“New Year’s Day” – A Look Back and a Peek to the Future

By John Auers and Robert Auers

New Year’s Day was U2’s first hit single, both in the UK and internationally, and we believe it is very appropriate to use as the theme for our blog today – reviewing key energy developments in 2017 and also providing a glimpse of what 2018 might hold.   The past year was truly an eventful one for the oil industry, with major and potentially trend-setting developments in all segments of the business.   A variety of forces were at play in these events – government policies, geopolitical turmoil, natural disasters, market shifts, technological advances, etc.  Certainly, the changeover from the Obama to Trump Administration created a very different (and more positive) dynamic in the world’s most important petroleum industry, and the year ended with the passage of a tax bill which could be the most impactful force of all.   Aided by the stimulus that a huge cut in the corporate tax rate will provide, optimism about economic growth is surging and that is always goes news for the energy industry.  The upstream segment is benefitting from oil prices that have reached their highest levels in two and one half years and this has allowed, U.S. shale producers to sustain a return to strong production growth. This growth is stimulating midstream projects, which have also gotten an important boost from more supportive policies from Trump’s regulators.  Continued strong product demand, both in the U.S. and worldwide, helped refining margins bounce back in 2017, although individual refineries, particularly in the U.S. and Mexico, had to deal with significant challenges from Mother Nature (hurricanes, earthquakes etc).  But while the industry has many reasons to feel optimistic about the short-term environment, 2017 also brought an ever-increasing doomsaying about “peak demand”, “stranded oil” and accompanying worries about the long-term future of petroleum.  U2’s “New Year’s Day” was an anthem celebrating the optimism about a return of freedom in Eastern Europe when the first cracks in the Iron Curtain began to spread; today, we examine what happened in 2017 and see what that might mean for the future of oil.

The Upstream – “We can break through

Oil prices began 2017 on a bit of a roll, having increased by about 20% in the last few weeks of 2016 after OPEC announced their plan to cut crude beginning in January 2017.  While crude prices remained above $50 (for Dated Brent) through the first few months of the year, optimism over the cuts declined and by the summer Brent was back in the $40’s.  However, continued production discipline by OPEC and their key non-OPEC partner, Russia, combined with healthy demand led to inventory declines and a return to optimism, despite continued strong production growth in the U.S..  Prices have been on an upward trajectory for much of the second half of 2017, which accelerated a bit towards the end of the year, with Brent prices closing the year near a two and a half year peak reached earlier in December.

The recovery in oil prices, combined with an every improving ability to efficiently extract oil from tight formations led to a dramatic turnaround in in U.S. oil production growth in 2017.  Although final production numbers will not be in for a few weeks, it appears that domestic production will have grown by about 1 million BPD in 2017, more than recovering all the volume lost over the previous two years.   As we head into 2018, it appears that production is certainly set to “break through” the all-time U.S. record of 10 million BPD (set in 1970) sometime during this year. 

Additionally, as a result of the strong production growth and facilitated by the late 2015 repeal of the crude export ban, we saw a surge in U.S. exports during the final four months of 2017, peaking in November at just over 3 MMBPD (as implied by EIA’s weekly numbers).  Moreover, we’ve seen the number of different destinations for U.S. crude exports expand, with Western Europe and China leading the way.  It should be noted that the refinery outages on the USGC as a result of Harvey also contributed to the export surge. The graph below shows U.S. crude exports by country through October 2017.

The Midstream – “Oh maybe the time is right

The time certainly seemed right for the midstream industry in the U.S. in 2017 as it was the most visible and immediate beneficiary of the changeover in Presidential Administrations.   This was most evident in the reversal of Obama Administration decisions denying approval for both the Dakota Access (DAPL) and Keystone XL (KXL) pipelines.  In the case of DAPL, this had an immediate impact on crude flows in the U.S. The 570 MBPD pipeline started up in June and has resulted in a significant shift of Bakken flow away from the East Coast and toward the Gulf Coast and offshore.  This has also caused a reversal of the Bakken (ex-Clearbrook) – WTI  differential, with Bakken (ex-Clearbrook) averaging nearly $3 over WTI during the month of October (vs. ~$1 under WTI prior to pipeline’s completion).  It should be noted that WTI at Cushing is often a blended crude and receives a quality discount due to undesirable refining properties.  (Still, this too might change, with Enterprise announcing that new specifications for WTI at its Cushing terminal (a physical delivery point for NYMEX WTI) will be added in January 2019.)

Meanwhile, strong production growth in the Permian has contributed to the announcement of a host of new projects that will transport crude oil to the Gulf Coast, where this new production can be exported abroad.  These include four separate pipelines to Corpus, announced by TexStar, Plains, Magellan and Buckeye, with a total eventual proposed capacity of 2.3 MMBPD. Initial startup for all of these projects is currently planned for 2019.  TexStar’s 590 MBPD EPIC pipeline, however, is only one of these that has already completed a successful open season, while Plain’s Cactus II and Buckeye’s Southern Gateway recently launched binding open seasons.  Magellan is still gauging shipper interest in its pipeline, but has yet to launch a binding open season.  Furthermore, Kinder Morgan recently announced its final decision to proceed with its nearly 2 Bcf/d Gulf Coast Express gas pipeline, slated for 2019, that will help relieve Permian gas takeaway concerns.  However, a shortage of Permian pipeline takeaway capacity may develop during the second half of 2018 and into early 2019, until sufficient new takeaway capacity can come online to support the continued rapid Permian production growth.

Pipeline bottlenecks out of Cushing have emerged as well, due not only to growing Permian production, but also a return to production growth in the Anadarko and DJ Basins.  This bottleneck has significantly contributed to the widening of the LLS-WTI differential from near $2 for most of 2017 to roughly $6 for most of the fourth quarter.  Nonetheless, the recent startups of the 200 MBPD Diamond Pipeline to Memphis, TN, and the 115 MBPD expansion of the Ozark Pipeline to Wood River, IL, should help relieve these constraints, at least for the time being.  Looking farther out, the eventual reversal of the Capline Pipeline, from Patoka, IL to St. James, LA, may eventually allow Canadian and other mid-continent crude to avoid the Cushing hub altogether.  Still, as this project is not slated for completion until late 2022, additional Cushing takeaway capacity bottlenecks may emerge, especially if mid-continent production growth (primarily in Oklahoma, Colorado, and Wyoming) is stronger than expected.

Lastly, Canadian pipeline capacity is currently being stretched to its limit, leading to an increase in crude by rail from the region.  The production ramp up of the 200 MBPD Fort Hills project, which will continue through 2018, will further strain current infrastructure.  Moreover, other smaller upstream projects will continue to come on line in Western Canada over the next 5-10 years, requiring additional new takeaway capacity from the region.  Three well-known projects have been proposed to help alleviate this constraint – the Enbridge Line 3 Replacement, Keystone XL, and the Kinder Morgan TransMountain Twin.  Two of these three projects will likely be necessary to meet pipeline demand over the next decade, but all three face challenges, including continued regulatory scrutiny despite the improving U.S. federal environment.  While it is unclear which ones will ultimately be completed, we will learn much about those probabilities in 2018, as decisions are rendered by regulatory authorities in Minnesota, Nebraska, British Colombia/Canada and the sponsoring companies themselves make determinations on how to proceed.  In the meantime, until a new pipeline project can be completed out of Western Canada (likely not until at least 2019 when the Line 3 project could be started up), growing volumes of crude by rail will be needed move oil out of the region.

The Downstream – “And so we’re told this is the golden age

Whether another Golden Age is imminent or not, prospects for refiners in the U.S. certainly did see some positive momentum in 2017.  We witnessed continued strong worldwide demand growth of approximately 1.5 MMBPD in 2017, following growth 1.6 MMBPD and 1.8 MMBPD in 2016 and 2015, respectively.  U.S. demand, meanwhile, also showed respectable growth, once again, of 160 MBPD, following 150 MBPD and 400 MBPD of demand growth in 2016 and 2015, respectively.  Furthermore, Latin American refining woes have continued, exacerbated by natural disasters (especially in Mexico).  Texas’ Gulf Coast refiners (and a few in Louisiana) faced their own share of operating issues related to Hurricane Harvey, but were able to recover much quicker than their Mexican counterparts.  All of this led to continued generally strong refining margins (especially immediately following Harvey) for the year and the third year in a row 90%+ U.S refinery utilization, despite as much as 23% of U.S. refining capacity being offline in September due to Harvey.  Furthermore, the U.S. midcontinent has seen an additional benefit from the widening WTI-LLS and WCS-Maya differentials that have decreased their supply costs (relative to the USGC and USAC peers) during the final four months of the year.

Still, some troubling signs appeared after the surge in margins related to Harvey.  While diesel margins have remained strong (and have recently strengthened more due to the ongoing cold snap), gasoline margins have fallen considerably since peaking in September.  USGC RBOB Regular – LLS, for example, slipped from $18 in September to roughly $9 in December.  In addition, RVO compliance costs amounted to roughly $6 per barrel of BOB sold in December, assuming the refiner purchased the necessary RINs to cover its RVO (instead of blending renewable fuel themselves).

This brings us to our next issue for U.S. refiners, that is, rising RIN prices.  The end effect of RVO compliance costs on refiners’ bottoms lines is something that it difficult to determine, but, as we discussed a few weeks ago, we believe that they are substantially passed onto consumers.  Potentially rising RIN prices, therefore, likely will not determine U.S. refining profitability going forward, but they are still certainly a hot topic in the industry and one that we continue to monitor.

Since Turner, Mason & Company is in the business of analyzing downstream markets and assisting all segments of the oil industry in responding to changing market dynamics, recent developments and trends certainly hold center stage in our work.  We are in the process of absorbing the changes and potential responses and incorporating our analysis into developing updates of both our short-term and long-term forecasts regarding supply, demand and prices for both crude oil and petroleum products.   These detailed supply and demand and price forecasts will be included in our 2018 Crude and Refined Products Outlook, scheduled to be issued in early February 2018 and also be used in our other industry analysis and work products.   In addition, our Worldwide Refinery Construction Outlook, also to be released in early February, provides a detailed list of global proposed refinery construction projects and an estimated likelihood for the eventual completion of each.  For more details about these publications or other TM&C services, please visit our website, send us an email or give us a call at 214-754-0898.