 19% over the same time period reaching $2.39/MMbtu as of Jan. 25. Powder river basin 8,800-btu coal has seen the sharpest drop off of 2011 levels at 27% sitting at just $.58/MMbtu near the end of January while prices for Illinois basin rail 11,800-btu coal are down 8% from prior-year levels.

Figure 5: US physical market prompt quarter coal prices ($/MMBtu)

Looking forward to the rest of the year, coal market prices will likely remain pressured with only modest recovery. The Central Appalachia NyMEX benchmark looks to climb 16% over the course of the year based on the forward curve as of Dec. 31, 2012. The NyMEX Prb spec looks to rise nearly 8% in 2013 while pricing for Northern Appalachian, Illinois basin, and rockies coal are expected to recover more slowly throughout 2013 as spot volumes begin to pick up.

Figure 6 - SNL Energy coal forecast for CAPP, NAPP and ILB (12/31/2012)

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Figure 7 - PRB forward prices (12/31/2012)

Despite the pronounced drop in coal market prices, the cost of coal as delivered to power plants in 2012 largely remained above 2011 levels. Delivered prices have felt pressure from rising transportation costs which comprise a significant portion of the total costs for generators. A prior analysis by SNL Energy showed that transport costs comprised 37% of total delivered costs overall in the first quarter of 2012, but this percentage was as high as 57% for Prb coal. Coal transportation costs were 17% higher in the third quarter of 2012 compared to 2011 levels according to the latest data from SNL Energy’s proprietary coal transportation cost estimates. These costs look to remain high in 2013 as lower diesel costs are offset by an increase in rail cost adjustment factors.

Figure 8 - Delivered coal costs to U.S. power plants

Coal plant costsTo determine at what point coal plants might be economically displaceable in 2013, SNL Energy mapped each non-cogenerating coal plant in the u.S. to one of 18 different coal spot markers where possible. Each of the coal markers

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ties to a coal spec covered in SNL Energy’s new proprietary coal forecast. Secondary coal sources at each plant were also accounted for where applicable. Estimates for transport costs of each coal spec assigned to the plant were also included based on SNL Energy’s transportation costs estimates.

In addition to fuel costs, other components of variable O&M were also included based on reported values and estimates by SNL Energy. Total variable costs for each plant were calculated and efficiency adjusted based on the heat rate of the plant compared to a typical 7,500 btu/kWh CCGT plant.

Figure 9 below shows the cumulative bcf/d gas equivalent switching potential if all coal plants with costs higher than the specified level were able to be displaced by CCGT plants and were operating at 2011 utilization rates in the base year. This can be thought of as the completely unconstrained coal-to-gas switching potential which could occur if dispatch decisions were made purely on current spot prices and available CCGT capacity was sufficient to cover all displaced coal in every hour. This should not be thought of as true switching potential, but rather as a gauge for the trigger points at which switching might be possible.

Figure 9 - Implied maximum call on gas from coal displacement vs. gas equivalent variable cost

At the bottom of the stack are plants primarily burning Prb coal which would generally require natural gas fuel costs below $3.00/MMbtu before switching potential begins to be realized, and costs below $2.50/MMbtu before significant volumes are displaced. Illinois basin coal falls next in the stack with some limited switching possible above $3.00/MMbtu for the most inefficient plants and displaceable volumes growing below $3.00/MMbtu.

Plants burning Appalachian coal offer the most switching potential with nearly all capacity potentially displaceable at CCGT fuel costs below $2.70/MMbtu. At prices between $3.00/MMbtu and $3.50/MMbtu, switching potential begins to drop rapidly before falling off even more sharply at prices above $3.50/MMbtu. The possibility of economic displacement persists at prices above $4.00/MMbtu but loses significance at $5.00/MMbtu.

Discussion of results and implications for gas marketsSNL Energy used plant financial and operating information in a regional hourly dispatch model to estimate potential coal-to-gas switching in 2013 compared to a base year of 2011. In the model, some factors such as hourly load

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were held constant at 2011 values while coal and gas commodity costs were allowed to vary. For a more complete discussion of methodology, please see the model methodology section.

SNL Energy considered multiple scenarios based on variations in forward natural gas prices including a base case in which natural gas prices were taken from the NyMEX forward curve for various natural gas hubs as of Dec. 27, 2012. A low-gas case was also considered where prices represent a $.50/MMbtu drop in each month below the Dec. 27 forward curve as well as a high-gas scenario where prices rise $.50/MMbtu each month over the Dec. 27 forward curve.

SNL Energy’s analysis found continued switching potential in the first half of 2013 with results showing significant price sensitivity within natural gas price ranges considered. In the base case, maximum switching potential was found to be 2.83 bcf/d on average in the first half of 2013 but this falls to just .49 bcf/d in the second half of the year as natural gas prices draw nearer to the critical $4.00/MMbtu level. Average switching for the year would represent a nearly 2 bcf/d reversal on average compared to 2012 switching levels.

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Low gas case 2.83 4.04 1.64

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Figure 10 - Summary of gas results

under the low natural gas case, maximum switching potential was found to be 2.83 bcf/d on average for the year while in the high gas case switching reverses by .34 bcf/d on average relative to 2011 levels. under the high gas scenario switching remains positive at .77 bcf/d in the first half of the year before falling by 1.42 bcf/d on average in the second half of the year compared to 2011 levels.

Figure 11 below shows a regional breakdown of maximum switching potential under SNL’s base case. regions shown include ones with switching potential identified for 2013. based on the results shown, switching looks largely limited to Eastern markets in 2013 with some potential also identified in the MISO region. The PJM and the non-PJM VACAr NErC sub region lead all regions, each with an average maximum call on gas of .42 bcf/d resulting from displacement of coal generation. The SOu and CENTrL sub regions also continue to show switching potential in 2013 with .31 bcf/d and .14 bcf/d respectively of maximum incremental gas demand identified. In every region with the exception of VACAr, switching potential versus 2011 either reverses or falls to zero in the fourth quarter under SNL Energy’s base case.

Implied call on gas (Bcf/d)

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MISO 0.56 0.42 0.27 -0.15 0.27

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VACAR 0.65 0.42 0.37 0.26 0.42

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FL 0.38 0.18 0.04 -0.41 0.05

Total 3.07 2.59 1.81 -0.83 1.65

Figure 11 - Regional summary of gas results under base case

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In order to assess the environment for switching across a broader range of outcomes, SNL Energy also considered switching potential across a wider range of gas prices spanning from $1.00/MMbtu under and $1.50/MMbtu over the Dec. 27 forward curve for each month of 2013. Figure 12 below summarizes these findings and plots annual average maximum switching potential as a function of the average annual Henry Hub price associated with the various shifted natural gas forward curves. This represents a different approach to the switching problem which explores what natural gas prices might be in 2013 based on what amounts of switching are needed to balance the market. While figure 12 is useful for gaining insight into how annual average switching potential moves with a change in annual average price, it represents a simplified view which does not incorporate price-driven feedback effects and which holds coal market prices constant.

Figure 12 - Annual maximum switching potential versus average annual Henry Hub price

The chart shows positive incremental switching potential versus 2011 at prices below the $4.00/MMbtu mark. between the base case natural gas average of $3.58/MMbtu and $4.00/MMbtu, switching “demand” is particularly elastic and falls rapidly with an increase in price. To the downside of the base case, between $3.33/MMbtu and $3.58/MMbtu, incremental gas demand grows only modestly with drops in price. At prices below $3.33/MMbtu the price elasticity of switching demand grows at an increasing rate with only small price changes needed to encourage incremental demand.

The chart offers some insight into average natural gas price ranges that might be seen in 2013 based on incremental gas demand needed for market rebalance. The steep drop off in switching potential at average prices above $3.58/MMbtu, and the outright reversal at $4.00/MMbtu likely limits the upside for average gas prices to below $4.00/MMbtu under most reasonable assumptions. The curve would imply that there is a little more play to the downside. A $.25/MMbtu drop in price from the base case would elicit a modest 157 bcf of incremental gas demand for the year while a further $.25/MMbtu drop to an average price of $3.08/MMbtu would result in maximum incremental demand of 443 bcf for the year. Assuming a reasonably normal end to the winter heating season and a return to average conditions for the rest of the year, gas prices look unlikely to be pressured below the $3.00/MMbtu mark on average in 2013 putting gas price ranges somewhere between $3.00/MMbtu to $4.00/MMbtu on average for the year.

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Discussion of results and implications for coal marketsHourly dispatch models were also used to estimate implied drops in coal tonnage in 2013 resulting from coal-to gas-switching, and the distribution of lost volumes among coal basins.

Total calculated maximum coal displacement versus 2011 was found to be nearly 24 million tons in SNL Energy’s base case. The bulk of this would come from Central Appalachian coal which could see 13.7 million tons of lost volume followed by Northern Appalachia with nearly 5 million tons displaced. SNL Energy’s results show 3.8 million of lost tonnage from the Illinois basin with just over 1 million tons coming from the Powder river basin.

Figure 13 - 2013 displacement summary for coal

Maximum displaced coal tonnage could nearly double to 43.3 million tons in 2013 if natural gas prices drop $.50/MMbtu off of the base case natural gas forward curve. This could result in an incremental 4.8 million tons lost from NAPP, 5.8 million tons lost from the Illinois basin and 4.4 million tons from the Prb compared to the base case.

While maximum displacement amounts under SNL Energy’s base case are not trivial, they represent a marked improvement compared to prior estimates by SNL Energy for lost coal tonnage in 2012. A similar analysis conducted by SNL Energy in May 2012 estimated a maximum potential displacement of nearly 63 million tons of coal between April and December 2012 with even Prb coal under fire with an estimated potential loss of over 11 million tons.

Conclusions and key considerationsSNL Energy’s analysis did not consider several factors which may influence potential coal displacement including the state of coal contracts and inventories as well as transmission bottlenecks. The hourly dispatch model also did not incorporate minimum up and down times, ramp rates for coal units as well as economic incentives beyond the single-hour dispatch decision. SNL Energy’s estimates, therefore, represent a maximum level of displacement based on plant economics considered and may overstate potential due to restrictions limiting switching.

While coal inventories have come down from levels exceeding 200 million tons in the spring of 2012, stocks remain high particularly in the East and may provide some pushback for switching potential. This may also be met with some pickup in tonnage required to be taken as the result of contracts that were deferred in 2012.

Weather will be a key consideration in 2013, particularly in the second half of the heating season. Increases in gas surpluses beyond the 300 bcf level seen at the end of January may result in a drop in natural gas prices. Analysts

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have become increasingly concerned about this scenario as the chances for cold winter weather to draw down current surpluses are narrowing. This sentiment was reflected in the February 2013 NyMEX Henry Hub contract which fell by $.34/MMbtu in the final week of trading.

under SNL Energy’s base case switching in 2013 looks to remain largely an Eastern phenomenon with some pickup of incremental gas demand coming from MISO. This would result in a total maximum potential of 1.65 bcf/d on average. Switching is heavily skewed towards the first half of the year with incremental switching-driven gas demand reversing compared to 2011 on average in the fourth quarter. risk factors to the upside and downside remain for natural gas prices, with sentiment leaning towards the downside given the natural gas market’s inability to shed much off of surpluses at current prices so far this winter. In either case, the expected rise in natural gas demand from other sectors in 2013 should take pressure off of the gas generating fleet resulting in a firm reversal of coal-to-gas switching relative to 2012.

Figure 14 – Location of CCGT plants versus coal plants at greatest risk of displacement in 2013

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Location of CCGT plants compared with coal plants at greatest risk of displacement in 2013

Coal plants shown include those ranked lower in the dispatch stack than the average CCGT plant in the region for at least 3 months of 2013.As of Dec. 31, 2012Source SNL EnergyMap Credit: Whit Varner

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Model methodologyFor the January 2013 update to its coal-to-gas switching report, SNL Energy took a different approach to estimating switching potential than has been done in previous analyses. This new approach relied on regional hourly dispatch simulations for a forward-looking 2013 dispatch curve compared to simulations from a base year of 2011. This was done in order to estimate incremental gas demand from the combined cycle generating fleet between these two periods under a number of scenarios.

For both 2011 and 2013, hourly load was held constant at 2011 values while coal and natural gas prices were allowed to vary based on historical and forward-looking market prices. The makeup of the generating fleet was allowed to change in accordance with known unit retirements and new builds. Therefore, some of the switching identified may be permanent switching resulting from coal retirements as well as expanded potential due to growth in available CCGT capacity to displace coal volumes.

regions were defined based on ISO planning areas for plants falling within an ISO region, while plants falling outside of ISO regions were limited to dispatch within NErC sub regions. The generating stack was compared to regional load in each hour based on aggregated hourly data from FErC 714 filings.

The hourly dispatch model included a number of important features such as assignment of coal units to coal markers and gas units to regional gas hubs, as well as estimates of historical and forward-looking fuel transportation costs. Each generating unit was also assigned other variable operating costs based on reported values, SNL estimates and cost defaults. Heat rates for thermal units were modeled based on calculated values from the EIA-923 filing as well as CEMS data sets.

A number of other important features were also considered in the dispatch model including assignments of units to multiple regions where applicable based on SNL Energy’s regional power markets tools. Forced outage rates were considered for all plant technologies based on reported values from NErC while outage rates for nuclear units were based on seasonal patterns. Monthly shaping for wind and hydro generation was also included for regions based on historical patterns.

The hourly dispatch model did not include some important features for thermal units such as start-up costs, minimum up and down times, ramp rates and commitment decisions based on the economics over minimum up times instead of the single-hour dispatch decision. Modeling also did not include transmission constraints and wheeling costs across regions. As such, switching levels estimated represent maximum values and may exceed realized values.

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