National | Sweeping Transformation of U.S. Energy Markets
By Special Contributor, Andrew D. Weissman, Publisher, Energy Business Watch
The past few months we have seen a startling transformation of U.S. energy markets—in which the electricity, natural gas and coal markets have converged, driving prices for all three commodities to multi-year lows.
Prices for electricity and natural gas are not likely to remain at current levels indefinitely; a partial rebound is likely later this year. This is a particularly good time, therefore, to lock in prices for electricity and natural gas for the remainder of 2012 and 2013, if not longer.
On the other hand, the convergence of the electricity, natural gas and coal markets is likely to permanently change the way in which U.S. electricity and natural gas markets function and to ensure that prices remain favorable on a long-term basis.
What’s Changed?
By now, of course, the startling increases that have occurred in U.S. production of natural gas are near-universally recognized. These increases have been putting downward pressure on natural gas for more than three years.
During this period, for the natural gas market to balance, it was necessary for natural gas prices to fall sufficiently to drive the dispatch cost for natural gas-fired generation below the cost for the most expensive coal-fired generating units (most of which were located in SERC or PJM).
In 2010, the amount of coal displacement required to balance supply and demand was in the range of 1 ½ Bcf/day for much of the year. While natural gas production continued to grow in 2011, its summer was the hottest in U.S. history, and therefore served to absorb a significant portion of the additional natural gas flowing into the U.S. market.
Even with record weather-driven demand for natural-gas fired generation last summer, however, for the market to reach equilibrium, an additional 1 ½ to 2 Bcf/day of coal displacement was required for the first three quarters of last year, bringing total coal displacement to 3 to 3 ½ Bcf/day.
Until last fall, however, spot market prices for natural gas remained near $4.00/MMBtu. This was a low enough price to induce the 3 to 3 ½ Bcf/day of coal displacement required to balance the market, while keeping electricity prices high enough to cover the fixed costs for most natural gas and coal-fired generating units.
Natural Gas Cash Prices at Henry Hub
January 1 to November 15, 2011 
November 16, 2011 to May 15, 2012 
Since the fall of 2011, however, the natural gas and electricity markets have been on a wild ride. Between early September and mid-April, the NYMEX front-month Henry Hub natural gas futures contract fell by more than 50%, bottoming out at $1.907/MMBtu on April 19th.
Wholesale power prices and operating margins for natural gas and coal-fired plants have fallen in tandem. Over the past several months, on-peak prices in the mid-to-low $20/MWhr range have not been unusual, with spark spreads frequently dropping below $8.00/MWhr. Prices for Powder River Basin coal and some eastern coals also fell sharply.
Since then, electricity and natural gas prices have rebounded, and could remain above spring levels for much of the summer. However, unless this summer is again brutally hot or a major hurricane wipes out 100 Bcf or more of production, spot market prices for electricity and natural gas are likely to again come under pressure starting in late July or August, pulling futures prices back down. Later in the fall, the futures market is likely to shift gears and starting focusing on next winter. Even if cash market prices hit rock bottom levels before the injection season ends, futures could rise.
Late July or August, therefore, may be the last good opportunity to lock in the prices for electricity and natural gas that reflect the extreme current oversupply condition in the U.S. market.
While the second half of the summer may seem far off, it is just six to eight weeks away. Energy users who want to take advantage of this opportunity should re-examine their requirements immediately, and start the procurement process soon.
Major inflexion point in the development of the U.S. energy markets.
The abrupt decline in natural gas and electricity prices over the past several months is due in substantial part to a sudden surge in U.S. production of natural gas, which jumped an astounding 3.25 Bcf/day in a period of just 120 days from August through November—the largest leap ever in U.S. production within a four-month period.
This surge completely offsets the 3 to 3 ½ Bcf/day a day of price-induced coal displacement that results from natural gas falling to $4.00/MMBtu—requiring as much as 3.25 Bcf/day of additional coal displacement to balance supply and demand.
The impact of this surge was intensified, however, by the confluence of three other major developments:
- A federal Court of Appeals’ stay of EPA’s Cross-State Air Pollution Rule in late December, which took off the table a program that could have bolstered prices considerably this year;
- The end of a period of nearly two straight years of above-normal weather-driven demand;
- The warmest winter in U.S. history.
It is tempting to attribute this year’s plunge in prices to last winter’s extremely mild weather. To do so, however, would be to take a myopic view.
While the absence of heating demand last winter was literally off the charts, the above-normal weather-driven demand during the previous twelve months was nearly as great. If weather-driven demand for the period between November 1, 2010 and March 31, 2012 had been in the normal range, the amount of natural gas in storage at the end of the winter would still have been in the 2,400 Bcf range—more than three quarter of a Trillion Cubic Feet above the previous all-time high.
Need for record levels of coal displacement.
The past fifteen months have made it crystal clear that in a normal-weather scenario, if natural gas were priced higher than the equivalent price of coal (as it had been with only rare exceptions prior to March of 2009), the market would be vastly oversupplied.
To balance the market, therefore, prices have had to sink even further. Our estimates indicate that at $2.00/MMBtu, the total amount of price-induced coal displacement in the shoulder months is likely to be in the range of 6.00 – 6.25 Bcf/day—nearly twice last year’s average. (In the peak summer months, when many natural gas-fired combined-cycle units need to run at high capacity factors to meet summer load, even at prices near $2.00/MMBtu, the amount of price-induced coal displacement is likely to be significantly lower.)
It is unclear, however, whether this unprecedented market will be sufficient to avoid a storage availability squeeze this fall, which could send prices much lower during the last few months of the injection season.
Three factors will be critical: weather, U.S. production rates, and the extent of further declines in net pipeline and LNG imports into the U.S.
Weather as always, is a major wild card. Most forecasts for this summer predict that weather conditions will not be quite as hot as the records set last year, in part due to a developing El Nino condition in the Pacific (which increases the likelihood of relatively benign weather in much of the U.S.). But long-term forecasts have been notoriously unreliable over the past two years, and could prove to be far off the mark again this summer.
If they are, and last year’s scorching heat is repeated, the odds that prices will collapse this fall will be significantly reduced; depending upon the severity of the weather, natural gas prices could remain in the mid-$2.00/MMBtu range this summer. Spark spreads also could be more robust than they have been earlier this year.
On-shore production rates will also be a factor between now and the end of the injection season, and could be an even more significant factor next year.
Here, the prognosis is mixed. The natural gas rig count has fallen by nearly 400 rigs over the past two years—a 40% decline. Further, in February 2012 (the last month for which EIA has reported data), production declined by 0.4 Bcf/day—the first significant month-over-month decline in some time.
The significance of the decline in natural gas-directed drilling, however, is not clear-cut. The efficiency of horizontal drilling and fracking is continuing to improve at a rapid rate. Significantly more wells are being drilled per rig and the yield per well continues to improve. Even if production from natural gas-directed drilling starts to slow down, therefore, it is not likely to decline rapidly.
Further, the natural gas rig count no longer has the same meaning that it once had. Very few rigs have been laid down: most that have been removed from dry-gas formations have simply been relocated to liquid-rich combo plays that produce both natural gas and petroleum liquids (natural gas liquids and petroleum).
The natural gas production obtained from these wells varies considerably from play to play and within specific formations (with both “dry gas” and “wet gas” windows in plays such as Marcellus Shale and Eagle Ford). In many instances, however, the natural gas produced per well is almost as great as in dry-gas-only formations such as Haynesville or the northeast portions of Marcellus Shale. Additionally, it is often possible to drill more wells per rig, since in many instances liquid-rich plays are not as deep (particularly compared to Haynesville, the deepest of all of the major plays).
Pipeline flow data also indicates that the dip in production in February may be a short-lived phenomenon, due principally to curtailments at specific wells by Chesapeake, EnCana and Conoco Phillips, and that production in subsequent months has been relatively flat.
It is very not clear, therefore, whether U.S. production will decline significantly between now and the end of this year—and it is still possible that production will increase.
Reductions in LNG imports and net pipeline imports are more likely to affect total U.S. supplies. Even in the most extreme scenario, however, they are only likely to offset a portion of the year-over-year increase in supplies that is likely to occur this year, since current production levels are still well above their annual average.
Even if the supplies flowing into the U.S. market this year decline, the decline is likely to be small.
Fundamental shift in how the market functions.
Weather remains the most important factor that will affect the price trajectory for electricity and natural gas this year.
It is important to recognize that, even if weather-driven demand is high enough to avoid a storage availability crisis this fall, 4 ½ to 6 Bcf/day of continued coal displacement is still likely to be needed to avoid a storage availability crunch in the fall. To achieve this level of coal displacement, prices well below $3.00/MMBtu may still be required.
Since prices are not likely to return to the $4.00/MMBtu range in a normal-weather scenario, a shift in the supply/demand balance of as much as 3 Bcf/day may be required, through a combination of production decreases and increases in non-price-induced demand for natural gas.
The experience of the past few years suggests that a decrease in production of this magnitude may be difficult to achieve. Further, with the sole exception of price-induced coal displacement, the demand needle is difficult to shift more than a fraction of a Bcf per year.
Additionally, while this is occurring, the world will not be static. Some major producers (most notably EnCana) have announced that they already are able to achieve attractive half-cycle returns at a $3.00/MMBtu, even in Haynesville (a dry-gas-only play that requires drilling at least a mile further down than at many other shale formations). As techniques for shale development continue to improve and Pad drilling is more widely deployed, development costs are likely to sink even further.
Coal prices have also declined significantly, reducing the breakeven price for natural gas by as much as 50 cents/MMBtu.
The likelihood that electricity and natural gas prices will remain low for the next several years is relatively high. In effect, the equilibrium prices for electricity and natural gas are converging. Competition between natural gas and coal is likely to become a permanent feature of the U.S. market, driving down prices for both commodities.
The competition between these fuels, in turn, will set electricity prices in the U.S. for much of the year, in an iterative three-way process between natural gas, electricity and coal.
Over the next few years, this is likely to result in sweeping changes in the energy infrastructure in the U.S. Retirement of older coal-fired units has been expected for many years, driven primarily by stricter environmental requirements. The implementation of these requirements, however, remains uncertain.
As recently as four months ago, it looked as if retirement of coal-fired plants might be delayed by several more years. The abrupt downward shift in natural gas and electricity prices, however, is like a thunderclap that is suddenly accelerating this process.
As a result of lower natural gas prices, many coal-fired units can no longer earn sufficient operating margins to cover their fixed costs. Many of these units are not currently operating or are only occasionally used to generate power.
The majority of these units is likely to still be operated this summer. In the fall, however, unless natural gas and electricity prices fall sharply, a significant number of units may be mothballed or retired—and quite possibly never brought back into service—with additional coal-fired units retired over the next 24 to 36 months.
By three years from now, as much as 15% of all of the coal-fired generating units may be retired.
This shift away from coal will bring with it massive infrastructure changes, requiring construction of another major tranche of natural gas-fired generating units. It also will result in sweeping changes in the operation of the electric transmission grid and the interstate pipeline system and permanently change the face of the coal industry in the U.S.
It remains to be seen how well the mixed, partially-regulated/partially de-regulated electricity system in the U.S. will function in this rapidly changing environment. Most current pricing rules do not give the signals necessary to incentivize construction of new generating facilities—and it is not clear that integrated planning processes in states that remain regulated will yield better results.
Later in the decade, the stability of prices paid by large energy users could be greatly affected by how these issues are resolved. We will address this issue in greater detail in future columns.
