By David Middleton – Re-Blogged From http://www.WattsUpWithThat.com
Over the past 10 months or so, articles like this have been a “dime-a-dozen”…
Coal plants keep closing on Trump’s watch
Benjamin Storrow, E&E News reporter
Climatewire: Tuesday, February 21, 2017
In the next four years, utilities have plans to close 40 coal units, federal figures show. Six closures have been announced since Trump’s victory in November.
Any guesses as to why this is irrelevant?
Here’s a hint:
AUG 6, 2017
Nine Natural Gas Facts That You Should Know
Jude Clemente , CONTRIBUTOR
I cover oil, gas, power, LNG markets, linking to human development
Natural gas is now our main source of electricity, and thanks to the shale production revolution prices collapsed from $8.86 per MMBtu in 2008 to just $2.52 in 2016. Prompt month September prices are now below $2.80, a shoulder month and blue weather maps for the next two weeks mean a bearish market. So far this summer, although hotter on the low demand Western coast, we simply haven’t had a prolonged heatwave to increase prices.
Gas is not just cleaner but also has unmatched versatility: no single sector accounts for more than 35% of all gas usage – utilized in electricity, industry, heating, transportation, and more. Gas is the most interesting and talked about major fuel market these days and in future, so continually arm yourself with some gas knowledge:
1. FERC now finally has quorum for the first time since early-February, and with a huge backlog of unapproved pipeline projects at least 6 Bcf/d of new takeaway capacity projects are scheduled to come online throughout the critical Appalachian Basin between now and the end of First Quarter, 2018. Although don’t expect significant volumes flowing through the troubled Rover pipeline until next year – a 3.25 Bcf/d line carrying PA and OH shale gas into eastern Michigan and up into Dawn Hub in Ontario.
2. From 2016-2018, U.S. piped gas export capacity to Mexico will double to nearly 15 Bcf/d. The country now takes about 4.2 Bcf/d from the U.S. and needs more U.S. supply because gas is 60% of Mexico’s electricity and domestic production is rapidly dropping. But, bear in mind that the 2013 Energy Reforms have been progressing and upstream auctions for more foreign investment have been successful. Mexico’s de-regulation is about producing more, not importing more from the U.S, with a $640 billion investment required (here).
3. By 2020, more than 150 new natural gas power plants are scheduled to come online in the U.S., concentrated in or around our shale basins. There’s at least 90,000 MW of new gas generation currently in development, 70% of which is located in the PJM and ERCOT regions. This represents nearly a 20% expansion of our gas capacity, as gas is surging toward being 50% of all U.S. power capacity – given coal and nuclear retirements and the requirement to back up wind and solar.
4. We’ve been lucky: we had the warmest winter ever in 2015-2016, and 2017 has brought the warmest February ever. Let’s be clear: a normal cold winter could bring $4 or even $5 natural gas. This is especially true since low injections in the past month (a 20 Bcf gain reported last week) should equal just 3.7 or 3.8 Tcf in gas storage to start the winter withdrawal season in November. This would be below average and well below the more than 4 Tcf we had last year. As a declining surplus, inventories are now 9% below last year’s level and just 3% above the five-year average for this time of the year. To reach 4 Tcf, the average weekly injection over the next 15 weeks until the heating season will need to average a very unlikely 66 Bcf.
5. As likely our most vital incremental gas producing state, Pennsylvania’s GOP-controlled Senate has passed a volumetric fee on production designed to generate an estimated $100 million annually. This severance tax will be a very tough sell in the House, where Republicans have a strong majority. PA’s Commonwealth Foundation details the full proposal on its website. Make no mistake: anything that disrupts PA gas production impacts ALL natural gas users around the world. The Marcellus is probably the world’s largest gas field and now produces nearly 20 Bcf/d of gas – more than double the second place Permian in the U.S.
- U.S. natural gas exports are rapidly rising.
- 90 GW of natural gas-fired power plants are scheduled to come online by 2020.
- One normally cold winter could send natural gas prices up to $4-5/mmbtu.
- The Marcellus is fracking HUGE.
What does any of this have to do with coal?
Natural gas prices have been the driving factor in the utilization rate of coal-fired power plants since at least 2009.
From 1997-1999, the spot price (Henry Hub) for natural gas averaged $2.28/mmbtu. In 2002-2003, there was a surge in construction of natural gas-fired power plants.
From 2003-2008, natural gas prices averaged $7.10/mmbtu and very few natural gas-fired power plants were built. Recently low natural gas prices appear to be fueling another surge in gas-fired power plant construction.
JANUARY 30, 2017
Source: U.S. Energy Information Administration, Electric Power Annual and Preliminary Monthly Electric Generator Inventory
The electricity industry is planning to increase natural gas-fired generating capacity by 11.2 gigawatts (GW) in 2017 and 25.4 GW in 2018, based on information reported to EIA. If these plants come online as planned, annual net additions in natural gas capacity would be at their highest levels since 2005. On a combined basis, these 2017–18 additions would increase natural gas capacity by 8% from the capacity existing at the end of 2016. Depending on the timing and utilization of these plants, the new additions could help natural gas maintain its status as the primary energy source for power generation, even if natural gas prices rise moderately.
The upcoming expansion of natural gas-fired electricity generating capacity follows five years of net reductions of total coal-fired electricity generating capacity. Available coal-fired capacity fell by an estimated 47.2 GW between the end of 2011 and the end of 2016, equivalent to a 15% reduction in the coal fleet over the five-year period.
The electricity industry has been retiring some coal-fired generators and converting others to run on natural gas in response to the implementation of environmental regulations and to the sustained low cost of natural gas. The cost of natural gas delivered to power generators fell from an average price of $5.00 per million Btu (MMBtu) in 2014 to $3.23/MMBtu in 2015 and averaged $2.78/MMBtu from January through October 2016, the latest available data.
Expanded production from shale formations is one of the main reasons that natural gas prices have remained low in recent years. Many of the natural gas-fired power plants currently under construction are located in Mid-Atlantic states and Texas, where the nation’s major natural gas shale plays are located. Expanding natural gas pipeline networks also help support the growth in natural gas-fired electric generating capacity.
Based on projections in EIA’s January 2017 Short-Term Energy Outlook (STEO), natural gas prices are expected to increase in both 2017 and 2018. Rising natural gas prices could lead developers to postpone or cancel some of the upcoming power plant additions. Construction timelines for these plants are relatively short: more than half of the natural gas-fired generating capacity scheduled to come online in 2017 and 2018 was not yet under construction as of October 2016.
While the construction of new and decommissioning of old power plants plays a role in the generating mix, a more significant factor is utilization rate.
Source: U.S. Energy Information Administration, Electric Power Monthly
Last year marked the first time on record that the average capacity factor of natural gas combined-cycle plants exceeded that of coal steam plants. The power industry has been running natural gas combined-cycle generating units at much higher rates than just 10 years ago, while the utilization of the capacity at coal steam power plants has declined. The capacity factor of the U.S. natural gas combined-cycle fleet averaged 56% in 2015, compared with 55% for coal steam power plants.
The mix of energy sources used in U.S. electricity generation has changed dramatically over the past few years. This change is particularly evident in the shift from the use of coal to natural gas for power generation. The industry has been building new natural gas capacity and retiring coal plants, but another important factor behind the changing generation mix is the day-to-day pattern of how existing power plants are used.
Coal power plants primarily rely on steam-driven generating units. In contrast, power plants fueled by natural gas rely on a variety of technologies. Natural gas-fired generating units driven by combustion turbines or steam turbines accounted for about 28% and 17%, respectively, of total natural gas-fired capacity in 2015. Combined-cycle plants, which are designed as an efficient hybrid of the other two technologies, accounted for 53% of gas-fired generation capacity and tend to be used more often than the other types of natural gas generators, as measured by capacity factors.
Capacity factors describe how intensively a particular generating unit or a fleet of generators is run. For instance, a capacity factor near 100% means that the unit is operating almost all the time at a rate close to its maximum possible output.
When natural gas prices exceeded coal prices by a large margin, as was typically the case over the 2005-08 period, electricity systems where both natural gas-fired combined-cycle and coal-fired power plants were available to serve load would typically run combined-cycle units only after making maximum use of available coal-fired generation. As natural gas prices have declined, power plant operators have found it more economical to run combined-cycle units at higher levels.
The capacity factor of the U.S. natural gas combined-cycle fleet has risen steadily from an average of 35% in 2005 to more than 56% in 2015. Although there is a wide variation of capacity factors for natural gas combined-cycle power plants, many of these units operated in the 50%-80% range in 2015. In 2005, combined-cycle units commonly operated at capacity factors lower than 30%.
The utilization rate of coal-fired plants is very sensitive to natural gas prices.
Here is a plot of the coal utilization rate with natural gas spot prices overlaid:
Coal-fired utilization rates correlate fairly well with natural gas prices (R² = 0.4396 (2005-2015), R² = 0.7232 (2009-2015).
Here’s the plot for 2005-2015:
Under the EIA’s reference case with no clean power plan, they forecast that US coal-fired generating capacity will decline from 274 to 217 GW between now and 2050.
Here’s what happens when I combine the coal-fired utilization rate (calculated from projected natural gas prices) and the EIA’s generation capacity forecast:
The above projections are based on the US EIA’s fairly conservative estimates of future natural gas prices and current forecast of coal-fired power plant closures with no regulatory relief other than the cancellation of Obama’s Clean Power Plan. If coal utilization rates rise back to 65-70%, the rate of plant closures will very likely slow down.
The Wild Card
What happens if the Marcellus goes south?
The Marcellus/Utica is fracking huge. But, like all oil & gas plays, it will peak and enter a decline phase. If that decline is sharp, like the Haynesville, gas prices could rise more quickly than expected. What happens to coal-fired utilization rates if natural gas spikes to $10-15/mmbtu for a protracted period of time? The coal-fired utilization rate would climb to 69-75%.
|Natural Gas ($/mmbtu)||Coal Power Plant Utilization Rate|
A rise to a 70-75% utilization rate by 2050 would lead to more coal-fired generation, relative to 2015, despite the decline in capacity from 274 to 217 GW.
I don’t expect that the Marcellus/Utica will start its decline any time soon. The IEA forecasts that Marcellus production will continue to rise through at least 2022… But no one’s crystal ball is perfect.
However, coal-fired power plants will very likely return to 60-65% utilization rates as natural gas prices modestly rise over the next few years and decades. Both coal and natural gas are currently operating at utilization rates that allow for significant increase in output without capacity additions.