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.
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.
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.
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According to the Nigeria National Petroleum Corporation (NNPC), Nigeria has the world’s 9th largest natural gas reserves (192 TCF of gas reserves). As at 2018, Nigeria exported over 1tcf of gas as Liquefied Natural Gas (LNG) to several countries. However domestically, we produce less than 4,000MW of power for over 180million people.
Think about this – imagine every Nigerian holding a 20W light bulb, that’s how much power we generate in Nigeria. In comparison, South Africa generates 42,000MW of power for a population of 57 million. We have the capacity to produce over 2 million Metric Tonnes of fertilizer (primarily urea) per year but we still import fertilizer. The Federal Government’s initiative to rejuvenate the agriculture sector is definitely the right thing to do for our economy, but fertilizer must be readily available to support the industry. Why do we import fertilizer when we have so much gas?
I could go on and on with these statistics, but you can see where I’m going with this so I won’t belabor the point. I will leave you with this mental image: imagine a man that lives with his family on the banks of a river that has fresh, clean water. Rather than collect and use this water directly from the river, he treks over 20km each day to buy bottled water from a company that collects the same water, bottles it and sells to him at a profit. This is the tragedy on Nigeria and it should make us all very sad.
Several indigenous companies like Nestoil were born and grown by the opportunities created by the local and international oil majors – NNPC and its subsidiaries – NGC, NAPIMS, Shell, Mobil, Agip, NDPHC. Nestoil’s main focus is the Engineering Procurement Construction and Commissioning of oil and gas pipelines and flowstations, essentially, infrastructure that supports upstream companies to produce and transport oil and natural gas, as well as and downstream companies to store and move their product. In our 28 years of doing business, we have built over 300km of pipelines of various sizes through the harshest terrain, ranging from dry land to seasonal swamp, to pure swamps, as well as some of the toughest and most volatile and hostile communities in Nigeria. I would be remiss if I do not use this opportunity to say a big thank you to those companies that gave us the opportunity to serve you. The over 2,000 direct staff and over 50,000 indirect staff we employ thank you. We are very grateful for the past opportunities given to us, and look forward to future opportunities that we can get.
Headline crude prices for the week beginning 15 July 2019 – Brent: US$66/b; WTI: US$59/b
Headlines of the week
Unplanned crude oil production outages for the Organization of the Petroleum Exporting Countries (OPEC) averaged 2.5 million barrels per day (b/d) in the first half of 2019, the highest six-month average since the end of 2015. EIA estimates that in June, Iran alone accounted for more than 60% (1.7 million b/d) of all OPEC unplanned outages.
EIA differentiates among declines in production resulting from unplanned production outages, permanent losses of production capacity, and voluntary production cutbacks for OPEC members. Only the first of those categories is included in the historical unplanned production outage estimates that EIA publishes in its monthly Short-Term Energy Outlook (STEO).
Unplanned production outages include, but are not limited to, sanctions, armed conflicts, political disputes, labor actions, natural disasters, and unplanned maintenance. Unplanned outages can be short-lived or last for a number of years, but as long as the production capacity is not lost, EIA tracks these disruptions as outages rather than lost capacity.
Loss of production capacity includes natural capacity declines and declines resulting from irreparable damage that are unlikely to return within one year. This lost capacity cannot contribute to global supply without significant investment and lead time.
Voluntary cutbacks are associated with OPEC production agreements and only apply to OPEC members. Voluntary cutbacks count toward the country’s spare capacity but are not counted as unplanned production outages.
EIA defines spare crude oil production capacity—which only applies to OPEC members adhering to OPEC production agreements—as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices. EIA does not include unplanned crude oil production outages in its assessment of spare production capacity.
As an example, EIA considers Iranian production declines that result from U.S. sanctions to be unplanned production outages, making Iran a significant contributor to the total OPEC unplanned crude oil production outages. During the fourth quarter of 2015, before the Joint Comprehensive Plan of Action became effective in January 2016, EIA estimated that an average 800,000 b/d of Iranian production was disrupted. In the first quarter of 2019, the first full quarter since U.S. sanctions on Iran were re-imposed in November 2018, Iranian disruptions averaged 1.2 million b/d.
Another long-term contributor to EIA’s estimate of OPEC unplanned crude oil production outages is the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. Production halted there in 2014 because of a political dispute between the two countries. EIA attributes half of the PNZ’s estimated 500,000 b/d production capacity to each country.
In the July 2019 STEO, EIA only considered about 100,000 b/d of Venezuela’s 130,000 b/d production decline from January to February as an unplanned crude oil production outage. After a series of ongoing nationwide power outages in Venezuela that began on March 7 and cut electricity to the country's oil-producing areas, EIA estimates that PdVSA, Venezuela’s national oil company, could not restart the disrupted production because of deteriorating infrastructure, and the previously disrupted 100,000 b/d became lost capacity.