ANS

Alaska North Slope (ANS) crude oil production has been sliding for years — decades really — but that is poised to change in the second half of the 2020s. Two long-planned ANS projects — Pikka and Willow — are slated to start up in 2026 and 2029, respectively. By the early 2030s, these and other projects in the works could return North Slope production to levels not seen since the turn of the century. In today’s RBN blog, we’ll discuss these projects and our new, long-term forecast for ANS oil production — a topic in our upcoming Future of Fuels report. 

The renewed focus on energy security — and the acknowledgment that the world will continue to rely on hydrocarbons for decades to come — may be breathing new life into an often-overlooked U.S. production area: Alaska’s North Slope. The state’s crude oil output is down to its lowest level since before the Trans-Alaska Pipeline System (TAPS) came online in 1977. But now federal regulators are moving toward final approval for ConocoPhillips’s $8 billion Willow project in the National Petroleum Reserve, and Australia’s Santos Ltd. and Spain’s Repsol have taken a final investment decision (FID) on the $2.6 billion first phase of their Pikka project between Willow and Prudhoe Bay. In today’s RBN blog, we discuss recent hydrocarbon-related developments in America’s Last Frontier.

<p>Independent refiner PBF Energy on June 11 announced its plan to acquire Shell Oil’s Martinez, CA, refinery for about $1 billion; the deal is expected to close by the end of 2019. The purchase will give PBF its sixth U.S.</p>

Forty years ago, Alaska was seen as the next big thing for U.S. crude oil production––and it was. With the completion of the Trans Alaska Pipeline System in 1977, Alaska North Slope production took off, and by early 1988 it was topping 2 MMb/d and accounting for nearly one-quarter of total U.S. output. But that was the peak; since then, ANS production has fallen steadily, and in August 2016 it averaged only 443 Mb/d, or 5% of the national total. While there is clearly a lot of oil (and natural gas) still in the ground in the North Slope region, developing those resources would be very costly. Today we begin a two-part series on energy production in the 49th state with a look at the oil side of things.

Although California refineries initially met the criteria that spurred development of crude-by-rail (CBR) shipments to other coastal regions (lack of pipeline infrastructure and wide crude price differentials between stranded inland supplies and coastal alternatives) neither rail shipments or terminal build outs have made much of a dent in the Golden States’ crude supply. At their height in December 2013 CBR shipments into California reached 36 Mb/d – just 2% of the State’s 1.9 MMb/d refining capacity and they have since dwindled to a trickle. Today we examine the low pace of shipments.

Most of the crude by rail  (CBR) shipments to 4 refineries in Washington State are ex-North Dakota from where rail freight costs are over $10/Bbl. Bakken crude from North Dakota competes at Washington refineries with Alaska North Slope (ANS) shipped down from Valdez, AK. Back in 2012 ANS prices were more than $20/Bbl higher than Bakken crude – easily covering the rail cost. In 2016 so far the ANS premium to Bakken has averaged well below the $10/Bbl freight cost making CBR shipments uneconomic. But as we discuss today - Northwest refiners are still shipping significant volumes of crude from North Dakota.

Crude by rail (CBR) shipments from North Dakota to West Coast destinations peaked in January 2015 at 170 Mb/d – falling since then to average 140 Mb/d in 2015, January through May. The vast majority of these shipments have moved to four refineries in Washington State – providing a cheaper alternative to the Alaska North Slope (ANS) crude staple these refineries have run for decades. There is big potential to expand CBR shipments to West Coast Ports and to California but building the infrastructure has proven painstakingly slow. Today we discuss the long term fate of West Coast CBR.

Yesterday (August 3, 2015) Brent crude closed under $50/Bbl for the first time since January 2015. At that price expensive crude-by-rail (CBR) freight costs to the East Coast leave Bakken producers with netbacks not much over $30/Bbl. Yet CBR shipments to the East Coast were still over 400 Mb/d in May 2015 according to the Energy Information Administration (EIA). By 2017 there should be adequate capacity to get all Bakken crude to market by pipeline. But direct pipeline competition against rail to the East Coast is not expected until at least 2020. Today we look at the future of East Coast CBR.

In 2015 Alaskan crude has enjoyed something of a change in fortunes compared to the past few years – when shale production seemed to threaten its future. Production was up by over 50 Mb/d in the first 4 months of 2015 (according to the Energy Information Administration – EIA). The market share of Alaskan crude in West Coast refineries also crept up by 1% this year compared to 2014 at a time when crude throughput at those refineries increased. Today we discuss the changes and whether they are likely to continue.

Since the start of the shale oil boom in 2011 crack spread margins for Midwest refiners have averaged about $23/Bbl. Once written off refineries on the East Coast have averaged $16/Bbl this year so far (2015) and California refiners are currently enjoying average $24/Bbl crack spreads. Refinery utilization at the Gulf Coast has averaged close to 90% for the past 4 years and 92% in the Midwest. Today we review buoyant margins and operating levels at U.S. refineries.