Oil supply could easily be threatened by geopolitical risks, and such a disruption could cause oil prices to skyrocket, experts tell CNBC.
Natural gas futures initially rallied on Thursday, following the release of a government report that showed natural gas in storage fell inside the expected range last week. However, the buying wasn’t strong enough to sustain the move and prices retreated into the close.
The price action strongly suggests there are a lot more shorts in the market than buyers. It also means that the market is not going to have a prolonged rally until these shorts are taken out and the longs take control.
September Natural Gas futures settled at $2.948, down -0.027 or -0.91%.
According to the U.S. Energy Information Administration (EIA), U.S. natural gas in storage rose by 57 billion cubic feet in the week ended July 7. This was slightly above the mid-point of the 51 bcf to 61 bcf range.
Total natural gas in storage now stands at 2.945 trillion cubic feet, 8.9% lower than levels at this time a year ago and 6.2% above the five-year average for this time of year.
The price action on Thursday indicates that the market is still in the hands of strong sellers. They didn’t seem to be too impressed by the EIA report and they don’t appear to be too nervous about the weather forecast calling for high to very high natural gas demand in most of the U.S. besides the northeastern U.S.
The weather forecast calling for hot high pressure with highs of 90s and 100s has been in the forecast all week. However, the market is trading only slightly higher for the week. This also points to the shorts being in control.
The market is likely to continue to be rangebound over the near-term unless the shorts increase their positions enough to force the weaker longs out of their positions. If this occurs, we could see a break into $2.830 over the near-term.
In order to breakout to the upside, the news is going to have to be bullish enough to take out the shorts and encourage investors to buy strength by chasing the market higher.
The daily chart indicates that an upside bias could develop on a sustained move over $3.006. Upside momentum will pick up on a move over $3.043 with the next potential targets $3.114 and $3.134.
It also shows that the downside bias will resume on a sustained move under $2.935.
Holding inside $2.935 and $3.006 will create a choppy, two-sided trade.
EIA now forecasts Brent crude oil spot prices to average $51 per barrel (b) in 2017 and $52/b in 2018. West Texas Intermediate (WTI) crude oil prices are expected to be $2/b lower than Brent prices in 2017 and 2018. Daily and monthly average prices could vary significantly from this forecast because global economic developments and geopolitical events in the coming months have the potential to push oil prices higher or lower than the current Short-Term Energy Outlook (STEO) price forecast.
For example, EIA's forecast for the average WTI price in October 2017 is $48/b, while the options markets indicate an expected range of WTI prices from $36/b to $60/b (at the 95% confidence interval) based on the recent prices of futures and options contracts for October 2017 delivery.
U.S. crude oil production patterns in the Lower 48 onshore basins continue to vary by region, and quickly evolving trends in this sector can affect both current prices and expectations for future prices. However, lasting price movements could be limited over the next year because some U.S. tight oil producers have used financial instruments to guarantee a price above $50/b for their expected production.
Crude oil prices reached their lowest year-to-date levels in late June. Prices fell after EIA reported builds in total U.S. crude oil and petroleum products inventories that were above the five-year average during the weeks ending June 2 and June 9. The build in total U.S. petroleum inventories for the week ending June 2 was the largest for any week since 2008. Rising Libyan and Nigerian production in June also put downward pressure on prices.
EIA forecasts total U.S. crude oil production to average 9.3 million b/d in 2017, up 0.5 million b/d from 2016. In 2018, crude oil production is forecast to rise to an average of 9.9 million b/d. If achieved, 2018 production would be the highest annual average on record, surpassing the previous record of 9.6 million b/d set in 1970. The 2018 forecast is 0.1 million b/d lower than in last month’s STEO because of lower forecast crude oil prices in late 2017 and in 2018.
Forecast Organization of the Petroleum Exporting Countries (OPEC) crude oil production is expected to fall by 0.2 million b/d in 2017, as OPEC members have limited production based on their November 2016 agreement. In May 2017, this agreement was extended through the first quarter of 2018. Uncertainty remains regarding the duration of and adherence to the current OPEC production cuts, which could influence prices in either direction. EIA’s forecast assumes a further extension of the agreement in 2018 but with lesser compliance. Without a further extension of the OPEC agreement, EIA would expect larger inventory builds and lower prices in 2018 than are included in this forecast.
Global liquids consumption growth is expected to be 1.5 million b/d in 2017 and 1.6 million b/d in 2018. In both years, most of this growth (about 1.2 million b/d annually) comes from countries outside of the Organization for Economic Cooperation and Development (OECD), with China and India expected to be the largest contributors to non-OECD liquid fuels consumption growth. Global oil inventories are forecast to be relatively unchanged in the second half of 2017 before returning to average inventory builds of 0.2 million b/d in 2018.
GALVESTON – The nation's climate agency Thursday predicted an above-normal 2017 hurricane season with 11 to 17 named storms, five to nine of them hurricanes and two to four Category 3 or higher hurricanes.
The National Oceanic and Atmospheric Administration predicted a 45 percent chance of the hurricane season that begins June 1 being above normal, a 35 percent chance of a normal season and a 20 percent chance of a below normal season. An average season is 12 named storms, six hurricanes and 3 major hurricanes.
NOAA's predictions are based on the likelihood of a weak El Nino weather system over Pacific, which when strong causes wind shear that disrupts hurricane formation.
"The outlook reflects our expectation of a weak or non-existent El Nino, near- or above-average sea-surface temperatures across the tropical Atlantic Ocean and Caribbean Sea, and average or weaker-than-average vertical wind shear in that same region," said Gerry Bell, lead seasonal hurricane forecaster with NOAA's Climate Prediction Center.
NOAA releases 21 new storm names for the 2017 hurricane season.
Bell said a strong El Nino causes more intense wind shear, which tends to break up tropical disturbances before they can grow into a hurricane. He cautioned that chances were 50-50 that a stronger El Nino could develop later in the hurricane season, which ends Nov. 30.
He said NOAA's predictions had a 70 percent chance of being correct. NOAA plans to update its outlook in early August, shortly before the peak of the hurricane season.
NOAA's predictions follow two earlier forecasts, one by Colorado State University and one by The Weather Co.
Colorado State University in April predicted 11 named storms, four hurricanes and two major hurricanes. Bell said NOAA does not issue an April prediction because conditions could significantly change by June. The university is scheduled to issue a revised prediction June 1.
The Weather Co. on May 22 predicted 14 named storms, seven hurricanes and three major hurricanes.
All three predictions include Tropical Storm Arlene, a rare pre-season storm that formed in April.
The United States has had a long run of good luck, said Ben Friedman, acting NOAA administrator. "It's been a record 12 years since a Category 3 or higher storm has hit the United States, Friedman said.
A Category 3 storm has winds of from 111 mph to 129 mph.
"Regardless of how many storms develop this year, it only takes one to disrupt our lives," said Robert J. Fenton, acting Federal Emergency Management Administration administrator.
Fenton advised coastal residents to prepare for hurricane season by having a family discussion about what to do, where to go and how to communicate among family members when a storm threatens. He also said it's important to know the evacuation route, tune into local news or download an app from FEMA at www.fema.gov/mobile-app that issues alerts.
As of 2016, the United States had 99 operating nuclear reactors at 61 plants across the country, with a capacity-weighted average age of 37 years. The oldest operating nuclear reactor in the United States was built in 1969. Watts Bar 2, which entered commercial service in 2016, was the first new reactor added since 1996. An additional four reactors are currently under construction. Operation of nuclear plants at high capacity factors enabled them to contribute nearly 20% of total U.S. electricity generation in 2016 while only making up 9% of U.S. generation capacity.
Of the 99 gigawatts (GW) of total operating nuclear capacity in the country, 95 GW came online between 1970 and 1990. However, planned nuclear capacity additions began to slow as early as the late 1970s because of a number of factors, including slowing electric demand growth, high capital and construction costs, and public opposition. Costs, schedules, and public acceptance were all influenced by the accident at the Three Mile Island plant in 1979. From 1979 through 1988, 67 planned builds were canceled. However, because of the long times required for permitting and building new nuclear reactors, many plants that had begun the process in the 1970s continued to come online through the early 1990s.
U.S. nuclear plants are licensed for an initial operating life of 40 years by the Nuclear Regulatory Commission (NRC). Owners of nuclear power plants can apply for a license renewal, extending license expiration by 20 years. The decision to apply for a renewal is based on the economics of the capital investments required to extend the operating lifetime and estimated future revenues. As of 2016, the NRC had granted license renewals to 84 of the 99 operating reactors in the United States.
Nuclear capacity has decreased in the United States in recent years as plants have retired. The retirement of the Fort Calhoun Nuclear Generating Station in October 2016 marked the fifth nuclear retirement since 2013. Several other plants have announced plans to retire in the near future (including Oyster Creek, Pilgrim, Palisades Unit 1, and Indian Point Units 2 and 3) totaling more than 4 GW of capacity. In addition, Pacific Gas and Electric announced that it will not seek license extensions for its Diablo Canyon nuclear power plant, meaning Diablo Canyon Units 1 and 2, with a combined capacity of more than 2 GW, will be retired by the time their current licenses expire in 2024 and 2025, respectively.
Nuclear capacity can increase either by building new reactors or by instituting changes that allow existing plants to increase their generating capacity, known as uprates. Four new reactors are under construction and are expected to bring more than 4 GW of capacity online. Uprates of existing plants require NRC approval, and almost all U.S. reactors have applied and received at least one uprate. Through 2016, these uprates have contributed more than 7 GW to total U.S. nuclear capacity.
Nuclear plants have higher capacity factors than any other electricity generating technology, averaging 90% over the past five years. Because nuclear plants run near full capacity for much of the time they are operating, they serve as baseload generation. Refueling and maintenance outages at nuclear plants are typically scheduled during the spring and fall periods of lower electricity demand. Nuclear plants typically refuel every 18 to 24 months, and over the past few years these outages have typically lasted about six weeks.
Thirty states have at least one operating nuclear reactor. Illinois (6 plants with 11 total reactors) and Pennsylvania (5 plants with 9 reactors) have the most nuclear capacity in the country, and together they account for one-fifth of total U.S. nuclear capacity.
This article is part of an ongoing series of Today in Energy articles examining the fleet of utility-scale power plants in the United States. Previous articles have examined hydroelectric, coal, and natural gas generators.
U.S. gross natural gas output in the lower 48 states jumped by the most in almost three years to 80.2 billion cubic feet per day in February, the U.S. Energy Information Administration (EIA) said on Friday in its monthly 914 production report.
The 1.8 bcfd increase in February over January was the biggest monthly increase since April 2014 and the first monthly increase in three months.
Gross production in February climbed to its highest since August 2016. That compares with the record 82.6 bcfd hit in February 2016.
Output increased in all three of the biggest lower 48 producing states - Texas, Pennsylvania and Oklahoma.
In Texas, the largest gas-producing state, output in February increased for the first month in 10, up 0.7 bcfd to 21.3 bcfd. That was the biggest monthly increase in the state since March 2011.
In Pennsylvania, output rose by 0.3 bcfd to a monthly record high of 15.2 bcfd in February. That was the fourth monthly increase in a row.
Production in Oklahoma increased by 0.2 bcfd to 6.5 bcfd in February. That was its biggest monthly increase since March 2015.
EIA also reported dry gas production for February, but did not break out individual states. U.S. dry production, including Alaska, increased to 72.1 bcfd in February from 70.7 bcfd in January. Monthly dry gas production peaked in April 2015 at 75.0 bcfd.
Gas production declined in 2016 for the first time since the start of the shale revolution a decade ago as low energy prices reduced drilling activity.
Next-day gas prices at the Henry Hub benchmark in Louisiana averaged $2.49 per million British thermal units in 2016, the lowest annual average since 1999. Prices averaged $2.61 in 2015, which before last year was also the lowest since 1999.
Before 2016, U.S. dry gas production last dropped in 2005 when Hurricanes Katrina and Rita slammed into the Gulf Coast, damaging energy infrastructure along the Gulf of Mexico, which had been supplying more than 20 percent of the nation's gas.
Since then, producers have figured out how to use horizontal drilling and hydraulic fracturing technologies to unlock more of the gas trapped in shale rocks.
Today, the seven biggest U.S. shale fields produce more than 60 percent of the nation's gas, while the Gulf of Mexico accounts for around 4 percent of the total.
By Helen Reid and Danilo Masoni
LONDON/MILAN, April 5 European shares ended little changed on Wednesday, as gains in commodity stocks were offset by weaker autos, but investors remained upbeat about prospects for the region's equities following solid economic data.
The pan-European STOXX 600 index ended at 380 points after moving in an out of positive territory throughout the session. UK's FTSE added 0.1 percent and Germany's DAX slipped 0.5 percent.
Euro zone businesses had their best quarter in six years, construction purchasing managers' indexes showed, with individual countries' data also improving, indicating broad-based growth in economies across Europe.
Though major indexes were little changed after the data, it added to an improving picture for investors looking at European equities.
"It's the most positive economic backdrop that we have seen since Mario Draghi's been head of the ECB," said Mike Bell, global market strategist at JP Morgan Asset Management.
"Investors are not fully pricing in that improvement in economic fundamentals, perhaps understandably because of political concerns," he added, noting caution around the French election. "We think that now is a good opportunity to be buying European equities while others are still fearful."
Draghi has been ECB president since November 2011.
In a further sign of growing confidence, Citi upgraded continental European stocks to overweight, predicting that the STOXX 600 index would rise another 8 percent by year-end.
Meanwhile merger and acquisitions activity continued to drive price action on Wednesday.
Syngenta rose 0.9 percent after ChemChina won conditional EU antitrust approval for its $43 billion bid for the Swiss pesticides and seeds group.
"The approval .. is a big positive for the deal advancing towards closure," said Bernstein analysts in a note.
Danish business support services firm ISS rose 4 percent after agreeing to buy U.S. catering firm Guckenheimer for 1.5 billion Danish crowns ($222 million).
Oil services groups Wood Group rose 2.7 percent after saying it expected about 36 percent more cost savings from its deal to buy Amec Foster Wheeler for 2.2 billion pounds. Amec rose 2.2 percent.
"Wood Group's increase to the synergies estimate from this deal is in line with our expectation that the original $134m target materially underestimated the opportunities for cost savings," said RBC oil services analyst Victoria McCulloch.
Petrofac lagged a positive oil sector, down 3.5 percent after downgrades from Deutsche Bank and Bernstein.
Autos stocks were the worst-performing sector for the second straight day, down 1.1 percent to their lowest closing level in nearly 8 weeks. (Reporting by Danilo Masoni, editing by Pritha Sarkar)
Oil and gas drilling activity continues to recover in Alberta and across Canada, with the number of wells drilled this year now expected to outpace last year's total by 64 per cent.
The Petroleum Services Association of Canada revised its forecast for 2017 upward — again — on Thursday, and now expects some 6,680 wells to be drilled nationwide this year, with roughly half of those in Alberta.
That's up from the 5,150 wells it foresaw in its January forecast, which was also an upgrade from last November's initial forecast of 4,175 wells.
After hovering around 11,000 wells annually from 2012 to 2014, drilling activity shrunk to just 5,400 wells in 2015 and then fell to a low of 4,084 wells in 2016 in the wake of the oil price crash.
But now it seems the trend is in the opposite direction.
"It's been tough," said PSAC president Mark Salkeld. "We've lost member companies, they've gone under. We've seen the mergers and acquisitions. We've seen the services companies come together to grow and expand.
"But it's been hell. It's been just absolute hell on the pricing and we're coming out of it."
The industry has some degree of confidence in $50-a-barrel oil and the lowering of costs by the service sector, he added.
In Alberta, specifically, PSAC now expects 3,320 wells will be drilled this year, up from its initial forecast of 1,900.
Saskatchewan is expected to see 2,670 wells, up from an original forecast of 1,940.
British Columbia is forecast to have 449 wells drilled and another 221 are expected in Manitoba this year.
Twenty wells are expected in the rest of the country.
U.S. President Donald Trump will sign an executive order on Friday that seeks to expand offshore oil and gas drilling to areas currently off limits, in his administration's latest move to expand domestic energy production.
The order could lead to a reversal of bans on drilling across swathes of the Atlantic, Pacific and Arctic oceans and the U.S. Gulf of Mexico that former President Barack Obama sought to protect from development.
"It is better to produce energy here than be held hostage by foreign entities," Interior Secretary Ryan Zinke told reporters on Thursday in a briefing about the executive order, which will be called the America-First Offshore Energy Strategy.
Trump campaigned on a promise to do away with Obama-era environmental protections that he said were hobbling energy development and undermining U.S. national security without providing any tangible benefits. Industry cheered but environmental advocates were enraged.
Zinke said the order will require him to review and replace the Obama administration's most recent five-year oil and gas development plan for the outer continental shelf, which includes federal waters off all U.S. coasts.
The order will also reverse Obama's move to place parts of the Arctic permanently off limits to drilling, and encourage more seismic surveying to determine which areas are likely to hold rich reserves of oil and gas.
In addition, under the order Commerce Secretary Wilbur Ross will review previous presidents' designations of marine national monuments and sanctuaries under the 1906 Antiquities Act over the last 10 years.
Weeks before leaving office, Obama banned new oil and gas drilling in federal waters in the Atlantic and Arctic oceans, protecting 115 million acres (46.5 million hectares) of waters off Alaska and 3.8 million acres in the Atlantic from New England to the Chesapeake Bay.
On Wednesday Trump signed a separate order to examine areas of federally managed land to determine if they were improperly designated as national monuments by former presidents, rendering them off limits to development.
Environmental groups, including Oceana and the Center for Biological Diversity, criticized the new executive order and promised to fight it in court. They pointed out the order comes seven years after a large oil spill from a BP platform in the Gulf of Mexico, which had prompted them to urge a slowdown in offshore oil development.
Democratic senators also opposed the order, saying it could threaten the fishing and tourism industries. (Editing by Richard Valdmanis and Jeffrey
A powerful storm system bore down on the eastern United States on Monday after spawning tornadoes and torrential rains that killed at least 16 people and shut down hundreds of roads over the weekend, forecasters said.
The storm that tore through the central United States from Texas to Illinois could spawn damaging winds, hail and tornadoes as it heads into parts of the Middle Atlantic and Northeast, the National Weather Service said.
The front, described as a "powerhouse of an upper level system," could pack downpours of more than an inch (2.5 cm) an hour as it hammers Pennsylvania and New York state, the weather agency said.
Flooding that could be record breaking in eastern Oklahoma, northern Arkansas, Missouri and Illinois was expected to take several days to recede, it said.
High water in Missouri on Monday forced about 330 roads to close, including a stretch of Interstate 44 near Rolla, the state transportation department said on its website. More than 100 highways also were shut in neighboring Arkansas, state officials said.
In North Carolina, Governor Roy Cooper urged residents to remain on their guard, especially in areas already hit by flooding. Almost 30 roads were closed from high water and washouts, his office said in a statement.
Tornadoes from the storm system killed four people on Saturday in Canton, Texas, about 60 miles (95 km) east of Dallas. The National Weather Service said Canton was hit by four tornadoes, with two packing winds of 136 miles to 165 miles (219 km to 265 km) per hour.
Five people died in Arkansas, with two still missing, said state emergency management spokeswoman Melody Daniels. She could not confirm news reports that the missing were children who were in a car swept off a bridge.
In Mississippi, one man was killed when a tree fell on his home, and a 7-year-old boy was electrocuted when he unplugged an electric golf cart in standing water, said Greg Flynn, a spokesman for the state's emergency agency.
Two people were killed in Tennessee in storm-related incidents, authorities said. They included a Florence, Alabama, woman struck by a falling tree on Sunday, the Lincoln County Sheriff's Department said in a statement.
In Missouri, a 72-year-old Billings woman was swept away by high waters on Saturday, and two men ages 18 and 77 drowned in separate incidents on Sunday, emergency management spokesman Mike O'Connell said.
Cheniere Energy recently celebrated loading its 100th LNG export cargo to nearly 20 countries from Sabine Pass in Louisiana, the first such facility in the contiguous U.S. Now at over 2 Bcf/d and with five additional export terminals expected by 2020, the U.S. could be exporting 10-12 Bcf/d of LNG, or about 15-17% of our total current gas demand.
A quantum leap from the zero we were exporting in January 2016.
Now 85% complete and expected online in Q4, Dominion Cove Point in Maryland will be our first LNG export facility on the East Coast. Dominion recently asked FEFC for approval to introduce fuel gas at the plant. Fully subscribed under 20-year terminal service agreements, the $3.8 billion Cove Point will have the capacity to export some 0.8 Bcf/d, ready to weaken Russia's stranglehold on Europe.
Yet, with the Panama Canal's expansion in June 2016, Sabine Pass can reach any major import terminal within 25 days.
Already with three fully-operational LNG trains, Sabine Pass’ fourth train is in the commissioning process and will be completed in the second half of this year. Trains five and six will come online over the next few years.
Sabine Pass has already made such a significant change in the global LNG market that gas from the Montney shale play in western Canadian is set to reach the U.S. Gulf for export to the world (here). Canada's own LNG export off the nearby BC coast is not expected until at least 2022.
For reference, it takes 37 hours to drive from Edmonton to New Orleans, slightly less than from NYC to LA.
Even though the LNG market has been oversupplied, it's good time to add LNG export capacity because it takes years for commissioning. Exporting just 1-2% of the world's LNG last year, the U.S. by 2019 will soar past 13 other exporters and become the 3rd largest LNG exporter behind Qatar and Australia.
For the past three years, underground natural gas storage capacity in the Lower 48 states has changed by relatively small increments compared to the changes in 2012 and 2013. No new storage facilities have entered service since 2013, so recent annual changes in both storage design capacities and demonstrated maximum working gas volumes reflect the aggregate effect of small changes at existing facilities.
The relatively small change in natural gas storage capacity over the past three years is likely a reflection of long-term trends, such as higher levels of natural gas production, the proximity of production to consuming markets in the Northeast and Midwest, and the lower price premium for natural gas during the winter. These trends may reduce reliance on storage as a source of supply during periods of elevated demand, such as during cold winter months.
EIA has published updated estimates of storage capacity based on data for the end of November, which is approximately when storage levels have reached their highest points for the year. EIA uses two distinct measures of natural gas storage capacity: design capacity and demonstrated working natural gas volume.
Design capacity is the sum of the 385 active storage fields’ working gas design capacity, as of November 2016, as reported in EIA’s Underground Natural Gas Working Storage Capacity. Design capacity is based on the physical characteristics of the reservoir, installed equipment, and operating procedures particular to the site that are often certified by federal or state regulators. Design capacity increased slightly, growing 0.7%, from 4,658 billion cubic feet (Bcf) in November 2015 to 4,688 Bcf in November 2016. This increase resulted from a combination of expansions at existing facilities, reclassifications from base gas to working gas, and the restoration of an inactive facility to service.
Demonstrated maximum working gas volume is the sum of peak volumes reported by the 385 active storage facilities in the Lower 48 states, regardless of when the individual field-level peaks occurred over the five-year (60-month) reporting period ending November 2016. In the graphic below, this measure is compared to the five-year period ending November 2015. In the Lower 48 states, the demonstrated maximum working gas volume grew by 0.7%, from 4,342 Bcf in 2015 to 4,373 Bcf in 2016.
Demonstrated maximum working gas volumes can be affected by short-term circumstances. For example, the 2016 injection season started with very high levels largely because of the mild winter of 2015–16. These injections led to all-time high storage levels in November, at the beginning of the most recent withdrawal season. As a result, many storage facilities reached new demonstrated maximums in 2016.
Capital expenditure for 44 U.S. onshore-focused oil production companies increased $4.9 billion (72%) between the fourth quarter of 2016 and the fourth quarter of 2015 based on their public quarterly financial statements. This increase in investment spending was the largest year-over-year increase for any quarter by these 44 companies since at least the first quarter of 2012.
Higher oil prices are contributing to an increase in upstream earnings for U.S. producers, prompting some companies to increase their investment budgets. Company announcements and increases in the number of active oil rigs suggest U.S. oil production companies are continuing investment growth in the first quarter of 2017. The U.S. active oil-directed rig count reached 662 on March 31, 2017, up from 525 at the end of 2016.
Lower investment levels over the previous two years likely contributed to a reduction in cash from operations for these 44 companies despite an increase in crude oil prices. The reduction in cash from operations for these 44 companies totaled $475 million year-over-year in the fourth quarter of 2016. Significant reductions in exploration and development spending in 2015–16 led to less drilling, which reduced oil production in the fourth quarter of 2016, offsetting increased revenue that came from higher prices. Cash from operations lags capital expenditure for these companies because they invest to develop reserves that will increase oil production and cash flow in the future.
Many of these companies use oil futures and options to hedge their investment in production into the future. Financial hedging for producers reduces the effect of a fall in revenue if prices were to decline. A measure for the amount of future production oil companies have hedged is the number of short positions, or future sales into these markets. These short positions consist of futures and option contracts held by producers and merchants. Producers have begun using them more since crude oil prices rose above $50 per barrel in the fourth quarter of 2016. In mid-February 2017, the number of short positions in U.S.-based futures and options reached 756,000 contracts, close to the 10-year high of 802,000 contracts.
Financial indicators from these 44 U.S. onshore-focused oil production companies with quarterly financial reports suggest that they are continuing to increase capital expenditures in exploration and development, supporting continued production growth in the United States. Financial results for the first quarter of 2017 will be released in May.
Primary energy consumption in the United States in 2016 totaled 97.4 quadrillion British thermal units (Btu), a slight increase from the 2015 level. Consumption of coal decreased by 9%, nearly offsetting increases in the consumption of renewables, petroleum, natural gas, and nuclear fuel.
Fossil fuels continue to account for the bulk of U.S. energy consumption, and the consumption of petroleum and natural gas both increased in 2016. However, those increases were more than offset by lower coal consumption. Overall, fossil fuels made up 81% of the United States’ total energy consumption in 2016, slightly lower than 2015 levels, but down from 86% in 2005.
Petroleum consumption increased to 19.6 million barrels per day in 2016, led by increases in the transportation sector. Natural gas consumption increased to 27.5 trillion cubic feet, led by higher demand in the electric power and industrial sectors. Natural gas consumption in the residential and commercial buildings sectors fell slightly, reflecting lower heating demand. Coal consumption fell to 730 million short tons in 2016, the third consecutive year of declining coal consumption. Coal consumption decreased in the electric power sector by 61 million short tons (8%), while industrial sector coal consumption fell by 6 million short tons (11%).
Nuclear fuel consumption in the United States increased 1% in 2016. The number of total operable nuclear generating units briefly increased from 99 to 100 when Watts Bar Unit 2 in Tennessee came online. Later in the year, the retirement of Nebraska’s Fort Calhoun nuclear facility brought the number of nuclear units in the United States back to 99. Year-end 2016 nuclear capacity was slightly higher than in 2015 (99.3 gigawatts versus 98.7 gigawatts), and annual average nuclear capacity factors, which reflect the use of power plants, were also slightly higher, at 92.5% versus 92.3% in 2015.
Renewable fuels had the largest increase in energy consumption in 2016. Wind generation increased by nearly 20%, making up almost half of all renewable consumption increases. Solar consumption also significantly increased, as considerable electric generating capacity was added for both wind and solar resources in 2016. Hydroelectric consumption increased by 7% as the West Coast recovered from severe drought conditions. Together, wind, hydro, and solar made up 91% of renewable consumption increases. Biomass consumption, which accounted for 47% of all renewable consumption in 2016, remained close to its 2015 level.
China is the world’s largest net importer of crude oil, and in recent years, China’s crude oil imports have increasingly come from countries outside the Organization of the Petroleum Exporting Countries (OPEC). While OPEC countries still made up most (57%) of China’s 7.6 million barrels per day (b/d) of crude oil imports in 2016, crude oil from non-OPEC countries made up 65% of the growth in China’s imports between 2012 and 2016. Leading non-OPEC suppliers included Russia (14% of total imports), Oman (9%), and Brazil (5%).
On an average annual basis, China’s crude oil imports increased by 2.2 million b/d between 2012 and 2016, and the non-OPEC countries’ share increased from 34% to 43% over the period. Market shares for China’s top three non-OPEC suppliers (Russia, Oman, and Brazil), all increased over these years. While still comparatively small as a share of China’s crude oil imports, imports from Brazil reached a record high of 0.6 million b/d in December 2016, and imports from the United Kingdom reached a high of 0.2 million b/d in February 2017.
Growth in China’s total crude oil imports in 2016 reflected both lower domestic crude oil production and continued demand growth. After increasing steadily between 2012 and 2015, China’s crude oil production declined significantly in 2016. Total liquids supply in China averaged 4.9 million b/d in 2016, a year-over-year decline of 0.3 million b/d, the largest drop for any non-OPEC country in 2016. U.S. crude oil production fell by more than 0.5 million b/d in 2016, but total liquids declined by less than 0.3 million b/d because other liquids production increased by less than 0.3 million b/d.
Much of Chinese production growth from 2012 through 2015 was driven by more expensive drilling and production techniques, such as enhanced oil recovery (EOR) in older fields. As oil prices declined during 2016, investments in developing new reserves also fell and were not high enough to offset the natural production declines of older fields.
China’s demand growth has remained the world’s largest in every year since 2009, increasing 0.4 million b/d in 2016. As China increased its imports to address a growing gap between its domestic production and demand, it surpassed the United States as the world’s largest net importer of total petroleum (crude oil and petroleum products) in 2014. The United States imports more crude oil and exports more crude oil and petroleum products than China.
Other factors contributed to an increase in Chinese crude oil imports. For example, in July 2015, the Chinese government began allowing independent refiners (those not owned by the government) to import crude oil. The independent refiners previously had restrictions on the amount of crude oil they could import and relied on domestic supply and fuel oil as primary feedstocks. Another factor is the Chinese government’s filling of new Strategic Petroleum Reserve sites.
EIA’s latest Short-Term Energy Outlook (STEO) forecasts a 0.3 million b/d increase in China’s total liquid fuels demand in both 2017 and 2018. Absent any domestic production increases, China’s crude oil imports are expected to continue increasing. More information about China’s crude oil imports and various market forces that may suggest continued growth in non-OPEC crude oil imports are available in EIA’s This Week in Petroleum.
In 2016, natural gas-fired generators accounted for 42% of the operating electricity generating capacity in the United States. Natural gas provided 34% of total electricity generation in 2016, surpassing coal to become the leading generation source. The increase in natural gas generation since 2005 is primarily a result of the continued cost-competitiveness of natural gas relative to coal.
Natural gas-fired combined-cycle units accounted for 53% of the 449 gigawatts (GW) of total U.S. natural gas-powered generator capacity in 2016. Combined-cycle generators have been a popular technology choice since the 1990s and made up a large share of the capacity added between 2000 and 2005. Under current natural gas and coal market conditions in many regions of the country, combined-cycle generating units are often used as baseload generation, which operate throughout the day.
Other types of natural gas-fired technology, such as combustion turbines (about 28% of total natural gas-powered generator capacity) and steam turbines (17%), generally only run during hours when electricity demand is high. The capacity-weighted average age of U.S. natural gas power plants is 22 years, which is less than hydro (64 years), coal (39), and nuclear (36).
Natural gas-fired capacity is widely distributed across the United States. Every state except Vermont has at least one natural gas plant. About 38% of U.S. natural gas-fired generation capacity is located in four states: Texas, California, Florida, and New York. Natural gas power plants account for more than half of the total electricity generating capacity in each of these four states and in seven other states. Texas has the most natural gas-fired capacity of any state, with 69 GW, or 15% of the national total. California and Florida each have about 40 GW of natural gas-fired capacity.
The operating profile of the nation’s natural gas-fired generation facilities varies, depending on the overall level of electricity demand, plant efficiency, and natural gas prices. The average capacity factor, a metric that measures the utilization of power plants, for natural gas combined-cycle units has increased from 43% in 2011 to 56% in 2016. The upward trends in both natural gas net generation and the natural gas-fired combined-cycle annual capacity factor (which is approaching 60%) highlight the growing contribution of natural gas-fired combined-cycle generators, which traditionally only served peaking and intermediate loads, but now have increasingly become more common to meet baseload demands.
This article is part of an ongoing series of Today in Energy articles examining the fleet of utility-scale power plants in the United States. Previous articles have examined hydroelectric and coal generators.
Working natural gas in storage as of March 31, the traditional end of the heating season, totaled 2,051 billion cubic feet (Bcf), or almost 15% above the five-year average according to EIA's Weekly Natural Gas Storage Report. The total inventory of U.S. natural gas in storage tends to follow seasonal patterns of injections through the summer and withdrawals during the winter. Unlike the 2015–2016 heating season’s extremely high levels of natural gas inventories due to mild weather, inventories during the 2016–2017 heating season closely tracked the five-year average (2012-2016) until withdrawals slowed toward the end of the season.
At the end of March 2016, U.S. natural gas storage inventories were near the highest on record for the end of a heating season, totaling 2,470 Bcf, or 54% higher than the previous five-year average (2011-2015). For most of 2016 and continuing into the 2016–2017 heating season, inventories remained above the previous five-year average. Inventories began the most recent heating season at a record of 4,047 Bcf on November 11, 2016, because of relatively warm seasonal weather.
Overall natural gas consumption during the 2016–2017 heating season was about the same as the previous year, but U.S. dry natural gas production fell by 3% over that same period. Natural gas consumption in the residential, commercial, and industrial sectors remained relatively unchanged. Responding to slightly higher natural gas prices, natural gas consumed in U.S. electric power generation fell 2.1 Bcf from the 2015–2016 heating season, but the drop was almost entirely offset by a 2.0 Bcf increase in natural gas exports from the United States, according to data from PointLogic.
EIA’s latest Short-Term Energy Outlook expects an increase in working natural gas inventories of about 1,750 Bcf through this summer’s injection season. The resulting forecast of U.S. natural gas inventories at the end of October 2017 suggests that they will not match the record high end-of-injection-period levels set at the end of October 2016. Similar to recent consumption patterns, consumption in the residential, commercial, and industrial sectors is expected to remain relatively flat on an annual average basis as electric power sector consumption of natural gas declines slightly and gross natural gas exports—especially liquefied natural gas exports—continue to increase.
After reaching a record high of 79 billion cubic feet per day (Bcf/d) in 2015, U.S. marketed natural gas production fell to 77 Bcf/d in 2016, the first annual decline since 2005. Texas, the state with the most natural gas production, fell by 2.5 Bcf/d, while Ohio and Pennsylvania each increased by about 1.2 Bcf/d.
EIA measures natural gas production in three different ways. Gross withdrawals are the full volume of compounds extracted at the wellhead, which includes all natural gas plant liquids and nonhydrocarbon gases after oil, lease condensate, and water have been removed. Marketed natural gas production excludes natural gas used for repressuring the well, vented and flared gas, and any nonhydrocarbon gases. Dry natural gas production is marketed production minus natural gas plant liquids.
Pennsylvania and Ohio had the two largest annual natural gas production increases from 2015 to 2016, reflecting higher production from the Utica and Marcellus shale plays, which have accounted for 85% of the U.S. shale gas production growth since 2012. Production in Pennsylvania and Ohio has accounted for an increasing share of total U.S. natural gas production in recent years, growing from less than 2% in 2006 to 24% in 2016.
Pennsylvania surpassed Louisiana in 2013 to become the second-highest natural gas producing state, behind Texas. Although both states had higher production in 2016, Ohio surpassed West Virginia last year to become the seventh-highest natural gas-producing state. The increased productivity of natural gas wells in the Marcellus Shale and Utica Shale is a result of ongoing improvements in precision and efficiency of horizontal drilling and hydraulic fracturing occurring in these regions.
Louisiana, West Virginia, and North Dakota also increased their natural gas production in 2016. Louisiana’s increase was the first annual increase since 2011, while West Virginia and North Dakota have had 13 and 8 consecutive years of natural gas production increases, respectively.
EIA's Short-Term Energy Outlook projects that natural gas production will increase in both 2017 and 2018 as natural gas prices rise, resulting in higher rig activity. Spot natural gas prices at the Henry Hub, a natural gas market benchmark, fell from $2.63 per million British thermal units (MMBtu) in 2015 to $2.51/MMBtu in 2016. Henry Hub prices are expected to increase to an annual average of $3.10/MMBtu in 2017 and $3.45/MMBtu in 2018. These price increases reflect the expectation of increased natural gas consumption, increased exports, and lower average inventory levels.
Working gas in storage was 4,045 Bcf as of Friday, November 18, 2016, according to EIA estimates. This represents a net decline of 2 Bcf from the previous week. Stocks were 39 Bcf higher than last year at this time and 241 Bcf above the five-year average of 3,804 Bcf. At 4,045 Bcf, total working gas is above the five-year historical range.