Back in March 2017, we published our Energy Outlook for 2017 for our subscribers. Specifically, when it comes to natural gas, we noted that:
" Furthermore, we project that at the end of the withdrawal season this April, inventories will stand at approximately 2,000 BCF. Taking into consideration this starting point, we forecast that for the most part, natural gas price will be rangebound trading from $3/mmbtu to $3.50/mmbtu (Henry Hub) by year end. And given that demand/supply will remain tight in 2017, we could see natural gas prices temporarily climb above $3.5/mmbtu (Henry Hub) in H2 2017 if we experience a very warm summer."
And when it comes to the WTI price, we noted in March 2017 that:
"Barring considerable oil production growth in Libya and assuming that OPEC extends its output agreement and the OPEC/non-OPEC cuts (~1.8 million barrels per day) remain in place by year end, we project that the upward effect of the supply-demand rebalance will be more obvious in H2 2017 and we will definitely see higher oil prices by year end.
On that front, we believe that due to budget constraints, Saudi Arabia will continue its efforts to curb crude output by maintaining the recent OPEC cuts by year end. Saudi Arabia has not managed to dramatically restructure its economy while significantly reducing its overreliance on energy revenues.
After all, we project that WTI price will be rangebound from $50 to $55 in H1 2017 and will exceed $55 in H2 2017 reaching $60 in Q4 2017."
If you check the charts, you will see that our forecasts both for natural gas and WTI were correct.
That said, this is our Energy Outlook for 2018, as promised.
Our Oil Forecasts
From a technical standpoint, it's noteworthy that one of the most remarkable shifts that occurred in 2017 was the change in the futures curve. This change was first noticed for Brent and more recently for WTI. Contracts for nearby delivery have been trading at a premium to longer-dated ones as demand rises and supplies tighten. This pattern, known as backwardation, hasn’t been seen so consistently since 2014, as illustrated below:
From a fundamental standpoint, global oil demand has consistently grown over the last years. The 10-year average stands at approximately 1 MMbbls/d growth, the 5-year average is approximately 1.2 MMbbls/d growth and the demand growth in 2017 was approximately 1.7 MMbbls/d, which is approximately 40% stronger than the 5-year average.
We believe that global oil demand will continue to grow at a steady pace throughout the rest of the decade and a minor economic downturn will just slow the pace of growth without upending the upward trend line of demand.
Specifically, we project that global oil demand growth in 2018 will be at least 1.6 MMbbls/d thanks to surging demand primarily from China and India while North America's and Europe's continued growth will support this forecast.
On the supply side, OPEC and Russia recently extended the production cuts by the end of 2018, which translates into approximately 1.8 MMbbls/d. It's noteworthy that Libya and Nigeria, previously exempt from cutting production due to internal strife, agreed not to increase their output next year above 2017 levels.
Meanwhile, US crude oil production was up about 12% or approximately 1.0 MMbbls/d reaching approximately 9.8 MMbbls/d in late 2017, while the oil rig count was up approximately 50% (or approximately 230 rigs) in late 2017 compared with the same period in 2016.
Therefore, production growth in the U.S. didn't fully offset OPEC's and Russia's production cuts in 2017, resulting in a significant supply gap of approximately 800,000 bbls/d.
Assuming that OPEC's and Russia's compliance for production cuts is 100% this year, we project that the supply gap of approximately 800,000 bbls/d will not close and will be at or above 300,000 bbls/d in 2018.
To say it differently, we project that US crude oil production will rise much less than 1.0 MMbbls/d in 2018 even if oil rig count goes up another 230 rigs this year.
On that front, EIA forecasts that US crude oil output will rise by 780,000 bbls/d in 2018. But we don't share EIA's rosy approach. We question the projected growth of U.S. shale and based on our model, we project that US crude oil production growth in 2018 will not exceed 500,000 bbls/d, due to a handful of reasons such as:
1) The crude oil production growth in the U.S. can't be linear due to the nature of the decline curve of the unconventional wells, which is exponential.
2) The crude oil production growth in the U.S. in 2017 took place with the shale producers drilling their sweet spots, which translates into the highest ROIs.
However, the sweet spots are gradually being exhausted and the quality acreage is not limitless when it comes to major oil plays such as Bakken and Eagle Ford. This trend is evident in local North Dakota statistics and output in still-booming McKenzie County has held steady while neighboring Williams and Mountrail counties have experienced declines. And the Permian plays can't save the day.
The exhaustion of the sweet spots will be partly offset by improved drilling efficiency thanks to technical advances (i.e. well length, the amounts of water and sand used in fracking) coupled with the fact that the shale producers in the U.S. will primarily work on their inventory of "drilled but uncompleted wells" (DUCs) this year.
And we believe that things will get progressively worse each year after 2018 as wells in various sweet spots are exhausted and technology fails to close the gap.
3) The numerous bankruptcies have made the shale producers in the U.S. learn the hard way. As a result, the American producers seem to change their business plans from "production growth at all costs" to "living within their means", so they will try to better align spending with their cash flows in order to improve returns while servicing their debts over the next years.
4) The majority of the oilfield services companies will continue to experience logistical constaints (i.e. crews availability, capacity shortages, equipment shortfalls) by year end.
5) Inflationary pressures will begin adding to the cost of oil production and therefore, any rise in the price of oil will partly be directed to oilfield services firms, which were squeezed during the downturn.
After all, we project that US inventories will continue to decline primarily thanks to surging exports that are being driven by a wide Brent-WTI spread over $5/bbl and therefore, the current storage surplus will switch to storage deficit versus the 5-year average by the end of April 2018 (the latest), which is a few weeks before the arrival of the US driving season, which formally starts on the Memorial day holiday weekend in late May and ends on the Labour Day holiday in early September.
Furthermore, the Brent-WTI spread has contracted steadily over the past two weeks, falling under $5.50/bbl. Should this spread continue to contract, it could limit US oil exports. However, we project that the Brent-WTI spread will remain at or above $4/bbl during most part of 2018.
Last but not least, we project that WTI will fluctuate between $58 and $66 in H1 2018 and will range between $62 and $70 in H2 2018.
Not to forget that our oil price forecast does not take into account potential supply outages caused by a bunch of factors such as the discord between Qatar and the OPEC core countries, the Saudi Arabia-Iran battle or the worsening situation in Venezuela where there were only 40 working oil rigs according to Baker Hughes, the lowest level since 2003.
Our Natural Gas Forecasts
From a technical stanpoint, when it comes to the futures curve, the pattern currently is backwardation, which creates a tailwind for natural gas ETF holders. As you know, UNG, BOIL and UGAZ hold front-month contracts, sell them 2-3 weeks prior to expiration and rotate these funds into the T+1 soon-to-be-front-month-contract, with this process repeating each month. Therefore, these three ETFs are currently selling higher-priced assets and re-buying in at a lower price, creating price-independent profits.
Also, this backwardation implies that investors believe that the current natural gas price is due to a transient rise in demand associated with colder-than-average temperatures and will not fundamentally alter supply/demand balance that would be needed to support higher prices beyond the winter period, although the storage deficit versus the 5-year average is approximately 400 BCF.
From a fundamental standpoint, we will start by presenting the supply side.
Natural gas production in the U.S. currently is about 76 BCF/d, so it's up over 5 BCF/day year-over-year. With Canadian and LNG imports being flat on a YoY basis, total supply currently stands at approximately 81 BCF/d.
On that front, some significant natural gas pipeline projects in the Northeast United States are expected to be completed over this winter, with more than half of the capacity designed to transport natural gas from the Appalachian region where more than 40% of onshore U.S. natural gas production now occurs, to Midwest and Southeast markets, as illustrated below:
The pipeline projects out of the Northeast vary in size and purpose allowing pipelines to more easily meet demand needs. Some projects will serve as short interconnects, while others are designed to deliver natural gas from Appalachia, where growth in regional production has far outpaced growth in regional consumption, to other markets.
The biggest project is Energy Transfer's (ETP) Rover pipeline (3.25 Bcf/d) that will move natural gas from Appalachia to the Midwest. Also, there is TransCanada's (TRP) Leach XPress (1.5 Bcf/d) that brings natural gas from Appalachia to the Southeast and Williams' (WMB) Atlantic Sunrise that will transport up to 1.7 Bcf/d from the Marcellus shale in Pennsylvania to markets in the U.S. Mid Atlantic and Southeast.
Furthermore, higher oil prices favor increased drilling activity that results in additional nat gas production coming from the oil drillers (associated gas).
Meanwhile, multiple new sources of demand are coming online over the summer and next Fall, including additional LNG export plants.
Specifically, and aside from Dominion Energy's Cove Point LNG export terminal on the Chesapeake Bay in Maryland that recently came on line, other LNG projects in the U.S. Gulf Coast that will be completed in 2018 are Freeport's LNG and Kinder Morgan's Elba Island LNG project, as illustrated below:
Cove Point adds just 5.6 BCF/week at maximum capacity, while towards the middle of 2018, Cameron Train 1 is coming online followed by the small Elba plant, which will push daily LNG demand above 4.5 BCF/d. In Q3 and Q4 2018, Cameron Train 2 and Freeport Train 1 are expected to come online, pushing LNG feedgas demand above 6 BCF/d, nearly double recent levels. In 2019, demand is expected to climb above 10 BCF/d as multiple other LNG projects reach completion, as illustrated above.
When it comes to the exports to Mexico, we don't expect demand from Mexico to increase more than 2 Bcf/d on a YoY basis, based on the existing pipeline projects and their completion dates.
Moreover, we don't expect demand growth from the coal-to-gas plant conversions to exceed 2 Bcf/d on a YoY basis, based on the existing projects from the Utilities and municipal plant owners.
In short, the combination of LNG feedgas demand and Mexico's pipelines with Coal-to-gas conversions are expected to see YoY gains that will negate much all of the YoY gains in production.
After all, natural gas price will be ultimately determined by Mother Nature, which is unpredictable. We are heavily dependent on Mother Nature given that Mother Nature largely determines two key demand elements such as residential/commercial heating demand and powerburn electricity demand.
As you know, residential/commercial heating demand and powerburn electricity demand are temperature-dependent elements while domestic production, LNG imports, Canadian imports, LNG exports, Mexico's pipelines and coal-to-gas conversions are temperature-independent elements of the supply/demand equation.
That said, based on our model, we project that natural gas storage inventories will be between 1,200 BCF and 1,700 BCF at the end of the withdrawal season in March 2018, which will be one of the smallest season-ending level in the last 5-years, behind only 2014's 824 BCF post-polar vortex level.
Additionally, we project that Henry Hub price will be rangebound between US$2.70/mmbtu and US$3.40/mmbtu during most part of 2018.
And we will be surprised to see prices move much above US$3.40/mmbtu or under US$2.70/mmbtu for an extended period of time.
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