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Last Updated: May 18, 2017
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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.

marcellus-wellhead-prices-were-0-88-less-than-henry-hub-in-2016

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).

u-s-gas-production-fell-4-26-bcf-d-from-september-2015-to-october-2016

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).

shale-gas-growth-has-slowed-from-7-bcf-d-in-q1-2015-to-2-bcf-d-in-q1-2017

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?

shale-gas-rig-count-has-more-than-doubled-since-june-2016-with-higher-prices

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.

Rover Pipeline

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.

rover-pipeline-route-map-may-2017

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.

eia-forecasts-higher-than-average-consumption-for-summer-2017

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).

unlikely-that-oh-pa-wv-gains-will-offset-tx-ok-wy-ar-ocs-losses-in-2017

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.

gas-mid-cycle-price-has-shifted-to-3-60-mmbtu-or-higher

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.

henry-hub-hh-forward-curves-are-inverted-and-rising

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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Upcoming OPEC Meeting: What to Expect

A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.

That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.

That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.

Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.

Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?

Expectations at the 176th OPEC Conference

  • 25 June 2019, Vienna, Austria
  • Extension of current OPEC+ supply deal from end-June 2019 to end-December 2019
June, 12 2019
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $71 per barrel (b) in May, largely unchanged from April 2019 and almost $6/b lower than the price in May of last year. However, Brent prices fell sharply in recent weeks, reaching $62/b on June 5. EIA forecasts Brent spot prices will average $67/b in 2019, $3/b lower than the forecast in last month’s STEO, and remain at $67/b in 2020. EIA’s lower 2019 Brent price path reflects rising uncertainty about global oil demand growth.
  • EIA forecasts global oil inventories will decline by 0.3 million barrels per day (b/d) in 2019 and then increase by 0.3 million b/d in 2020. Although global liquid fuels demand outpaces supply in 2019 in EIA’s forecast, global liquid fuels supply is forecast to rise by 2.0 million b/d in 2020, with 1.4 million of that growth coming from the United States. Global oil demand rises by 1.4 million b/d in 2020 in the forecast, up from expected growth of 1.2 million b/d in 2019.
  • Annual U.S. crude oil production reached a record 11.0 million b/d in 2018. EIA forecasts that U.S. production will increase by 1.4 million b/d in 2019 and by 0.9 million b/d in 2020, with 2020 production averaging 13.3 million b/d. Despite EIA’s expectation for slowing growth, the 2019 forecast would be the second-largest annual growth on record (following 1.6 million b/d in 2018), and the 2020 forecast would be the fifth-largest growth on record.
  • For the 2019 summer driving season, which runs from April through September, EIA forecasts that U.S. regular gasoline retail prices will average $2.76 per gallon (gal), down from an average of $2.85/gal last summer. The lower forecast gasoline prices primarily reflect EIA’s expectation of lower crude oil prices this summer.

U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

World liquid fuels production and consumption balance


Natural gas

  • The Henry Hub natural gas spot price averaged $2.64/million British thermal units (MMBtu) in May, almost unchanged from April. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices will average $2.77/MMBtu in 2019, down 38 cents/MMBtu from 2018. EIA expects natural gas prices in 2020 will again average $2.77/MMBtu.
  • EIA forecasts that U.S. dry natural gas production will average 90.6 billion cubic feet per day (Bcf/d) in 2019, up 7.2 Bcf/d from 2018. EIA expects natural gas production will continue to grow in 2020, albeit at a slower rate, averaging 91.8 Bcf/d next year.
  • U.S. natural gas exports averaged 9.9 Bcf/d in 2018, and EIA forecasts that they will rise by 2.5 Bcf/d in 2019 and by 2.9 Bcf/d in 2020. Rising exports reflect increases in liquefied natural gas exports as new facilities come online. Rising natural gas exports are also the result of an expected increase in pipeline exports to Mexico.
  • EIA estimates that natural gas inventories ended March at 1.2 trillion cubic feet (Tcf), 15% lower than levels from a year earlier and 28% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the 2019 April-through-October injection season and that inventories will reach almost 3.8 Tcf at the end of October, which would be 17% higher than October 2018 levels and about equal to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts that the share of generation from coal will average 24% in 2019 and 23% in 2020, down from 27% in 2018. The forecast nuclear share of generation falls from 20% in 2019 to 19% in 2020, reflecting the retirement of some nuclear reactors. Hydropower averages a 7% share of total generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. generation in 2018. EIA expects they will provide 11% in 2019 and 13% in 2020.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and almost 20% in 2020. EIA expects that annual generation from wind will surpass hydropower generation for the first time in 2019 to become the leading source of renewable electricity generation and maintain that position in 2020.
  • EIA forecasts that U.S. coal consumption, which reached a 39-year low of 687 million metric tons (MMst) in 2018, will fall to 602 MMst in 2019 and to 567 MMst in 2020. The falling consumption reflects lower demand for coal in the electric power sector.
  • After rising by 2.7% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.0% in 2019 and by 0.9% in 2020. EIA expects U.S. CO2 emissions will fall in 2019 and in 2020 because its forecast assumes that temperatures will return to near normal, and because the forecast share of electricity generated from natural gas and renewables increases while the forecast share generated from coal, which produces more CO2 emissions, decreases. Energy-related CO2 emissions are sensitive to weather, economic growth, energy prices, and fuel mix.

U.S. natural gas prices


U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

June, 12 2019
Sempra Energy ships first liquefied natural gas cargo from Cameron LNG export facility

U.S. LNG export capacity

Source: U.S. Energy Information Administration, U.S. liquefaction capacity database

On May 31, 2019, Sempra Energy, the majority owner of the Cameron liquefied natural gas (LNG) export facility, announced that the company had shipped its first cargo of LNG, becoming the fourth such facility in the United States to enter service since 2016. Upon completion of Phase 1 of the Cameron LNG project, U.S. baseload operational LNG-export capacity increased to about 4.8 billion cubic feet per day (Bcf/d).

Cameron LNG’s export facility is located in Hackberry, Louisiana, next to the company’s existing LNG-import terminal. Phase 1 of the project includes three liquefaction units—referred to as trains—that will export a projected 12 million tons per year of LNG exports, or about 1.7 Bcf/d.

Train 1 is currently producing LNG, and the first LNG shipment departed the facility aboard the ship Marvel Crane. The facility will continue to ship commissioning cargos until it receives approval from the Federal Energy Regulatory Commission to begin commercial shipments. Commissioning cargos refer to pre-commercial cargo loaded while export facility operations are still undergoing final testing and inspection. Trains 2 and 3 are expected to come online in the first and second quarters of 2020, according to Sempra Energy’s first-quarter 2019 earnings call.

Cameron LNG has regulatory approval to expand the facility through two additional phases, which involve the construction of two additional liquefaction units that would increase the facility’s LNG capacity to about 3.5 Bcf/d. These additional phases do not have final investment decisions.

Cameron LNG secured an authorization from the U.S. Department of Energy to export LNG to Free Trade Agreement (FTA) countries as well as to countries with which the United States does not have Free Trade Agreements (non-FTA countries). A considerable portion of the LNG shipments is expected to fulfill long-term contracts in Asian countries, similar to other LNG-export facilities located in the Gulf of Mexico region.

Cameron LNG will be the fourth U.S. LNG-export facility placed into service since February 2016. LNG exports rose steadily in 2016 and 2017 as liquefaction trains at the Sabine Pass LNG-export facility entered service, with additional increases through 2018 as units entered service at Cove Point LNG and Corpus Christi LNG. Monthly exports of LNG exports reached more than 4.0 Bcf/d for the first time in January 2019.

U.S. LNG exports

Source: U.S. Energy Information Administration, Natural Gas Monthly

Currently, two additional liquefaction facilities are being commissioned in the United States—the Elba Island LNG in Georgia and the Freeport LNG in Texas. Elba Island LNG consists of 10 modular liquefaction trains, each with a capacity of 0.03 Bcf/d. The first train at Elba Island is expected to be placed into service in mid-2019, and the remaining nine trains will be commissioned sequentially during the following months. Freeport LNG consists of three liquefaction trains with a combined baseload capacity of 2.0 Bcf/d. The first train is expected to be placed in service during the third quarter of 2019.

EIA’s database of liquefaction facilities contains a complete list and status of U.S. liquefaction facilities.

June, 12 2019