NrgEdge Editor

Sharing content and articles for users
Last Updated: January 26, 2018
1 view
Business Trends
image

In its latest Short-Term Energy Outlook (STEO), EIA expects the Henry Hub natural gas spot price to average $2.88 per million British thermal units (MMBtu) in 2018 and $2.92/MMBtu in 2019, slightly lower than the 2017 average of $2.99/MMBtu. Lower prices in 2018 and 2019 reflect EIA’s expectation of increased natural gas production and relatively flat consumption.


The confidence interval range for natural gas prices shown in the figure above is a market-derived range that reflects trading in New York Mercantile Exchange (NYMEX) futures and options markets and is not directly dependent on EIA's supply and demand estimates. The values for the upper confidence interval increase during the winter months compared with the rest of the year, reflecting the higher probability of an increase in natural gas consumption for space heating as a result of colder weather.

graph of annual U.S. natural gas consumption and production, as explained in the article text

Source: U.S. Energy Information Administration, Short-Term Energy Outlook


EIA expects natural gas consumption will increase slightly in both 2018 and 2019. On an annual basis, EIA expects combined residential and commercial natural gas consumption to increase by 1.3 billion cubic feet per day (Bcf/d) in 2018 because of colder weather closer to the recent historical average after a very warm early 2017, then remain nearly the same in 2019.


In 2018, the STEO forecasts increasing use of natural gas for electric power generation because of low natural gas prices. Natural gas-fired power generation is also expected to increase in 2019 because of growth in total electricity generation—fueled in part by increased natural gas-fired capacity—and anticipated coal-fired retirements.


EIA forecasts dry natural gas production to increase in both 2018 and 2019, exceeding domestic consumption of natural gas for the first time since 1966. EIA projects production growth to be concentrated in Appalachia’s Marcellus and Utica regions and in the Permian region, where oil production results in associated natural gas production.


Increasing pipeline takeaway capacity out of the Appalachia region, expected to increase by 8.4 Bcf/d by spring 2018, will deliver natural gas to end-use markets. Greater pipeline connectivity reduces spot market discounts to Henry Hub, the main price benchmark for natural gas, and is expected to result in higher wellhead natural gas prices and production growth.

graph of annual U.S. natural gas trade, as explained in the article text

Source: U.S. Energy Information Administration, Short-Term Energy Outlook


The United States became a net exporter of natural gas on an annual basis for the first time in 2017, with net exports averaging 0.4 Bcf/d. This trend is expected to continue, with net natural gas exports forecast to average 2.3 Bcf/d in 2018 and 4.6 Bcf/d in 2019.


Most of the projected increase in U.S. natural gas exports is expected to come from exports of liquefied natural gas(LNG). EIA expects gross exports of LNG to average 3.0 Bcf/d in 2018 and 4.8 Bcf/d in 2019, up from 1.9 Bcf/d in 2017, as new export terminals in Maryland, Georgia, Texas, and Louisiana come online. Exports of natural gas by pipeline to Mexico are expected to increase by 0.6 Bcf/d and 0.8 Bcf/d in 2018 and 2019, respectively, with total pipeline exports averaging 8 Bcf/d in 2019. By 2019, exports of natural gas by pipeline slightly exceed imports of natural gas by pipeline.

3
0 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

U.S. natural gas production, consumption, and exports set new records in 2018

U.S. natural gas dry production, consumption, and exports

Source: U.S. Energy Information Administration, Natural Gas Annual 2018

The U.S. Energy Information Administration’s (EIA) Natural Gas Annual 2018 shows that the United States set new records in natural gas production, consumption, and exports in 2018. In 2018, dry natural gas production increased by 12%, reaching a record-high average of 83.8 billion cubic feet per day (Bcf/d). This increase was the largest percentage increase since 1951 and the largest volumetric increase in the history of the series, which dates back to 1930. U.S. natural gas consumption increased by 11% in 2018, driven by increased natural gas consumption in the electric power sector. Natural gas gross exports totaled 10.0 Bcf/d in 2018, 14% more than the 2017 total of 8.6 Bcf/d. Several new liquefied natural gas (LNG) export facilities came online in 2018, allowing for more exports.

U.S. consumption of natural gas by sector

Source: U.S. Energy Information Administration, Natural Gas Annual 2018

U.S. natural gas consumption grew in each end-use sector. Demand for natural gas as a home heating fuel was greater in 2018 than in 2017 because of slightly colder weather during most of the winter. Similarly, the summer of 2018 saw record-high temperatures that increased demand for air conditioning and, therefore, electricity—much of which was fueled by natural gas. U.S. electric power sector consumption of natural gas grew by 14% in 2017, more than in any other end-use sector. The electric power sector has been shifting toward natural gas in the past decade because of favorable prices and efficiency gains.

dry natural gas production by state for 2017 and 2018

Source: U.S. Energy Information Administration, Natural Gas Annual 2018

U.S. natural gas production growth was concentrated in the Appalachian, Permian, and Haynesville regions. Pennsylvania and Ohio, states that overlay the Appalachian Basin, had the first- and third-largest year-over-year increases for 2018, increasing by 2.0 Bcf/d and 1.7 Bcf/d, respectively. Louisiana had the second-largest volumetric increase in dry production, increasing by 1.8 Bcf/d as a result of increased production from the Haynesville shale formation. Texas remained the top natural gas-producing state, with a production level of 18.7 Bcf/d, as a result of continued drilling activity in the Permian Basin in western Texas and eastern New Mexico.

November, 18 2019
Your Weekly Update: 11 - 15 November 2019

Market Watch  

Headline crude prices for the week beginning 11 November 2019 – Brent: US$62/b; WTI: US$56/b

  • The trade war between the US and China – and its implications on the rest of the global economy – continue to weigh down on crude oil prices, as varying indications from American and Chinese authorities paint a sketchy picture of how, or when, the trade dispute could be resolved
  • Mild improvement in US and China manufacturing and job offered hope for a respite, but the broader picture is still negative, particularly in India where a worsening economy is tampering fuel demand growth and triggering a diesel glut
  • With OPEC and the OPEC+ club preparing to meet in Vienna in three weeks, words from within the group are that the largest and most influential producers are not pushing for deeper cuts but will instead emphasise greater adherence to the current supply deal that is set to expire in March 2020
  • This comes as OPEC predicts that US shale will continue to steal its market share through 2023, making the prospect of further cuts unpalatable to members who are loathed to further sacrifice volumes amid weak prices
  • In Venezuela – where tumbling output has thus far made the OPEC task of curbing output easier – production and exports seem to have steadied, with international shipments exceeding 800,000 b/d for the second month in a row in October; most volumes going to China and Rosneft under barter deals
  • In the Persian Gulf, where the Iran situation is another potential flashpoint, a US-led multinational coalition has begun patrolling the vital shipping lane to prevent attacks and threats in the critical seabourne oil distribution pathway
  • Signs that US crude output is heading for a period of tempered growth after explosive growth seem to be confirmed by the chronic deterioration in the active US rig count; 7 oil rigs stopped operation, bringing the total count to 817 – the lowest number in 31 months
  • Until there is more clarity on the US-China trade situation or the outcome of the December OPEC meeting in Vienna, crude oil prices are likely to stay rangebound at US$60-63/b for Brent and US$56-59/b for WTI – not high enough to please producers, but not low enough to prompt decisive action


Headlines of the week

Upstream

  • Adnoc is aiming to start trading of its new Murban crude futures contract on the Abu Dhabi exchange in Q2 or Q3 2020, aiming to create a new price benchmark for Middle Eastern crudes while lifting destination restrictions on the grade
  • Hungary’s MOL Group has bought out Chevron’s interests in Azerbaijan for US$1.57 billion, acquiring a 9.57% stake in the Azeri-Chirag-Gunashli (ACG) field and an 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline
  • Equinor – along with partners ExxonMobil, Idemitsu and Neptune – have announced a new oil find in the North Sea at the Echino South well in the Fram field, with recoverable resources estimated at 38-100 million boe
  • The Ivory Coast has launched a new licensing round, covering five offshore blocks located near existing discoveries and infrastructure
  • The Canadian province of Alberta is loosening its crude oil production limits once again after a severe lack of pipeline capacity strained production last year by exempting new conventional wells from current output caps; Alberta currently allows producers to exceed their limits if shipping the excess by rail
  • Kosmos Energy has announced a new offshore oil discovery in Equatorial Guinea at the S-5 well of the Santonian reservoir in the Rio Muni Basin
  • Equinor is exiting Eagle Ford, selling its 63% interest and operatorship of its onshore shale plays in the area to Spain’s Repsol for US$325 million
  • As Total’s offshore Brulpadda discovery in South Africa moves ahead, the challenging geography of the Paddavissie play may require a fixed platform

Midstream/Downstream

  • South Africa’s Central Energy Fund and Saudi Aramco are collaborating on a new 300 kb/d refinery at Richards Bay that is expected to come onstream by 2028 as the largest oil refinery in the southern Africa region
  • The Chevron-SPC Singapore Refining Co joint venture delivered its first cargo of very low sulfur fuel oil in October in Asia’s key bunkering hub, ahead of the IMO deadline for marine fuel oil sulfur content kicking in in January
  • The refurbishment of the idled St Croix refinery in the US Virgin Islands is on track for completion in early 2020, reducing capacity by a third to 210 kb/d but increasing capacity for cleaner fuels, particular for marine usage
  • Husky Energy has completed the sale of its 12 kb/d Prince George refinery in Canada’s British Columbia to Tidewater for US$215 million

Natural Gas/LNG

  • The Port Kembla LNG import terminal in Australia’s New South Wales is facing delays, as Australian Industrial Energy and Japan’s JERA struggle to lock in customers to make the project commercially viable
  • Having taken over Anadarko’s interest in the Mozambique LNG project, Total is now looking to expand the export terminal with two additional trains, which could double capacity from a current planned 12.9 million tpa
  • The OMV/ETAP Nawara gas field in Tunisia is on track to produce first natural gas by end-2019, with capacity of 2.7 mcm/d boosting the country’s gas output by 50% and slashing gas imports by some 30%
  • After years of delays, the site for Indonesia and Inpex’s 9.5 million tpa Abadi LNG project has been decided as Yamdena island in the Arafura Sea

Corporate

  • Total will be exiting a key American industrial lobby group, following in the footsteps of Shell as it claims a divergent outlook on climate change issues
November, 15 2019
Brazil Needs a “Makeover” For Future Oil Bids

The year’s final upstream auctions were touted as a potential bonanza for Brazil, with pre-auction estimates suggesting that up to US$50 billion could be raised for some deliciously-promising blocks. The Financial Times expected it to be the ‘largest oil bidding round in history’. The previous auction – held in October – was a success, attracting attention from supermajors and new entrants, including Malaysia’s Petronas. Instead, the final two auctions in November were a complete flop, with only three of the nine major blocks awarded.

What happened? What happened to the appetite displayed by international players such as ExxonMobil, Shell, Chevron, Total and BP in October? The fields on offer are certainly tempting, located in the prolific pre-salt basin and including prized assets such as the Buzios, Itapu, Sepia and Atapu fields. Collectively, the fields could contain as much as 15 billion barrels of crude oil. Time-to-market is also shorter; much of the heavy work has already been done by Petrobras during the period where it was the only firm allowed to develop Brazil’s domestic pre-salt fields. But a series of corruption scandals and a new government has necessitated a widening of that ambition, by bringing in foreign expertise and, more crucially, foreign money. But the fields won’t come cheap. In addition to signing bonuses to be paid to the Brazilian state ranging from US$331 million to US$17 billion by field, compensation will need to be paid to Petrobras. The auction isn’t a traditional one,  but a Transfer of Rights sale covering existing in-development and producing fields.

And therein lies the problem. The massive upfront cost of entry comes at a time when crude oil prices are moderating and the future outlook of the market is uncertain, with risks of trade wars, economic downturns and a move towards clean energy. The fact that the compensation to be paid to Petrobras would be negotiated post-auction was another blow, as was the fact that the auction revolved around competing on the level of profit oil offered to the Brazilian government. Prior to the auction itself, this arrangement was criticised as overtly complicated and ‘awful’, with Petrobras still retaining the right of first refusal to operate any pre-salt fields A simple concession model was suggested as a better alternative, and the stunning rebuke by international oil firms at the auction is testament to that. The message is clear. If Brazil wants to open up for business, it needs to leave behind its legacy of nationalisation and protectionism centring around Petrobras. In an ironic twist, the only fields that were awarded went to Petrobras-led consortiums – essentially keeping it in the family.

There were signs that it was going to end up this way. ExxonMobil – so enthusiastic in the October auction – pulled out of partnering with Petrobras for Buzios, balking at the high price tag despite the field currently producing at 400,000 b/d. But the full-scale of the reticence revealed flaws in Brazil’s plans, with state officials admitting to being ‘stunned’ by the lack of participation. Comments seem to suggest that Brazil will now re-assess how it will offer the fields when they go up for sale again next year, promising to take into account the reasons that scared international majors off in the first place. Some US$17 billion was raised through the two days of auction – not an insignificant amount but a far cry from the US$50 billion expected. The oil is there. Enough oil to vault Brazil’s production from 3 mmb/d to 7 mmb/d by 2030. All Brazil needs to do now is create a better offer to tempt the interested parties.

Results of Brazil’s November upstream auctions:

  • 6 November: Four blocks on offer, two awarded (Buzios, 90% Petrobras 5% CNOOC 5% CNODC ; Itapu, 100% Petrobras)
  • 7 November: Five blocks on offer, one awarded (Aram, 80% Petrobras 20% CNOOC)
November, 14 2019