A long-standing tradition at RBN is our annual Top 10 RBN Energy Prognostications blog, where we lay out the most important developments we see for the year ahead. Unlike so many forecasters, we also look back to see how we did with our forecasts the previous year. That’s right! We actually check our work. Usually we can get that all into a single blog. But a lot will be coming at us in 2017, so this time around we are splitting our Prognostications into two pieces. Tomorrow’s blog will look into the RBN crystal ball one more time to see what 2017 has in store for energy markets. But today we look back. Back to what we posted on January 3, 2016. Recall back in those days that crude production had not started to decline materially, West Texas Intermediate (WTI; the U.S. light-crude benchmark) was at $37/bbl, natural gas was $2.33/MMbtu in the middle of winter, Congress had just OK’ed crude exports, and weak exploration and production companies (E&Ps) were dropping like flies. Now let’s look at RBN’s Prognostications for 2016.
Like all good New Year’s Top 10 lists, we’ll start at #10 on last year’s list and work our way down to #1.
10. We will finally start to see meaningful declines in U.S. crude oil production. Yup, we did experience the first significant declines in U.S. production since the onset of the Shale Revolution, down 1.0 million barrels/day (MMb/d) from the April 2015 high of 9.6 MMb/d to 8.6 MMb/d in September 2016. But we’ve got to admit, crude production was more resilient than we expected, and 2016 will come in only about 600 Mb/d below the 2015 average, year-on-year. Lesson learned? U.S. producers can get really innovative when appropriately motivated—and survival is a powerful motivator.
9. Those production declines will not translate into a sustained price recovery. Another good one. In 2015, WTI crude prices averaged $48.70/bbl. Despite declining U.S. production for most of the year, the average WTI price for 2016 was $43.30/bbl—down $5.40/bbl, so certainly no recovery. But wait, you say, aren’t prices at $53 and change today? Yes, they are, but we only had 36 days in 2016 when the price was over $50/bbl. Back in 2015, not many would consider that a sustained recovery. And anyway, most of the recent recovery has more to do with OPEC than production declines, right?
8. OPEC will not save U.S. producers from themselves. Last year we were skeptical that OPEC would reach any agreement to cut production, and technically the prediction was correct, given that the cut was not supposed to begin until January 1, 2017. But we’ve got to admit, they did something. Exactly what? We’ll explore that question in our 2017 Prognostications blog tomorrow.
7. The market has yet to recognize the depth of LNG’s problems. Well, the industry may have now recognized the problem. But does it matter? The sentiment seems to be best stated by one of our greatest market thinkers, Alfred E. Neuman, who profoundly asked, “What, me worry?”. The first two 4.5-million-tonne-per-annum (MTPA) liquefaction “trains” at Cheniere Energy’s Sabine Pass LNG site are already churning out LNG, and two more trains are planned to come online there over the next year or so. Dominion’s Cove Point facility is scheduled for startup in late 2017 or early 2018, adding another 5.25 MTPA. And still another nine trains along the Gulf Coast (combined capacity, ~40 MTPA or nearly 6 Bcf/d) are slated to come online in 2018-20. Of course, Australia has been on a LNG train-building binge of its own. But even in the face of this potential huge oversupply, the LNG industry is taking an optimistic view that international demand for LNG will pick up to absorb much of the excess, and is already gearing up for a second wave of U.S. LNG export terminal construction. Now that’s the power of positive thinking.
6. Midstream infrastructure is overbuilt. It was, and it is. From pipelines to natural gas processing plants, docks and ships, the midstream industry went on a construction bender during the shale heyday, based on a very optimistic production-growth outlook. They told themselves everything would be OK because of the take-or-pay commitments from producers that secured their investments. That worked out for most new projects. But what about all of the legacy assets with far fewer commitments, subject to having volumes “stolen” by new projects? Well that is exactly what has happened. Most midstreamers have been able to work through the challenges, but not without a lot of angst and hard negotiations.
5. The midstream overbuild will distort price differentials. Distort means price differentials far below the cost between the inlet side and the outlet side of a midstream asset, and we have ample evidence of this one. For example, shippers signed up for capacity at more than $3/bbl to move crude oil from Cushing to the Gulf Coast on one of several pipeline projects. But the differential averaged only $1.50/bbl in 2016, never getting higher than $2.00/bbl. We hear that anchor shippers on the Seaway Pipeline can’t sell capacity for more than one-tenth of what they committed to pay. Now that’s distortion. It’s the same across most U.S. midstream sectors, and is a classic result of overbuilding.
4. Crude oil exports will be a yawner. Sadly for most hopeful exporters, 2016 was pretty much a yawner. Total crude exports in 2015 (when exports were essentially limited to Canada) came in at 465 Mb/d, and we figure that 2016’s final numbers will show little more than 100 Mb/d above that. It’s should not be much of a surprise, given that the Brent to Louisiana Light Sweet (LLS) differential (a reasonable indicator of the spread to be captured by exporting U.S. crude) averaged only $0.35/bbl in 2016—hardly enough to justify the cost of dock capacity and a ship. Nevertheless, shippers are finding creative ways to make a few export deals work, and the happy news for ship owners is that most of these crude shipments are going to Asia, Europe and Latin America, versus Canada in 2015, which means longer voyages and demand for more tonnage.
3. Gas processing is a cost of doing business. It was another problematic year for the frac spread, the differential between natural gas prices and a basket of NGLs. The frac spread averaged a paltry $2.40/MMbtu in 2016, far below typical processing costs, plus the cost of transportation and fractionation for the liquids. So why process? Two reasons: Because processing is necessary for the natural gas to meet pipeline specs, and because in many cases producers signed up for take-or-pay capacity deals at new gas processing plants, and now have to pay for that capacity whether they use it or not—so even at today’s paltry frac spreads, they are better off using it. But stay tuned to 2017. This story is in for a change.
2. It’s about the money. We were generally right about this one. Access to capital did separate the winners from the losers, but it turned out that capital was a bit more accessible than we had expected, especially if you had bite-size requirements for it and could source funds from not only banks, but private equity, sovereign funds, public markets, and all manner of investors that concluded 2016 was the bottom of a market poised to flourish. In total, the 46 E&Ps that we track in our periodic capex analysis (see Back in the Saddle Again and Different Strokes) raised $56 billion to repair their balance sheets and to acquire lots of acreage from the less fortunate. That’s a lot of money.
1. The strong will devour the weak. Well, the strong did devour the weak, but mostly in smaller bites. Companies with good strategic positions and access to capital have been gnawing away at pieces of weaker companies that need capital to survive, either because they entered the downturn in a weak financial position, find themselves in the wrong geographic locations, or both. These weak companies do not want to throw in the towel. They have taken all possible actions to avoid bankruptcy or financial dismemberment by selling non-core assets, including undeveloped acreage, gathering/processing assets, and wells/acreage where they do not have the critical mass of operating activities that offer opportunities to cut costs and streamline operations. In effect, the stronger companies are like schools of piranha, eating small pieces of weaker companies in hundreds of transactions that are simultaneously fragmenting and reconstituting the U.S. E&P sector. We’ll have a special report on this market development coming early in 2017.
Overall it was a pretty good year for RBN’s Prognostications business. Looking back, the first half of the year was a bit tougher than we expected, while the end of the year was a bit better. But overall, we saw modest improvement in prices, somewhat higher rig counts that we would have expected at these prices, and easier access to capital than we would have thought these prices would justify. That is a good setup for the 2017 Prognostications that we will explore tomorrow. They will include our outlook for prices, production, capital, E&P investment strategies, and even some thoughts about the incoming Trump administration.
Happy New Year!