A year ago, most analysts were bearish about natural gas prices. I wrote that natural gas prices might double and they did. Today, most analysts are again bearish about gas prices and again, I think that they are probably wrong at least for 2017.
The mainstream narrative is that new pipeline capacity---notably the Rover Pipeline---out of the Marcellus and Utica shale plays will unleash a torrent of pent-up supply. That is because over-production in these plays has saturated the northeastern U.S. markets and 2016 wellhead prices averaged about $0.88/mmBtu less than Henry Hub prices (Figure 1). New take-away capacity to higher-priced markets will fix that problem but gas prices will plummet later in 2017 because of increased output.
Figure 1. Marcellus Wellhead Prices Were $0.88 per mmBtu Less Than Henry Hub Prices in 2016. Source: MarcellusGas.Org, EIA and Labyrinth Consulting Services, Inc.
Systematic overproduction turned the northeastern U.S. from the highest-margin market to the lowest by 2013. With a second chance to at least be on par with national pricing, shale gas companies will, according to the narrative, over-produce the entire U.S. market to a loss once again. Smart.
Conventional Gas, Shale Gas and Net Imports
There are three components to gas supply: conventional gas production, shale gas production, and imports. These must be understood to establish a context for a potential supply increase from the Marcellus and Utica shale plays.
There is no doubt that low prices resulted in a 4.26 bcf/d (billion cubic feet of gas per day) decline in gas production from September 2015 through October 2016 (Figure 2).
Figure 2. U.S. Gas Production Fell 4.26 bcf/d From September 2015 to October 2016. Source EIA Natural Gas Monthly and Weekly Updates, and Labyrinth Consulting Services, Inc.
Since 2008, conventional gas production has been in terminal decline and has fallen 26 bcf/d. It is currently falling about 3 bcf/d each year. Shale gas--including associated gas from tight oil---now makes up more than two-thirds of domestic supply. That means that shale gas output must grow by more than 3 bcf/d each year to offset falling conventional supply.
But annual shale gas production growth slowed from almost 7 bcf/d in the first quarter of 2015 to less than 2 bcf/d in the first quarter of 2017 (Figure 3).
Figure 3. Shale Gas Growth Has Slowed from Almost 7 bcf/d in the First Quarter of 2015 to Less Than 2 bcf/d in the First Quarter of 2017. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc.
If shale gas production growth doubles in 2017, then supply will be flat but considerably lower than 2015 levels when over-supply crushed gas prices. Gas supply must increase well beyond what is likely this year in order for prices to fall much below current levels of about $3.25 per mmBtu.
Considerable supply potential exists. The shale gas horizontal rig count has more than doubled---from 76 to 167 rigs---since June 2016 with higher gas prices (Figure 4). How quickly can that potential be converted into supply?
Figure 4. Shale Gas Rig Count Has More Than Doubled Since June 2016 With Higher Gas Prices. Source: EIA and Labyrinth Consulting Services, Inc.
EIA's latest production forecast suggests that it may happen very quickly. The May STEO projects gas growth of 5.6 bcf/d in 2017 which includes an additional 3.5 bcf/d between April and the end of the year (Figure 5).
Figure 5. EIA Forecast is for a 5.6 Bcf/d Gas Production Increase in 2017 with Prices Rising to $3.43 By December. Source: EIA May 2017 STEO and Labyrinth Consulting Services, Inc.[/caption]
Although that may be unreasonably aggressive, it is noteworthy that the overall supply balance (red and blue fill in the figure) remains in deficit for most of the year, and that spot prices continue to increase, ending the year at almost $3.50/mmBtu. Net imports (the third component of total supply in addition to shale gas and conventional gas) are forecast to average -0.3 bcf/d in 2017 compared to +1.7 bcf/d in 2016.
The Rover Pipeline was certificated for construction in mid-February and will connect gas from the Utica and Southwestern Marcellus shale plays to the Defiance Hub in northwestern Ohio (Figure 6). There is a gas surplus (~1.8 bcf/d) in Ohio so this pipeline is a gas exit route to the Dawn Hub in Ontario, and to the Midwest and Gulf Coast via interconnecting Vector, Panhandle Eastern and ANR pipelines. There, it will compete with existing supply and result in lower prices.
Figure 6. Rover Pipeline Route Connecting Utica and Southwestern Marcellus Shale Plays With the Defiance Hub. Source: Energy Transfer and Labyrinth Consulting Services, Inc.
Although Rover is scheduled to reach Defiance in November, it is unlikely that any gas will move beyond there before 2018. It will not, therefore, have any effect on gas supply in 2017. Depending on how much gas ultimately is sent to Canada, it may have limited effect on U.S. supply in 2018.
What Could Go Wrong?
The consensus of experts has been consistently wrong about natural gas supply for decades. That's why LNG import terminals were built following gas shortages in the 1970s only to be shuttered after imports from Canada, fuel switching to coal and nuclear, and gas industry deregulation resulted in 15 years of stable gas supply.
By the early 2000s, import terminals were re-opened as Canadian gas production began to decline and domestic output failed to rally even with much higher gas-directed rig counts. The shale revolution ended all of that and now, those import terminals are being re-designed to export LNG. Gas export will likely prove to be fully out-of-phase with future gas supply once again.
That is why I am skeptical when experts now declare an impending gas over-supply. Gas prices remain well above $3/mmBtu after one of the warmest winters on record, and most data suggests that supply will remain tight at least through the end of 2017.
What could go wrong with that hypothesis? Weather, of course, and Morgan Stanley has astutely pointed out that 2016 rainfall in California may displace some natural gas with hydro for electric power generation. They and PointLogic note that some cooler summer forecasts might further reduce gas demand.
At the same time, EIA expects higher-than-average consumption for Summer 2017 (Figure 7) and the Browning World Climate Bulletin predicts a warmer-than-average summer with early El Niño onset.
Figure 7. EIA Forecasts Higher-Than-Average Consumption for Summer 2017. Source: EIA May 2017 STEO and Labyrinth Consulting Services, Inc
Morgan Stanley supposes that associated gas from tight oil plays will be a major factor in increased gas supply. This ignores the considerable dysfunction in the pressure pumping business where frack crews commonly lag demand by at least 6 months. Rig count increases will probably not translate into production gains as quickly as many oil-price bears assume. Gas pipelines out of the Permian basin remain problematic and most gas from the Eagle Ford will go to Mexico.
Morgan Stanley's belief that significant expansion of production in the Haynesville Shale will occur is based on incorrect sub-$3.00 break-even prices. Exco--the second largest Haynesville producer--shows a maintenance spending level of about $3.50 in their 2016 10-K after writing off all proved undeveloped reserves in accordance with the SEC 5-year rule.
It also seems unlikely that losses in major gas-producing areas including Texas, Oklahoma, Wyoming, Arkansas, Utah, Louisiana and the OCS Gulf of Mexico will be quickly offset by gains in Ohio, Pennsylvania and West Virginia especially considering frack crew availability (Figure 8).
Figure 8. Unlikely That OH, PA & WV Gains Will Offset TX, OK, WY, AR & OCS Losses in 2017. Source: EIA and Labyrinth Consulting Services, Inc.
Comparative inventories indicate that the mid-cycle price trend has moved upward from $3.00 to $3.60 (or higher) since mid-March reflecting market perception of tight supply (Figure 9). The mid-cycle price---where the trend line intersects the y-axis---represents the median price that the market deems necessary to maintain supply throughout the present price cycle. If this trend persists, it is possible that year-end gas prices will be in the $3.50 to $4.00 range.
Figure 9. Gas Mid-Cycle Price Has Shifted To $3.60/mmBtu or Higher. Black arrows show progression from higher to lower price trend and back again. Source: EIA and Labyrinth Consulting Services, Inc.
At the same time, it is likely that prices will be substantially lower in 2018 once the Rover and other pipelines are operating and frack crews begin catching up with drilling levels. That possibility is reflected in inverted natural gas forward curves (Figure 10). Note that the price for futures contracts drops sharply in January 2017.
Figure 10. Henry Hub Forward Curves Are Inverted and Rising. Source: CME and Labyrinth Consulting Services, Inc.
Although forward curves should never be viewed as a price forecast, they reflect current market expectations. Those expectations seem clear and are supported by all available data: natural gas supply should remain fairly tight through 2017 and will probably increase some time in 2018 and that will result in lower gas prices. Understand the uncertainties and plan accordingly.
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A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.
Thankfully, it has not.
On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?
The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.
The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.
How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.
The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.
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Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020
As mitigation efforts to contain the 2019 novel coronavirus disease (COVID-19) pandemic continue to lead to rapid declines in petroleum consumption around the world, the production of liquid fuels globally has changed more slowly, leading to record increases in the amount of crude oil and other petroleum liquids placed into storage in recent months. In its May Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global inventory builds will be largest in the first half of 2020. EIA estimates that inventory builds rose at a rate of 6.6 million barrels per day (b/d) in the first quarter and will increase by 11.5 million b/d in the second quarter because of widespread travel limitations and sharp reductions in economic activity.
After the first half of 2020, EIA expects global liquid fuels consumption to increase, leading to inventory draws for at least six consecutive quarters and ultimately putting upward pressure on crude oil prices that are currently at their lowest levels in 20 years.
As with the March and April STEO, EIA’s forecast reductions in global oil demand arise from three main drivers: lower economic growth, less air travel, and other declines in demand not captured by these two categories, largely related to reductions in travel because of stay-at-home orders. Based on incoming economic data and updated assessments of lockdowns and stay-at-home orders across dozens of countries, EIA has further lowered its forecasts for global oil demand in 2020 in the May STEO. The STEO is based on macroeconomic projections by Oxford Economics (for countries other than the United States) and by IHS Markit (for the United States).
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020
In the May STEO, EIA forecasts global liquid fuels consumption will average 92.6 million b/d in 2020, down 8.1 million b/d from 2019. EIA forecasts both economic growth and global consumption of liquid fuels to increase in 2021 but remain lower than 2019 levels. Any lasting behavioral changes to patterns in transportation and other forms of oil consumption once COVID-19 mitigation efforts end, however, present considerable uncertainty to the increase in consumption of liquid fuels, even if gross domestic product (GDP) growth increases.
Members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) agreed to new production cuts in early April that will remain in place throughout the STEO forecast period ending in 2021. EIA assumes OPEC members will mostly adhere to announced cuts during the first two months of the agreement (May and June) and that production compliance will relax later in the forecast period as stated production cuts are reduced and global oil demand begins growing.
EIA forecasts OPEC crude oil production will fall to less than 24.1 million b/d in June, a 6.3 million b/d decline from April, when OPEC production increased following an inconclusive meeting in March. If OPEC production declines to less than 24.1 million b/d, it would be the group’s lowest level of production since March 1995. The forecast for June OPEC production does not account for the additional voluntary cuts announced by Saudi Arabia’s Energy Ministry on May 11.
EIA expects OPEC production will begin increasing in July 2020 in response to rising global oil demand and prices. From that point, EIA expects a gradual increase in OPEC crude oil production through the remainder of the forecast and for production to rise to an average of 28.5 million b/d during the second half of 2021.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020
EIA forecasts the supply of non-OPEC petroleum and other liquid fuels will decline by 2.4 million b/d in 2020 compared with 2019. The steep decline reflects lower forecast oil prices in the second quarter as well as the newly implemented production cuts from non-OPEC participants in the OPEC+ agreement. EIA expects the largest non-OPEC production declines in 2020 to occur in Russia, the United States, and Canada.
Pairing renewable energy generators with energy storage, particularly batteries, is increasingly common as the cost of energy storage continues to decrease. The U.S. Energy Information Administration’s (EIA) latest inventory of electric generators shows that the number of solar and wind generation sites co-located with batteries has grown from 19 paired sites in 2016 to 53 paired sites in 2019. This trend is expected to continue: according to planned installations reported to EIA, another 56 facilities pairing renewable energy and battery storage will come online by the end of 2023.
Source: U.S. Energy Information Administration, Annual Electric Generator Report
Note: Many battery systems provide more than one application.
Combining energy storage with renewable technologies such as wind and solar provides a variety of benefits. One of the most critical is the ability to store energy as it is generated and then redistribute it when needed, rather than as it is produced. This ability reduces the need to curtail renewable generation and allows the energy to be deployed during periods of high electricity demand.
Although the most commonly reported application for batteries co-located with renewable sources is storing excess energy, the majority of batteries serve more than one function. Frequency regulation, which helps maintain the grid’s electric frequency on a second-to-second basis, is the second-most common use for batteries co-located with renewables. Batteries can also provide transmission and distribution support, helping to smooth out energy flows. The ability to support the integration of renewables into the grid’s current infrastructure, in addition to other ancillary services that they perform such as frequency regulation, are primary drivers in the growth of battery-renewable pairings.
Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory
Currently, more than 90% of the total operating hybrid (renewable generator plus energy storage) capacity in the country is located in just nine states. Texas alone has 46% of the current total. Hybrid capacity in the United States is concentrated at a few large sites, and 10 facilities account for more than half of total operational capacity. Installation as part of a hybrid system is common for batteries but not for renewable generators such as wind and solar. Although nearly 25% of total U.S. battery capacity is installed as part of a hybrid system, only 1% of total wind capacity and 2% of total solar capacity is part of a hybrid system.
Reported data show that future projects will be much larger in scale than currently operating projects. One anticipated projected in Nevada called Gemini Solar is expected to add more than one gigawatt of combined renewable and storage capacity. The U.S. Department of the Interior approved the Gemini Solar project on May 11, 2020, and the first phase of construction is expected to begin in 2021. By the end of 2023, average renewable capacity at proposed U.S. facilities will more than double from 34 megawatts (MW) to 75 MW, and average battery capacity will grow from 5 MW to 36 MW.