One year agoPNB looks back at year-end 2013 issues and what has and hasn’t changed Mike Ellerd Petroleum News Bakken
As 2014 drew to a close, Petroleum News Bakken paused to look back at the last two editions of 2013 to compare the important Bakken industry-related issues making the news then with those making the news at the end of 2014.
Obvious to anyone who follows the industry, 2014 was fraught with change, including the major issue that wasn’t even on anyone’s radar at the end of 2013 - the plummeting global crude oil market and its ripple effects in the Williston Basin. But there were also a number of other key issues that continued from 2013 and developed through 2014. And then there were some industry-related issues that didn’t change at all, and the one that stands out is the Keystone XL pipeline.
The top story on the front page of the Dec. 29, 2013, edition was titled “XL: pipe and rail?” and reported that TransCanada was considering a rail option to the Keystone XL pipeline as an attempt to keep alive the project intended to move oil sands crude from Alberta - and pick up Bakken crude along the way - to the southern leg of the Keystone pipeline at Cushing, Oklahoma with options on to the Gulf Coast.
One year later, and six years after the project began the permitting process, Keystone XL remains mired in politics and is no closer to approval at the beginning of 2015 than it was at the end of 2013 (see related story on page 1).
ND pipeline regulation The second main story on the front page of the Dec. 29, 2013, edition reported on the North Dakota Industrial Commission considering a change to the state’s administrative rules giving the commission the authority to regulate all crude oil, natural gas, water and carbon dioxide gathering pipelines from wellhead facilities to transport pipelines regulated by the state’s Public Service Commission.
One year later, gathering pipelines have been under the state’s regulatory authority for nine months. The new rules were the result of HB 1333 that was passed in the 2013 legislature and directed the Industrial Commission to require all gathering pipeline systems installed after Aug. 1, 2011, to register with the state and provide information including GIS data and detailed construction information. Those rules gave the Department of Mineral Resources’ Oil and Gas Division regulatory authority over some 18,000 miles of existing gathering pipelines and an anticipated 30,000 miles of gathering pipe expected to be constructed in the full development of the Bakken play. The rules make North Dakota the only U.S. state to adopt such rules.
Kodiak ceased to existence The third main story on the front page of the last 2013 edition was a company update on Bakken-focused Kodiak Oil and Gas, whose board of directors had just approved a $940 million capital expenditure budget for 2014. The story reported that Kodiak had an active hedging program with more than 26,000 barrels per day of production - approximately 60 percent of the company’s estimated 2014 Bakken output - hedged at an average price of $93.29 per barrel (see discussion on crude oil prices below). Also in the story was coverage of Kodiak’s 2014 production guidance, which put Bakken output at 42,000 to 44,000 barrels of oil equivalent per day as well as downspacing pilots the company was conducting in its core acreage in McKenzie and Williams Counties.
One year later Kodiak no longer exists, having been acquired by Whiting Petroleum Corp. in a transaction first announced in July and finalized in December. That move elevated Whiting past both Hess Corp. and Continental Resources as the Williston Basin’s top Bakken oil producer averaging 127,448 bpd in October.
At the end of 2013, Kodiak ranked as North Dakota’s seventh largest Bakken producer averaging 42,928 bpd. Prior to its acquisition by Whiting in late 2014, Kodiak ranked as the 10th largest producer averaging 51,286 bpd.
Bakken crude conditioning A brief ran on page 1 reporting concerns that a Canadian refinery in New Brunswick had about potential risks associated with Bakken crude oil. Those concerns had been voiced prior to the July 2013 rail disaster at Lac-Megantic, Quebec.
The previous week in the Dec. 22, 2013, edition, two front page stories reported on the safety of transporting Bakken crude via rail, one about the Canadian transport ministry elevating the hazardous designation of Bakken crude, and the other about the U.S. Pipeline and Hazardous Materials Safety Administration considering mandatory new rail tank car standards.
One year later a lot has changed about how Bakken crude is viewed from a transportation safety standpoint. Following considerable debate among industry and government, including a study of Bakken crude properties commissioned by the North Dakota Petroleum Council, the Industrial Commission adopted new rules which will go into effect on April 1, 2015, requiring all Bakken crude oil to be “conditioned” to reduce the vapor pressure to below 13.7 pounds per square inch prior to transport from the well pad.
Throughout 2014, Transport Canada unfolded a series of new regulations including hazardous materials labeling; tougher tank car safety rules; and requiring railroads to conduct risk assessments, develop emergency response plans and enhance security of parked trains.
The U.S. government has not taken final action on mandatory tank car standards. The U.S. Department of Transportation released details of proposed new rules for crude-by-rail in July, but although nothing has yet been finalized. In mid-December, Sen. Charles Schumer, D-New York, renewed a call for phasing out or retrofitting the older model DOT-111 tank cars.
North Dakota flaring A story on natural gas flaring ran in the Dec. 22, 2013, edition and reported that the latest data available from DMR put flaring in the state at 28 percent, down from the 29 percent flared in September 2013. At the time, Hess Corp.’s Tioga gas processing plant was undergoing expansion and was out of operation, and construction was continuing on Oneok’s Divide County gathering system.
One year later the Hess plant is operating (although not yet at capacity due to a pipeline issue), Oneok’s Divide system is nearing completion, two more Oneok gas plants have gone online, gas gathering connections are ongoing, and new regulations are in effect requiring operators to have approved gas capture plans. The result has been a decline in flaring in the state to 22 percent in October (78 percent gas capture), slightly ahead of the state’s Jan. 1, 2015, target of 77 percent gas capture (23 percent flaring). North Dakota’s goal is to further increase gas capture throughout 2015 reaching 85 percent capture (15 percent flaring) by Jan. 1, 2016.
Land and leasing Nominations for the Montana Department of Natural Resources and Conservation’s March 2014 oil and gas lease auction had been released in late December and a story on those nominations ran in the Dec. 29, 2013, edition. A total of 6,012 state acres in 11 tracts were nominated for that auction and the focus of activity was outside of Montana’s portion of the Williston Basin. The largest acreages were in Powder River and Big Horn counties in southeast Montana and in Blaine County in north-central Montana, although there were a few nominated tracts in Richland and Sheridan counties in northeast Montana. At the time, the nominated acreage was the fourth lowest total in a DNRC auction since December 2008 when just 3,333 acres were nominated.
One year later, 35,292 acres in 78 tracts were nominated for DNRC’s March 2015 auction, the largest number of acres nominated since June 2012. And most of those tracts lie within the Williston Basin province (see story, page 1).
Dakota Prairie refinery The weekly photograph in the upper left of page 1 was an aerial shot showing construction of the Dakota Prairie refinery, the 20,000 bpd diesel topping joint venture between MDR Resources and Calumet Specialty Products Partners. The Dakota Prairie is considered a “greenfield” refinery because it was built on undeveloped property and is the first such refinery built in the U.S. since 1976.
One year later that refinery is nearing completion as units are being commissioned with production ramping up in early 2015.
And there are oil prices A brief ran on the front page of the Dec. 22, 2013, edition under the headline “North Dakota Light Sweet still in a Midcontinent price slump.” The importance of that story depends on what one considers “price slump.”
In reporting on crude oil prices in late 2014, Petroleum News Bakken had pointed out that the price of North Dakota Light Sweet as posted on the Flint Hills Resources market is typically 5 to 10 percent below what the state of North Dakota realizes for tax revenues. Through October 2013, NDLS pricing at Flint Hills had generally paralleled Brent and WTI pricing trading at a discount of approximately $9 to WTI; however, in early November, the spread between NDLS and WTI widened and in the last two weeks of 2013, NDLS traded at a discount of more than $20 to WTI.
But those were relative prices. At the end of December 2013, NDLS was trading on the Flint Hills market in the $74 to $75 per barrel range, WTI was trading in the $98 to $100 range and Brent was trading $110 to $112. It’s all relative.
One year later, WTI was trading in the $53 to $55 range, Brent was trading between $57 and $59, and on the Flint Hills market NDLS was trading in the $35 to $37 range.
North Dakota production Petroleum News Bakken also reported preliminary October 2013 North Dakota production data in the Dec. 29, 2013, edition, which had increased by more than 8,000 barrels from September 2013 production averaging approximately 941,000 bpd for the month (final data put that increase at more than 11,000 barrels between September and October 2013). At the time, DMR Director Lynn Helms was expecting a larger increase in production following increases of approximately 21,000, 39,000 and 51,000 bpd in each the three previous months and referred to the approximately 8,000 bpd increase in October 2013 as “lackluster.” That slowdown in growth was attributed to adverse weather conditions that had been plaguing the state.
Fast-forward to October 2013 when North Dakota saw negative production growth, down more than 4,000 bpd from September at an average of just over 1.18 million bpd. That contraction in growth was attributed to both a depressed crude oil market and a curtailment resulting from producers working to meet the state’s new gas capture requirements before bringing wells on production.
2014 was a rough and tumble year for the oil and gas industry, not only in the Bakken but throughout North America and worldwide. Where things go in 2015 remains to be seen, but whatever happens, Petroleum News Bakken will follow events and keep readers informed.
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