Industry Affairs October 2014

Growing U.S. Natural Gas Output Spurs Exports to Mexico

By Naureen S. Malik Oct 7, 2014 9:00 AM CT, Bloomberg.com

Natural gas production expanding at the fastest pace in three years will spur exports to Mexico, according to the U.S. Energy Information Administration.

Marketed production will increase 5.4 percent this year to average 73.98 billion cubic feet a day, representing the biggest volume and percentage gains since 2011, the EIA said in its Short-Term Energy Outlook released today. The forecast was raised from last month’s projection of 73.93 billion.

The boom in shale drilling at deposits from the Marcellus in the East to the Eagle Ford in Texas will expand natural gas output for the 10th straight year in 2015. The surge in supply is boosting demand for the fuel from Mexico, the Energy Department’s statistical arm said.

“The strong increases already seen in the Lower 48 states this year will continue,” the EIA said in the report. “Growing domestic production is expected to continue to put downward pressure on natural gas imports from Canada and spur exports to Mexico.”

Exports to Mexico, primarily from the Eagle Ford, will be driven by rising demand from its power sector and flat production, the EIA said.

Gross gas exports this year will increase this year by 0.5 percent to 4.32 billion cubic feet a day and then expand by 9 percent in 2015 to 4.71 billion, the report showed.

Mexico’s national energy ministry projected that gas flows across the border will rise to 3.8 billion cubic feet a day in 2018, more than double the rate of 1.8 billion in 2013, the EIA said in a May 29 report.

Rising Output

The EIA expects gas output to rise 2 percent in 2015 to average 75.48 billion cubic feet a day, setting a record for the fifth straight year after expanding for the past decade.

Gains in gas production and an unusually mild summer that reduced demand for the power-plant fuel helped U.S. stockpiles replenish at a record rate from an 11-year low during the frigid winter. The EIA expects supplies in the lower 48 states to reach 3.532 trillion cubic feet by the end of October, raised from last month’s outlook of 3.477 trillion.

“Rising domestic natural gas production this year, along with a mild summer that resulted in less electricity generation to meet air conditioning demand, contributed to the record build in natural gas inventories,” EIA Administrator Adam Sieminski said in an e-mailed statement.

Lower Prices

The government trimmed its 2014 gas price forecast for Henry Hub in Louisiana, the benchmark for New York futures, to $4.45 million Btu from $4.46 in last month’s outlook. Average prices will drop 14 percent next year to $3.84, the report said.

Gas futures for November delivery yesterday fell 14.1 cents, or 3.5 percent, to $3.898. Prices are down 7.8 percent this year.

“Even if this winter is as cold as last year’s, the net withdrawal from natural gas inventories over the heating season would not be as large as last winter’s drawdown,” Sieminski said. “Domestic gas production this winter is expected to be significantly higher than it was last winter.”

To contact the reporter on this story: Naureen S. Malik in New York atnmalik28@bloomberg.net

 

WHAT IN THE WORLD IS GOING ON WITH CRUDE OIL PRICES?

Alex Mills, October 2, 2014, PowellShaledigest.com

What in the world is going on with crude oil prices?

Historically, when war breaks out in the Middle East, where a major portion of oil exports come from, prices increase.

However, crude oil futures for November delivery on the NYMEX settled at $90.73 per barrel on Oct. 1, the lowest settlement since April 2013.

“The extended sell-off in global crude markets has reduced Brent futures market by around $16 per barrel since the start of the quarter (July 2014),” according to a report issued by J.P. Morgan. Brent closed at the lowest level since June 28, 2012. Prices decreased 16% last quarter and have slipped 15% this year.

Brent futures is crude oil traded in London, and it traded for $94.16 on Oct. 1. NYMEX is crude oil traded in New York.

Brent has been trading $10 to $15 higher than West Texas Intermediate (WTI) on NYMEX, but J.P. Morgan reports that “the spread between WTI and Brent futures appears to have become more stable over the past six month than seen in the previous eight quarters.”

The current spread is $3.43 between Brent and WTI.

While Brent and WTI are prices paid for future deliveries, the price reported at Cushing, OK is for actual barrels. Cushing is a major storage facility for crude oil, and the supply of oil at Cushing has an immediate impact on prices at Cushing and throughout Texas.

The enormous increase in oil production in the Permian Basin and all across Texas, and the lack of takeaway infrastructure is causing an oversupply of crude oil at the lease level. J.P. Morgan expects that supplies of domestic crude oil to increase 1 million barrels per day over the same period last year during the fourth quarter of 2014.

A major source of all of this new supply will come from the Permian Basin where prices have decline $17.50 per barrel below the price at Cushing, according to a news story in the Sept. 28 edition of the Midland Reporter-News.

The story quoted the EIA estimating oil production in the Permian Basin to have increased 300,000 barrels per day from a year ago to 1.7 million barrels per day.

The story quoted one producer who said he would net $80 per barrel in September. In addition to the increase in oil production, most of the pipeline capacity currently available goes to Cushing, where there is an oversupply.

Additional 225,000 barrels per day capacity on the Longhorn Pipelines and expansion of Sunoco Logistics Partners’ Permian Express pipeline may be available soon to reduce the transportation issues.

The other major destination for Permian Basin crude is the Gulf coast of Texas and Louisiana, where there are many refineries with an estimated capacity of 9 million barrels per day. However, the oil produced in the Permian Basin is primarily a light, sweet crude similar to the oil being produced in the Eagle Ford Shale in South Texas. Most of the refiners on the Gulf Coast cannot handle all of the new sweet crude. They were built to handle a sour, heavier crude oil.

Some producers want to be able to export the sweet crude to other countries, but U.S. law prohibits the export of most crude oil. More pressure on softening oil prices comes from Saudi Arabia’s announcement it has reduced its benchmark Arab Light prices to customers in Asia, Europe and the U.S. The Saudi price cut is a sign that they won’t be cutting back production further and may be setting up for a market share battle.

All of these factors have caused oil prices to decline even though there is a shooting war in progress in the Middle East.

 

Maze Of Federal Oversight Impedes North Dakota's Anti-Flaring Push

Ernest Scheyder, Wednesday, October 01, 2014, Reuters.com

TIOGA, N.D., Oct 1 (Reuters) - North Dakota's oil producers will struggle to comply with aggressive rules taking effect on Wednesday designed to curb the wasteful burning of natural gas, hindered by lengthy federal reviews of crucial pipelines.

The No. 2 U.S. oil state is pushing to resolve a problem commonly known as flaring, an environmental and economic squandering akin to burning cash.

Energy companies have been preparing since June for the deadline requiring them to capture 74 percent of natural gas extracted alongside crude oil from thousands of wells. The standards get tougher in January.

But the energy industry and state officials say they are bound to fall short of the goal through 2015, flaring gas in excess of targets and consequently having to trim oil production to comply with penalties built into the new standards..

The main reason, according to Reuters interviews and reviews of regulations, is simple: a Byzantine web of state and federal agencies who must sign off on new pipelines.

Too few pipelines and a lack of plant capacity to prepare gas for transport means North Dakota flares enough natural gas in one month to heat more than 160,000 homes for a year.

The pipelines are caught between state officials whose top energy policy goal is to cut flaring, and federal agencies, which weigh historical and ecological issues, including protection of habitats for rare plants and animals.

The federal holdups are "a major disappointment," said Lynn Helms, head of the North Dakota Department of Mineral Resources. "It will make it harder to meet that 74-percent goal."

State and industry officials say Hess Corp is running its newly built Tioga gas processing plant, the state's largest, at just 70 percent capacity because it needs to re-route a key new pipeline eight miles around an American Indian historical site.

This requires a review by the U.S. Bureau of Land Management, one of ten state and federal agencies overseeing various pieces of North Dakota land and water.

"The regulatory process could be improved if the multiple agencies involved, both state and federal, were to adopt a more-streamlined and interconnected system," Mike Turner, a Hess executive, said in an industry speech in August.

Hess declined to comment on the federal regulatory review for the new line, citing a plan to spin off its North Dakota oil and natural gas storage facilities and processing plants next year into a master-limited partnership.

 

Penalties

If producers violate the new flaring standards they won't be allowed to produce more than 200 barrels per day (bpd) of oil at each well. Most North Dakota wells produce in excess of 1,500 bpd when first online.

In addition, an oil producer could have future drilling permits delayed if it does not meet the flaring reduction goal and does not desire to utilize the gas in a "beneficial manner."

State regulators plan monthly audits to ensure producers are following the new standards, according to documents seen by Reuters.

That means output that has surged to some 1.1 million bpd of crude from about 321,000 bpd in 2010 could grow more slowly.

Oneok, which just announced plans for an eleventh natural gas processing plant in North Dakota, cannot build a 1.6-mile portion of its 20-mile Lost Bridge pipeline to its three Garden Creek plants without approval from the U.S. Forest Service and the Three Affiliated Tribes of the Mandan, Hidatsa and Arikara (MHA) Nation.

Approval for both lines won't come until November at the earliest, meaning contractors will miss the 2014 construction season due to the state's frigid winter and will likely have to wait until April to build.

While nearly all of North Dakota's land is privately held, some small patches of land at vital points are controlled by federal regulators, necessitating their approval for most pipelines in the state.

For example, any pipeline that crosses Lake Sakakawea, the dammed portion of the Missouri River that bisects the state's Bakken oil field, requires additional approval from the U.S. Army Corps of Engineers.

Oneok hopes to open its third Garden Creek processing plant by December. The Forest Service says it's working with the MHA Nation on the best route for the Lost Bridge line, which must traverse rugged, steep terrain.

Oneok works "diligently with all applicable regulatory agencies to ensure the sage, compliant construction of all our assets," said spokesman Brad Borror.