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Last Updated: October 25, 2019
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Market Watch  

Headline crude prices for the week beginning 21 October 2019 – Brent: US$59/b; WTI: US$53/b

  • Crude prices remain rangebound, with the market focused on a fragile economic outlook as major economies across the globe show signs of slowing growth
  • In particular, this has been focused on trade relations between the US and China; a sudden thaw in negotiations lead to what the US has described as a ‘partial deal’, with China offering to make additional agricultural purchases in exchange for a freeze on new tariffs – but a full deal still remains far off
  • Calculations by the IEA, EIA and OPEC also point to the need for OPEC+ to make another cut by December, giving the current build in global oil inventories; whether or not the hurting OPEC members agreed to the cuts at the December meeting, however, is another question
  • Not helping the situation is the fact the US crude production is accelerating – with Gulf of Mexico production rising to a new annual record of 1.8 mmb/d and US shale production expected to hit 9 mmb/d by the end of the year
  • However, soaring oil tanker rates – which is good news for beleaguered shippers – is clamping down on US exports, as Asian buyers are choosing to buy crude from closer to home; global shipping rates have been surging since the US imposed sanctions on Chinese shipowners, including COSCO, for breaching US sanctions on Iran
  • In Venezuela, the US is taking a softer stance – having extended sanctions exemptions for a Nynas-PDVSA biofuels joint venture and also close to extending the waiver for Chevron to operate (but with more conditions)
  • The White House will be losing its Energy Secretary, as Rick Perry will resign by the end of 2019, having brokered a new biofuels mandate that tries to appease both American refiners and farmers
  • After a brief rise, the US active rig count is back in the red, losing six gas rigs but gaining one oil rig for a net loss of five, bringing the total active rig count to 851
  • Bullish data released by the US government mid-week sent prices higher, but wider worries over the global economy will continue to cap any gains; Brent should trade in the US$59-61/b range and WTI in the US$54-56/b range

Headlines of the week

Upstream

  • At the recent deepwater auction in Brazil, Total and its partners led the sale by taking the high-profile Block C-M-541 – home of the Nemo prospect – while Malaysia’s Petronas made its debut by focusing on the Campos basin
  • Equinor has won a new exploration permit in Australia, gaining the WA-542-P site in the offshore Northern Carnarvon Basin, west of the recent Dorado strike
  • Energean Oil and Gas will be selling its North Sea assets – held by Edison E&P UK and Norway – to the Neptune Energy Group for US$250 million
  • Nigeria’s government has passed a new amendment to its Production Sharing Contract, raising royalties sharply and throwing a number of major deepwater projects into questionable territory
  • Algeria has passed a new law aimed at boosting investment in its upstream sector by cutting taxes but has triggered widespread civil protests

Midstream/Downstream

  • Having courting Eni and Austria’s OMV for upstream projects, ADNOC is now looking to persuade the two European firms to partner on its refining projects that are meant to expand capacity from 922 kb/d to 1.5 mmb/d by 2025
  • Singapore’s APEX has launched a new low-sulfur fuel oil (LSFO) contract, just ahead of the deadline for new IMO regulations on marine fuels to kick in
  • Chinese crude processing volumes reached a new high of 13.75 mmb/d in September as new integrated mega-refineries on the coast began operations

Natural Gas/LNG

  • Santos has agreed to purchase ConocoPhillips’ upstream gas assets in northern Australia for US$1.4 billion, gaining COP’s operating interests in the Darwin LNG plant and the Bayu Undan, Barossa and Poseiden gas fields
  • Total will be spending US$600 million to expand its presence in India’s LNG market, purchasing a 37.4% in domestic gas distributor Adani Gas, which is currently developing the Mundra and Dhamra LNG import terminals
  • Dominion Energy will sell a 25% interest in the Cove Point LNG project in Maryland to Brookfield Asset Management for some US$2 billion in cash
  • US regulators have proposed to loosen transport rules that would allow LNG to be transported by rail in hopes of connecting inland gas to coastal export hubs
  • Equinor has downgraded recoverable reserve estimates at the UK-Norway cross-border Utgard gas and condensate field by nearly 30% to 40 million boe
  • DTE Energy has purchased the Momentum Midstream and Indigo Natural Resources’ natural gas gathering system and pipeline in Louisiana for US$2.25 billion, adding to its distribution capacity along the US Gulf Coast
  • Lukoil has taken a 5% stake in the Ghasha ultra-sour 1.5 bcf/d gas mega-project in Abu Dhabi – made up of the Hail, Ghasha, Dalma and other fields – marking the first time a Russian firm has joined an ADNOC concession
  • The US Department of Energy has approved the Plaquemines LNG project in Louisiana for exports, allowing it to export up to 3.4 bcf/d of LNG

Corporate

  • Schlumberger announced that it was taking a huge write-down of US$12.7 billion in its latest financial earnings report, mainly from a US$8.8 billion goodwill hit from its acquisition of Cameron International Corp in 2016
  • Saudi Aramco has once again delayed its IPO, after having planned for an October 20 launch, citing time required to give potential investors more clarity after the recent crippling attacks on its Abqaiq processing plant

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January, 24 2020
EIA expects U.S. net natural gas exports to almost double by 2021

In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.

The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.

In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.

Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.

U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:

  • Pipelines in Central and Southwest Mexico (1.2 Bcf/d La Laguna–Aguascalientes and 0.9 Bcf/d Villa de Reyes–Aguascalientes–Guadalajara)
  • Pipelines in Western Mexico (0.5 Bcf/d Samalayuca–Sásabe)

U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:

  • Trains 2 and 3 at Cameron LNG in Louisiana
  • Train 3 at Freeport LNG in Texas
  • Trains 5–10, six Moveable Modular Liquefaction System (MMLS) units, at Elba Island in Georgia

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.

monthly natural gas trade

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

January, 24 2020
EIA forecasts U.S. crude oil production growth to slow in 2021

In the January 2020 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that U.S. crude oil production will average 13.3 million barrels per day (b/d) in 2020, a 9% increase from 2019 production levels, and 13.7 million b/d in 2021, a 3% increase from 2020. Slowing crude oil production growth results from a decline in drilling rigs during the past year that EIA expects will continue through most of 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rise, offsetting the decline in the number of rigs until drilling activity accelerates in 2021.

Figure 1. U.S. crude oil production

EIA’s U.S. crude oil production forecast is based on the West Texas Intermediate (WTI) price forecast in the January 2020 STEO, which rises from an average of $57 per barrel (b) in 2019 to an average of $59/b in 2020 and $62/b in 2021. The price forecast is highly uncertain, and any significant divergence of actual prices from the projected price path could change the pace of drilling and new well completion, which would in turn affect production.

Crude oil production in the Lower 48 states has a relatively short investment and production cycle. Changes in Lower 48 crude oil production typically follow changes in crude oil prices and rig counts with about a four- to six-month lag. Because EIA forecasts WTI prices will decline during the first half of 2020 but begin increasing in the second half of the year and into 2021, forecast U.S. crude oil production grows slowly month over month until the end of 2020. In contrast, crude oil production in Alaska and the Federal Offshore Gulf of Mexico (GOM) is driven by long-term investment that is typically less sensitive to short-term price movements.

In 2019, Lower 48 production reached its largest annual average volume of 9.9 million b/d, and EIA expects it to increase further by an average of 1.0 million b/d in 2020 and 0.4 million b/d in 2021. EIA forecasts the GOM region will grow by 0.1 million b/d in 2020 to 2.0 million b/d and to remain relatively flat in 2021 because several projects expected to come online in 2021 will not start producing until late in the year and will be offset by declines from other producing fields. Alaska’s crude oil production will remain relatively unchanged at about 0.5 million b/d in 2020 and in 2021.

The Permian region remains the most prolific growth region in the United States. Favorable geology combined with technological improvements have contributed to the Permian region’s high returns on investment and years of remaining oil production growth potential. EIA forecasts that Permian production will average 5.2 million b/d in 2020, an increase of 0.8 million b/d from 2019 production levels. For 2021, the Permian will produce an average of 5.6 million b/d. EIA forecasts that the Bakken region in North Dakota will be the second-largest growth area in 2020 and 2021, growing by about 0.1 million b/d in each year (Figure 2).

Figure 2. Monthly U.S. crude oil production by region

EIA expects crude oil prices higher than $60/b in 2021 will contribute to rising crude oil production because producers will be able to fund drilling programs through cash flow and other funding sources, despite a somewhat more restrictive capital market. Financial statements of 46 publically-traded U.S. oil producers reveal that these companies generated sufficient cash from operating activities to fund investment and grow production with WTI prices in the $55/b–$60/b range. The 46 selected companies produced more than 30% of total U.S. liquids production in the third quarter of 2019. The four-quarter moving average free cash flow for these companies ranged between $1.7 billion and $3.5 billion from the fourth quarter of 2017 through the second quarter of 2019. The third quarter of 2019—the latest quarter for which data are available—had less cash from operations than investing activities, but this figure was skewed by the large, one-time acquisition cost of Anadarko Petroleum by Occidental, valued at $55 billion (Figure 3).

Figure 3. Cash flow statement items for 46 U.S. oil producers

Results for these 46 publicly traded companies do not represent all U.S. oil producers because private companies that do not publish financial statements are not included in EIA’s analysis. The Federal Reserve Bank of Dallas Energy Survey sheds some light on the financial position of a broader set of companies. Released quarterly, the bank’s survey asks oil companies about business activity and employment and asks a few special questions that change each quarter. The number of companies that participate varies each quarter, but generally the survey includes about 100 exploration and production companies. In the most recent survey (from the fourth quarter of 2019), 75% of survey respondents said they can cover their capital expenditures through cash flow from operations at a WTI price of less than $60/b. In addition, 40% of survey respondents plan to increase capital expenditures in 2020 compared with 2019, while 24% of respondents expect to spend about the same (Figure 4).

Figure 4. Selected questions from the Federal Reserve Bank of Dallas' Energy Survey

Since about 2017, large, globally integrated oil companies have acquired more acreage in Lower 48 regions, particularly in the Permian. These companies have announced investment plans to make Lower 48 production an increasing portion of their portfolios. These companies can typically fund their investment programs through cash flow from operations and are generally less susceptible to tighter capital markets than smaller oil companies. The financial results of the public companies shown in Figure 3 and the Federal Reserve survey support EIA’s production forecast and suggest that U.S. crude oil production can continue to grow under EIA’s price forecast for 2020 and 2021 because many companies are less dependent on debt or equity to fund investment.

U.S. average regular gasoline and diesel prices decline

The U.S. average regular gasoline retail price fell more than 3 cents from the previous week to $2.54 per gallon on January 20, 29 cents higher than the same time last year. The Midwest price fell over 5 cents to $2.39 per gallon, the Gulf Coast price fell nearly 5 cents to $2.23 per gallon, the Rocky Mountain price fell more than 3 cents to $2.57 per gallon, the East Coast price fell more than 2 cents to $2.50 per gallon, and the West Coast price fell nearly 2 cents to $3.18 per gallon.

The U.S. average diesel fuel price fell nearly 3 cents from the previous week to $3.04 per gallon on January 20, 7 cents higher than a year ago. The Rocky Mountain price fell nearly 6 cents to $3.01 per gallon, the East Coast price fell nearly 4 cents to $3.08 per gallon, the Midwest price declined almost 3 cents to $2.94 per gallon, the West Coast price fell nearly 2 cents to $3.57 per gallon, and the Gulf Coast price dropped more than 1 cent to $2.80 per gallon.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 1.4 million barrels last week to 86.5 million barrels as of January 17, 2020, 17.1 million barrels (24.6%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, East Coast, Gulf Coast, and Rocky Mountain/West Coast inventories decreased by 0.7 million barrels, 0.4 million barrels, 0.2 million barrels, and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 6.9% of total propane/propylene inventories.

Residential heating fuel prices decrease

As of January 20, 2020, residential heating oil prices averaged nearly $3.07 per gallon, 3 cents per gallon below last week’s price and 10 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged almost $1.96 per gallon, more than 7 cents per gallon below last week’s price and more than 7 cents per gallon lower than a year ago.

Residential propane prices averaged almost $2.01 per gallon, less than 1 cent per gallon below last week’s price and more than 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.60 per gallon, nearly 4 cents per gallon lower than last week’s price and 20 cents per gallon below last year’s price.

January, 24 2020