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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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline