National | New Picture Emerging This Winter
By Special Contributor, Andrew D. Weissman, Publisher, Energy Business Watch
The last twelve months have demonstrated powerfully the impact on electricity prices of swings in weather and the impact of explosive growth in shale production. We’ll discuss first how the electricity market is changing and likely price levels for electricity and natural gas next year. We’ll then examine how this year’s election could affect energy markets longer term.
To understand how market dynamics are changing, it is important to focus not just on shale, but the link between shale and natural gas storage and how this link affects prices.
When last winter began, U.S. Lower 48 production of natural gas was at a new all-time high, 7 Bcf/day above year-ago levels. Further, despite 1.3-1.4 Tcf of above normal weather-driven demand during the previous twelve months, the amount of natural gas in storage was also at its highest level ever.
This steep rise in production, coupled with record storage at the end of the historical injection season, provided a clear indication that the natural gas market would be massively oversupplied in a normal weather scenario. Not surprisingly, prices for electricity and natural gas were already starting to plummet.
Last winter, however, the fall-off in prices for electricity and natural gas that began in the autumn started to rapidly accelerate. This steep decline was triggered in part by extremely mild weather, which cut consumption of electricity and natural gas sharply. But weather was only part of the story: even if weather conditions had matched historical norms, the natural gas market still would have been over-supplied by 1.75-2.25 Bcf/day.
The combination of extremely mild winter weather and record supply created a major crisis for the natural gas industry. To prevent the market from being flooded with natural gas, prices had to fall enough to induce sufficient substitution of natural gas-fired generation for coal to absorb massive amounts of natural gas.
By late March, prices at Henry Hub fell below $2.00/MMBtu for the first time since 2002, bottoming out on April 19 at $1.91/MMBtu—a 52% decline from $4.00/MMBtu-plus prices the previous winter. This steep drop in natural gas prices, intensified by a sharp decline in coal prices, resulted in more than 1.5 Tcf of price-induced coal displacement. During the first nine months of this year, prices at Henry Hub averaged just $2.54/MMBtu – a level not seen since 2002.
NYMEX Front-Month Natural Gas (S/MMBtu), 2011 vs. 2012
The massive increase in coal displacement at a $2.54/MMBtu price level, however, would not have been sufficient by itself to reduce the amount of natural gas in storage to tolerable acceptable levels. Instead, an outright price collapse was possible if summer weather matched historical norms. Despite severely depressed prices, a train wreck was avoided due only to a third straight near record-hot summer, which created 300-350 Bcf of additional weather-driven demand. Without extremely hot summer weather, prices might have had fall to the mid-$1.00/MMBtu range by mid-summer to balance the market and might still be at $2.50/MMBtu or lower now.
The stunning decline in natural gas prices that began last fall has had nearly as much impact on electricity prices, which fell by as much as $9-13/MWh on a year-over-year basis in gas-dependent regions.
On-Peak Day-Ahead Electricity Prices at PJM West
In many regions, for most of this year on-peak prices averaged just $32-37/MWh. Spark spreads in the spring dropped to as low as $10-12/MWh and dark spreads were often negative. An increasing number of coal-fired plants were shut down for long stretches of time or were using only sparingly as peaking units.
With operating margins at distressed levels and a sharp drop in utilization rates, many coal-fired units could no longer cover their fixed costs – let alone the expected cost of environmental retro-fits required by pending EPA regulations. As a result, many plant owners decided to permanently retire coal-fired plants.
Some analysts predict that by the middle of the decade, up to 80,000 MW– 30% – of the U.S. coal-fired fleet. If these retirements occur, it will fundamentally change the operation of the grid and have sweeping implications for the electricity market.
By the end of September, the amount of natural gas in storage had been reduced the year-over-year storage surplus to 272 Bcf. Further, October weather was much colder than last year. By November 1, this helped to reduce the year-over-year storage surplus to 109 Bcf.
This set the stage for the natural gas prices to rally modestly. By mid-November, the 2013 calendar year strip reached as high as $3.94/MMBtu — 19% above the mid-summer low of $3.30/MMBtu on June 13.
But what does all of this mean for this coming winter for both electricity and natural gas? Is the forward curve for natural gas overpriced? Does the upside potential offer greater rewards than the risk for natural gas prices to decline? Or could prices drop significantly by the end of the winter?
The answers to these questions depend on four major factors: (i) U.S. production of natural gas; (ii) weather; (iii) the impact of these factors on storage; and (iv) the market’s assessment of acceptable end-of-winter storage.
During the past twelve months, production of natural gas from shale has continued to explode. The natural gas rig count, however, has fallen off a cliff, declining by 53%. As a result, many market observers expect that U.S. production will start to decline significantly soon.
The natural gas rig count, however, has become a very misleading metric to assess future production, for several reasons:
- A rig today is not the same as a rig just two or three years ago. Vertical rigs have disappeared almost entirely, replaced by extremely powerful state-of-the-art horizontal rigs. Further, the turnaround time between rigs has been cut drastically, longer laterals are being drilled, and fracking techniques are continuing to rapidly improve. As a result, production per rig for natural gas-directed rigs is likely to be much higher than it was just twelve to twenty-four months ago.
- While most rigs previously classified as natural gas-directed rigs have been shifted to “liquid–plays” and otherwise counted as rigs drilling for oil, a large percentage of the rigs drilling in liquid-rich plays produces significant amounts of natural gas – in some instances as high as 50-80% of total hydrocarbon output.
- There is also a huge backlog of drilled-but-uncompleted wells that will be tied into the pipeline system as soon as the required infrastructure is completed.
Many analysts expect that despite these factors, natural gas production in several of the major plays will start to decline next year – an assessment with which we agree.
At the same time, however, a number of critical infrastructure additions will soon be complete. In Marcellus Shale alone, production is expected to surge, adding as much as 3.8 Bcf/day over the next twelve months. For most of next year, this is likely to totally offset declines in other plays. Even under the most bullish scenario for producers, production is not likely to start declining until the fourth quarter of next year – and even then only slowly.
Further, this assessment does not take into account the likelihood of continued rapid improvements in productivity, and the willingness of many producers to increase drilling again (at least modestly) at current price levels for the 12-18 month strip.
The last of these factors in particular – the likelihood that the modest rebound in prices since the summer will stimulate additional drilling – could prove to be particularly important. While uncertainty levels are high, if we had to bet, we would place our wager on production continuing to increase next year.
Weather, of course, could have an even greater impact on prices for natural gas this winter. At this point in the season, a wide range of outcomes is still possible:
November–March Gas-Weighted Heating Degree Days
The difference between the high end of this (entirely plausible) range is 350-400 Bcf. Production also could easily vary up or down by 1 Bcf/day or more and is not likely to be correlated significantly with winter demand.
Under scenarios that still have a substantial possibility of occurring, therefore, the amount of excess gas available to the market could vary by as much as 1.0 Tcf—the difference between a bullish scenario featuring a cold winter and a 1 Bcf/d production decline, and a bearish scenario featuring both warm weather and a 1 Bcf/d production increase.
The amount of natural gas required to keep end-of-winter storage at manageable levels will then depend upon two factors: (i) the price availability curve for coal displacement; and (ii) the market’s collective judgment regarding appropriate end-of-winter storage levels. The more gas that must be absorbed to keep end-of-storage at reasonable levels, the more prices will decline. Conversely, if winter weather is cold enough and production is flat, less coal displacement will be necessary and prices are likely to rise. The illustration below indicates the most likely price curve for coal displacement, and the price required for the winter season to end with 1,950 Bcf under a range of different scenarios regarding production and weather.
Equilibrium Price for Natural Gas Under Likely Weather Scenarios
After the 2011/2012 withdrawal/storage refill cycle, we believe the market will target end-of-season storage between levels during the past decade and last year. In a normal-weather scenario, this would result in an equilibrium price this winter of under $3/MMBtu—significantly below the most recent strip pricing.
Political Impacts on Energy Markets
Turning the page on the recent national election, energy markets are likely to scrutinize the impact of President Obama’s second term in the Oval Office. While the adverse impact of Obama’s reelection on energy markets is likely smaller than many have feared, the period lasting between now and the end of this year may define the tone the President will take in his second term.
Many pundits have speculated that Obama, unburdened by a reelection campaign, may pivot decisively to the political left. It may be more likely, however, that President Obama could shift towards a more centrist governing position, hoping to secure a legacy less as a partisan and more as a unifier, and in the process establish a strong center-left position for the Democratic party in future election campaigns.
Already, toward the end of his first term, President Obama relaxed some stringent requirements of new EPA regulations, perhaps signaling a shift toward a more centrist philosophy.
If Romney had been elected, he would have likely limited or eliminated several EPA initiatives affecting power plants, including the Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), and Regional Haze rules. The real-world effect of these actions would be to reduce pressure on utilities to either retire or retrofit their existing coal-fired capacity—reducing both natural gas power sector demand and the price of natural gas.
Further, if Romney would have opened up federal lands for oil production—as seems likely— this would also have the immediate effect of increased drilling, increased supply, and downward pressure on prices.
Global Warming Heats Up
The largest political development, however, concerns the government’s response to Superstorm Sandy and the real possibility of climate issues gaining traction. New Jersey’s Governor Christie, New York’s Governor Cuomo, and New York City’s Mayor Bloomberg-—none previously known to be bedfellows¬—all cited the increased incidents of extreme weather across the United States, along with the necessity of resource planning in the rebuilding effort to account for the increasing possibility of extreme weather events in the future.
Recent widespread meteorological disturbances have helped to bring the issue climate change back into the public eye. Sandy was the most destructive storm to hit the Northeast, following up on record-breaking heat in Texas last year and extensive drought in the Midwest this summer. Further, momentum may slowly strengthen if and when the economy rebounds and politicians shift their focus away from economic issues.
As politicians establish an implicit recognition of the possibility of climate change—through increased devotion of financial resources for the increased likelihood of natural disasters, for example—there may be an increased call for addressing the potential source of these calamities.
Further, swirling rumors have suggested John Kerry as a likely candidate for Secretary of State in Obama’s new cabinet. Senator Kerry, who led the Senate delegation to the Copenhagen climate talks in 2009, has had an outsized voice on climate change issues, and could work to advance the global warming agenda.
Other political changes could have far-reaching implications for the energy industry. EPA Administrator Lisa Jackson, Energy Secretary Steven Chu, and Interior Secretary Ken Salazar are all liable to be replaced. If new appointments are required, a lengthy Senate confirmation process could stall any federal action on energy issues.
Surprise appointments to any of these positions—including perhaps someone from the business community to head the EPA—could stir interest and strengthen Obama’s verbal commitment to a more bipartisan agenda.
Economic Concerns Are Main Driver
The bottoming of natural gas prices in April has brought the shale gas revolution mainstream. The desire and potential to create natural gas industry jobs and keep natural gas prices low to aid the nascent recovery in the industrial sector may guide the President to establishing more moderate positions.
The technological advances driving the shale gas revolution are likely to remain largely unaffected no matter who occupies the White House. While Romney may have relaxed potential legislation that could include oversight on green well completions or ongoing concerns from pipeline leaks, natural gas supplies have burgeoned even under the policies of the Obama administration.
Exploding supply has driven prices lower for both natural gas and coal, which must compete with natural gas to retain market share of the power generation mix.
Despite lower commodity costs, pressure to close coal plants has stemmed largely from economic considerations. Operating margins are no longer covering fixed costs, and older plants may not warrant the significant capital expenditures necessary for continued operation. As coal capacity retires, market vulnerability to natural gas and electricity price spikes is likely to increase.
If we experience a repeat of the 2012 summer, an equilibrium price of $3.55/MMBtu would return storage inventories to the same record levels reached at the end of 2012.
To the extent that end-of-winter storage is higher than 1,950 Bcf, prices will have to sink even lower to absorb excess natural gas supplies. If end-of-winter storage winds up below 1,950 Bcf, more available storage capacity will accommodate a further rise in prices. Higher natural gas prices will have a profound impact on electricity markets. With natural gas prices likely $0.75-$1.25/MMBtu higher than last summer, on-peak prices could easily rise by $7-$10/MMBtu, and even higher in heavily gas-dependent regions.
Electricity prices may also receive a further boost from other sources, including projections for reduced nuclear and hydropower availability. Additionally, under a harsh-weather scenario featuring either a cold winter or a hot summer, prices for both electricity and natural gas could rise even higher.
With higher prices, however, the amount of natural gas burned to generate electricity throughout the country will likely decrease, with the remainder of natural gas serving higher injections and greater storage builds in the summer months. Assuming all else constant, therefore, the percentage of electricity generated by natural gas is likely to decline in 2013.