So here we are. Last workday of 2017. Which means it’s almost time again to post our annual Top 10 RBN Prognostications for the upcoming year. According to our long-standing tradition, we’ll do that on the first workday of the New Year — Tuesday, January 2, 2018. But today, it’s time to look back, too see how those 10 Prognostications we posted way back at the start of 2017 — The Year of the Rooster in the Chinese calendar — held up. Yes, we actually check our work! In today’s blog, we grade ourselves on our year-ago views of how 2017 would turn out for energy markets.
The new normal. Or at least the market’s perception of a new normal. That’s how we will remember 2017. Producers have come to terms with the possibility of crude prices in the $50-60/bbl range for a long time to come, and natural gas stuck around $3/MMBtu. But even in the face of this sober market outlook, crude oil production is near its all-time record. And Lower-48 natural gas blew past its historic maximum a few weeks back. Increasingly the biggest challenges facing the market are related to infrastructure –– where will all these hydrocarbons find a home. As we have over the past six years, RBN tracked these trends in 2017 as they played out, and now at the end of the year, it’s time to look back to see what topics generated the most interest from you, our readers. We monitor the hit rate for each of our blogs that go out to about 23,000 of our members each day, and the number of hits tells you a lot about what is going on in energy markets. So once again, we look into the rearview mirror to check out the top blogs of 2017, based on the number of rbnenergy.com website hits.
Western Canadian natural gas producers are increasingly facing oversupply conditions and price volatility. While competition and pushback from growing U.S. shale gas supply continues to be a factor, producers are now also contending with fresh problems closer to home — namely transportation constraints right where production is growing the most, in central Alberta. This fall, the Alberta market experienced extreme bottlenecks that left production stranded and sent area gas prices reeling. The ramp-up of winter heating demand has since helped ease the constraints, but the problems are likely to return in the spring when demand is lower, leaving producers exposed to the risk of severe price weakness again in 2018 and limited in their ability to grow supply. Today, we continue our look at what’s behind the local constraints and the implications for production growth and prices in Western Canada.
This winter will be the last go-round for ISO New England’s Winter Reliability Program, under which the electric-grid operator in the natural gas pipeline-challenged region provides financial incentives to dual-fuel power plants if they stockpile fuel oil or LNG as a backup fuel. This coming spring, a long-planned “pay-for-performance” regime will go into effect, and gas-fired generators that can’t meet their commitments to provide power during high-demand periods — such as the polar vortex cold snaps that hit the Northeast in early 2014 — will pay potentially significant penalties. Today, we discuss the pitfalls that the pipeline capacity-challenged region may encounter as its power sector becomes increasingly gas-dependent.
Western Canadian natural gas producers have long battled unrelenting competition from growing shale gas supply in the U.S. But recent price action at AECO — Canada’s benchmark natural gas hub in Alberta — suggests market conditions there have gone from bad to worse. AECO prices in recent months have fallen to the lowest levels in more than a decade, even dropping below zero at one point in intraday trading this fall. Fundamentals are increasingly bearish, given that Canadian gas production has rebounded to the highest level in close to 10 years, storage there is near to five-year highs and exports are facing further cutbacks as U.S. gas supply is itself at record highs. In addition, producers are contending with a number of transportation issues closer to home. Today, we begin a look at the factors affecting the Western Canadian gas market.
The clock is ticking for international shipping companies, cruise lines and others to determine how they will meet the much more stringent standard for bunker fuel sulfur content that will kick in just over two years from now. While many shipowners will likely meet the International Marine Organization’s 0.5% sulfur cap in January 2020 by shifting to low-sulfur marine distillate or a heavy fuel oil/distillate blend, a smaller number are investing in ships fueled by LNG. LNG easily complies with the sulfur cap, and while it costs more than high-sulfur HFO — the bunker that currently dominates world shipping — it is less expensive than the low-sulfur distillate and HFO/distillate blends that will be needed to meet the new standard. But there are catches with LNG, including the need to dedicate more onboard space for fuel tanks and (even more importantly) the lack of LNG fueling infrastructure in a number of ports. Today, we discuss the short and long-term outlook for LNG as a marine fuel.
Just a month ago, the CME/NYMEX Henry Hub prompt natural gas futures contract was trading at a six-month high of $3.21/MMBtu (on November 10), and the U.S. gas storage inventory was at a three-year low, setting the stage for a bullish winter — assuming normal wintry weather. Since then, the prompt-month contract has tumbled about 50 cents to a settle of $2.715/MMBtu as of this Wednesday. In that time, temperatures fell across the country and seasonal demand for heating homes and businesses kicked in, and LNG exports ticked up slightly. But supply also grew by a lot, with natural gas production surging by 1.0 Bcf/d since then to a new record high of 76.9 Bcf/d just this past Monday. How did the fundamentals shake out in November, and what do current fundamentals mean for the balance of winter? Today, we reconcile these latest shifts in gas market fundamentals.
A number of Permian pipeline projects that would help alleviate impending takeaway constraints in the fast-growing production region have advanced in recent weeks — a clear sign that producers, shippers and midstream companies alike are paying close attention. But will these projects be enough, particularly when you consider the flood of capital spending in the Permian by exploration and production companies and the accelerated production growth that it may spur? Today, we discuss the progress midstreamers have been making on the Permian takeaway front as production of crude oil, natural gas and natural gas liquids (NGLs) in the play ratchets up.
Several large-scale gas pipeline expansions targeting the New England and New York City markets have been sidelined in the past year, either due to insufficient financial backing or the challenges of regulatory rigmarole in the region. But in recent weeks, a couple of smaller-scale projects along existing rights-of-way have managed to cross the finish line, allowing incremental gas supplies to trickle into the region. The new pipeline capacity will provide natural gas utilities and power generators in the region with greater access to additional gas supplies from the nearby Marcellus Shale this winter. Today, we look at recent capacity additions and their potential impacts.
U.S. trucking companies, trash haulers and transit agencies continue to invest in new vehicles fueled by compressed natural gas or liquefied natural gas, in part to meet corporate or agency carbon-footprint goals. But the economic rationale for switching trucks and buses from diesel to CNG or LNG is weaker than it was a few years ago, when diesel cost two-thirds more than natural gas fuels on a per-BTU basis — prices for diesel, CNG and LNG are now in the same ballpark. Also, developing regional or national networks of CNG/LNG fueling stations doesn’t come cheap. Today, we discuss the growing use of natural gas in trucks and buses — and threats to that trend.
As a volatile 2017 nears the finish line, the big question for U.S. exploration and production companies (E&Ps) is whether they will throttle back their capital expenditures in 2018, cruise on at the same pace or step on the accelerator. We won’t have all the answers for a couple of months, but early guidance issued along with third-quarter 2017 earnings results indicates a solid 14% increase in investment by seven oil-weighted and diversified producers. The big story among this handful of announcements is a 22% gain in planned 2018 capex by giant ConocoPhillips, which had been slashing investment since 2014. The company’s $2 billion capex boost includes doubling spending on its North American unconventional portfolio. Preliminary guidance for the natural gas producers, on the other hand, tells a different and less interesting story. Six companies, two-thirds of the nine gas-weighted E&Ps we’ve been tracking, indicate their 2018 investment will be relatively flat with the preceding year. So today, we focus on the 2018 plans of the oil producers and take an in-depth look at the ConocoPhillips budgeting process and the company’s noteworthy investment increase.
Producers in the Bakken region made substantial progress in 2014-15 in reducing the volume and percentage of gas that was flared or burned off, but those gains stalled in 2016, and flaring has actually been on the rise through much of 2017. Due to an unfortunate confluence of events (gas processing plant and pipeline issues among them), 16% of the gas produced in the Bakken in September was flared, marking the first time producers failed to meet the state’s ratcheting-down target for gas burn-offs. The October and November flaring numbers are expected to improve, but there are worries that without more processing capacity, Bakken producers will have trouble achieving the North Dakota flaring target when it drops to 12% (from the current 15%) in November 2018. Today, we discuss recent developments in Bakken gas production, gas flaring and gas-related infrastructure.
NGL prices have been rising fast since the middle of this year, but the same cannot be said for the price of natural gas. So how does this market scenario play out for gas processors who make their money extracting NGLs from gas? It plays out pretty darn good. In Part 1 of this series, we looked at how the relationship between the price of NGLs versus natural gas can be assessed by the Frac Spread, and concluded that things are definitely looking up for gas processing economics. But we also concluded that the Frac Spread misses the impact of a few key factors, including the BTU value and composition of the inlet gas stream. So today we’ll see what it takes to incorporate those factors into our assessment and, in the process, do a deep dive into the math of gas processing to examine the relationship between volumetric capacity, gallons of NGLs per 1,000 cubic feet of natural gas (GPMs) and moles. Today, we continue our latest expedition into the wilds of gas processing.
With Lower-48 natural gas production at record highs and averaging more than 5.0 Bcf/d higher than this time last year, LNG export demand will be all the more critical this winter and the rest of 2018 in order to balance the U.S. gas market. Deliveries to Cheniere Energy’s Sabine Pass LNG facility (SPL) are above 3.0 Bcf/d. Dominion Energy’s Cove Point LNG is due to add nearly 0.8 Bcf/d of export capacity and begin exporting commissioning cargoes any day now. Two other projects — Elba Island LNG and Freeport LNG — are due online before the end of 2018, while another high-capacity project, Cameron LNG, faces delays. These facilities will increase baseload demand for gas in the new year, but will it be enough, and how will it impact gas pipeline flows upstream? Today, we provide an update on the timing and potential impacts of new export LNG capacity over the next year.
Last Wednesday, November 22, the Federal Energy Regulatory Commission acted on a Petition for Declaratory Order (PDO) by Magellan Midstream Partners in which the midstreamer asked for FERC’s blessing to establish a marketing affiliate to “buy, sell and ship” crude oil on pipelines owned by Magellan as well as pipes owned by other companies. Today Magellan does not have such an affiliate, although many of its competitors do. Most of those competitors use their affiliates to generate incremental throughput on their pipelines, sometimes by doing transactions that result in losses for the marketing affiliate, but that are still profitable for the overall company because the marketing arm pays its affiliated pipeline the published tariff transportation rate. FERC denied Magellan’s request, coming down hard on such transactions as “rebates” specifically prohibited by the law governing interstate oil pipelines. In today’s blog, we take a preliminary look at FERC’s Magellan order and what it could mean for U.S. crude oil markets.