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Market Watch

Headline crude prices for the week beginning 5 March 2017 – Brent: US$65/b; WTI: US$62/b

  • Crude oil prices began the week on a stronger note, bouncing back from market jitters of American plans to impose steep tariffs on steel and aluminium imports to trade on indications that US crude inventories continue to fall.
  • Tanks at the important storage hub in Cushing, Oklahoma are at their lowest levels since 2014, as a booming American economy and backwardisation structure in futures trading encouraging drawdowns.
  • However, despite the fall in Cushing, overall US crude stockpiles rose more than expected – up by a preliminary estimate of 5.66 million barrels - providing some drag to the market.
  • The US is expected to become the world’s largest oil producer in 2019, overtaking Russia, with Saudi Arabia remaining the world’s largest exporter for the foreseeable future.
  • The upward march of American output remains the single largest drag on crude prices, and a key variable in determining direction, as the EIA confirmed that American production shattered a 47-year old output record last November, hitting 10.044 mmb/d.
  • OPEC commented that while it was committed to ensuring the market was rebalance by mid-2018, it warned that there was a risk of an ‘upcoming energy crisis’, sown by the current seeds of under-investment.
  • The US active oil rig count hit 800 for the first time in almost three years, gaining a single site. Along with 2 new gas rigs, the US rig count stands at 981 as of last Friday.
  • Crude price outlook: Crude prices should stay steady this week, with prices in the US$65-66/b range for Brent and US$62-63/b for WTI.

Headlines of the week

Upstream

  • The hits keep coming for ExxonMobil in Guyana, as it and partner Hess made a seventh major offshore discovery in two years in the Pacora-1 well. Development will be folded into the plans for the Payara field, which should bring Guyanese output up to a potential 500,000 bpd.
  • While Turkey squabbles with Cyprus over gas fields, Greece is hoping to make its own discoveries, sanctioning development of four blocks in the west of the country by Total, Italy’s Edison and Hellenic Petroleum.
  • Mexico will be hoping that the shale revolution can begin within its borders, as it offers up nine onshore areas in Tamaulipas state that will be awarded to private firms for the first time in September.
  • Thawing relations with China, The Philippines has identified two offshore sites – SC-57 and SC-72 at Reed Bank – which could be prototypes for proposed joint upstream activities with China.
  • Bolivia’s YPFB has reportedly signed an MoU with Dubai’s Kampac Oil and London’s Milner Capital to jointly invest US$2.5 billion to developing the Madre de Dios oil and gas basin in northern Bolivia.
  • Japan’s Inpex has been awarded a 10% interest in Abu Dhabi’s Lower Zakum concession for 40 years; separately, Inpex’s stake in the Satah and Umm al Dalkh concession has also been extended for 25 years.

Downstream

  • After years of delays, Vietnam’s second oil refinery in Nghi Son is ready for commercial startup in April, processing Kuwaiti crude. The country’s third refinery, in Long Son, also broke ground last week.
  • Total is aiming to build and operate a 150 kb/d greenfield refinery in Iraq, which would be linked to the Nassirya oilfield. Originally planned for 300 kb/d, PetroChina and Lukoil are also reportedly interested.
  • Poland’s plan to push for a merger of its two state oil refiners – PKN Orlen and Lotos – has met with intense political opposition once again.
  • Tullow Oil and its partners expects to finalise the construction of an export pipeline – linking the inland Amosing and Ngamia fields to the port of Lamu – by mid-2018, clearing the way for output to begin in 2022.

Natural Gas/LNG

  • While there has been no damage to ExxonMobil’s gas pipeline in Papua New Guinea after a 7.5 magnitude quake, it will take 8 weeks to repair and restore production at the PNG LNG plant, with ExxonMobil declaring force majeure on all exports as it continues to assess damage to gas fields.
  • Dominion Energy’s Cove Point export terminal in Maryland, USA has been cleared for commercial startup, shipping its first LNG cargo to Europe, becoming the second American LNG export facility to operate.
  • Timor Leste and Australia are on the verge of agreeing on a permanent maritime border at the Permanent Court of Arbitration, paving the way to develop the Greater Sunrise offshore gas field that had been shelved previously due to disputed oceanic borders. 
  • There may finally be some movement in the Philippines’ planned LNG import facility, as four potential investors – including Tokyo Gas and domestic power player First Gen – have reportedly expressed interest.
  • Japan’s Jera and Marubeni are reportedly teaming up with Australia’s Fortescue Metals to build a 2 mtpa LNG import terminal in New South Wales, which would help ease the east coast natural gas crunch.
  • India has begun to receive its first US LNG as Cheniere begins its 20-year contract with GAIL, supplying 3.5 mtpa of LNG per year.

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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