Renewable and hydroelectric generation has chomped away at natural gas market share of total power generation along the West Coast this year. The latest electric generation data from the Energy Information Administration shows power sourced from renewables (not including hydro) in California, Oregon and Washington combined in April 2017 through July 2017 edged up about 1% year-on-year, while hydroelectric generation averaged 23% higher year-on-year. At the same time, natural gas-fired generation fell 16% year-on-year. The reduced gas-fired generation demand, along with reduced gas storage capacity in the West, has displaced natural gas from the region and disrupted recent gas flow patterns. These shifts provide a glimpse of what gas flows and pricing dynamics could look like as more renewable capacity is added. In today’s blog, we analyze the effects of electric generation trends on regional gas flows.
Daily Energy Blog
The 43 U.S. exploration and production companies (E&Ps) we’ve been tracking racked up $160 billion in losses in 2015-16, but they turned things around in the first quarter of 2017, posting profits of $9.1 billion, or $9.12 per barrel of oil equivalent (boe), during that three-month period. At first glance, the second quarter might seem like a return to tough times; profits by the group fell more than 80%, to only $1.7 billion, or $1.71/boe. However, when $6.3 billion in impairments by ConocoPhillips — most of them tied to $16 billion asset sales and a write-down of the Australia Pacific LNG project — are excluded, second-quarter profits by our universe of Oil-Weighted, Diversified and Gas-Weighted E&Ps totaled $8.0 billion, or $8.02/boe, a decline of only 11.6% from the first three months of 2017. Today, we begin a review of E&P performance and profitability with a big-picture look at key elements of their income statements.
Russia is a major producer — and exporter — of crude oil and natural gas, and a major exporter of refined products to boot. So it’s important to keep an eye on what’s going on in Russia, because as U.S. producers and refiners know all too well, what happens halfway around the world often has ripple effects in places like the Permian, the Houston Ship Channel and the Sabine Pass LNG terminal. Today, we discuss Russian crude production and refinery output, its compliance with the OPEC/NOPEC agreement to rein in crude production, and the country’s efforts to steer more of its crude and refined-products exports to Russian ports. This blog is based on the latest FSU Monthly report from our friends at FGE – Facts Global Energy.
The rise of renewable energy has transformed power markets in the U.S. West Coast states, particularly California. The Golden State has added significant renewable power generation capacity in recent years. Additionally, record precipitation in the Pacific Northwest and California this year boosted hydroelectric generation in the region. These factors have reduced the natural gas market share of power generation in California and other Pacific Coast states, which has important implications for the U.S. gas market as a whole, especially considering that the Eastern U.S. is increasingly oversupplied and pushing its gas supply westward. Today, we look at the year-on-year changes in the West Coast power generation sector and their effect on the gas market this summer and longer term.
California’s 12 remaining refineries don’t feel much love from their native state. The refinery fleet is particularly sophisticated — capable of refining mostly heavy and sour crude oil into the ultra-clean transportation fuels that state rules require. But state regulators seem to treat refiners like unwanted guests, to the point that rules have been put in place to actively encourage the shift from petroleum-based fuels to lower-carbon alternatives. The reward for refiners’ pain comes in the form of higher refining margins — particularly during unplanned outages. Today we weigh the rewards of higher gasoline and diesel prices today against a questionable future for refining in the Golden State tomorrow.
Since last winter, the price gap between light crude oil and heavy crude — otherwise known as the light-heavy differential — has narrowed considerably. In February, the price difference between Louisiana Light Sweet crude (LLS) and heavy Maya crude on the Gulf Coast was almost $10/bbl, providing an advantage to refiners who have invested in cokers and other equipment that allows them to run a heavier crude slate. But since June Maya has on average sold for only about $5/bbl less than LLS. Today we examine the shrinking price gap between light and heavy crude and its effect on coking and cracking margins.
An analysis of mid-year 2017 guidance shows that the nine natural gas-focused exploration and production companies we’ve been tracking are still fully committed to the very aggressive exploration and development spending they outlined at the beginning of the year. These Gas-Weighted E&Ps slightly upped their total 2017 capital budgets to $8.87 billion, a whopping 59% boost from their 2016 investment — well above the 44% and 29% increases announced by the Oil-Weighted and Diversified E&P peer groups, respectively. The gas-focused producers also increased their 2017 production guidance by 1% to 1.046 billion barrels of oil equivalent (Bboe), in contrast to the mid-year reductions in 2017 output announced by the other two peer groups. Today, we continue our review of updated capital spending plans by 43 U.S.-based E&Ps, this time with a look at companies that focus on natural gas.
Three weeks ago, Hurricane Harvey threw a wrench in — well in a lot of things — but also into the natural gas market, curbing gas demand for power generation, curtailing pipeline exports to Mexico and stymying LNG exports. The market is still digesting the full impact of these disruptions and their potential effects on the gas market balance and storage. Adding to recent market shifts is the start-up of Energy Transfer Partners’ (ETP) Northeast-to-Midwest Rover Pipeline Phase 1A on September 1, which already is flowing 0.7 Bcf/d and lifting gas production out of Ohio. The market is hurtling towards winter, with just five weeks or so left until heating demand typically starts showing up and storage facilities officially begin to flip into withdrawal mode. What can recent supply and demand volumes tell us about what to expect from the gas market this winter? Today, we wrap up our most recent gas market update series with a forward look at potential scenarios for supply, demand and storage in the coming withdrawal season.
California refiners are under siege. State regulators seem to view crude oil refining as a nasty habit that needs to be broken. There’s an important catch, though: car-happy California is not only the nation’s largest consumer of gasoline — and second to Texas in diesel use — it allows only special, superclean blends to be sold within its boundaries. And California’s 12 remaining refineries need to meet tougher emission standards, too, making it difficult for them to expand their business or even modernize their plants. Today we discuss the irony that sophisticated refineries producing the cleanest fuels in the U.S. are faced with a shrinking market and no real hope of expansion.
In another key milestone for Northeast pipeline takeaway capacity expansions, Energy Transfer Partners’ beleaguered Rover Pipeline project began partial service on its Phase 1A portion on gas day September 1. The 3.25-Bcf/d project, which is due for completion in early 2018, is expected to provide relief for constrained Northeast producers while exacerbating oversupply conditions and gas-on-gas competition in the Dawn, Ontario, storage and demand market area and surrounding region. Within days of initial start-up, flows on Rover ramped up to 700 MMcf/d, and both Ohio and overall Northeast production already have posted record highs since then as a result. Today, we take a look at the project, including initial flows and the expected timing of full completion.
Natural gas liquids production in the Permian Basin has doubled in the past four years, and may well double again by 2022. That rapid growth — driven by the pursuit of Permian crude oil and the resulting production of large volumes of NGL-rich associated gas — threatens to overwhelm the region’s existing gas processing and NGL-pipeline infrastructure. This is a big deal, because if there’s not enough gas processing and NGL takeaway capacity out of the Permian, exploration and production companies (E&Ps) in the U.S.’s hottest shale play would be forced to slow the pace of their development. Today we discuss highlights from our new Drill Down Report on Permian NGL production growth and the need for more NGL-related infrastructure.
Today’s energy markets are being rocked by new technologies, massive flow shifts to exports, and a myriad of new midstream infrastructure projects — to say nothing of the continuing onslaught of Mother Nature. It is more important than ever to understand how the markets for crude oil, natural gas and NGLs are tied together, and that is why it is time again for RBN’s School of Energy. But … this is not the best time for our Houston conference venue. So we’ve made the decision to GO VIRTUAL! We will webcast the entire School in real-time, with the same content, the same faculty and the same models. And since an understanding of the new realities of today’s energy markets is so essential, we have renewed, restructured and rebuilt our curriculum to CONNECT THE DOTS across our content, data and models. That’s the theme for our upcoming School of Energy 2017 – Virtual Edition, which we summarize in today’s advertorial blog.
Even with a double-digit percentage decline in crude oil prices since their initial capital spending budgets for 2017 were set, the 13 diversified U.S. exploration and production companies (E&Ps) we’ve been tracking are trimming their spending plans for the year by only $300 million, largely keeping in place $19 billion in drilling and completion investment. The Diversified Peer Group’s apparent confidence flies in the face of eroding investor sentiment as the median enterprise value per barrel of oil equivalent (boe) of reserves has declined 23% since year-end 2016 to $13.72/boe. Today, we review the changes in the outlook for the Diversified Peer Group’s upstream capital spending plans and update their expectations for 2017 oil and natural gas production.
A federal appellate court decision has set back the approval of a newly completed set of natural gas pipelines in the U.S. Southeast, and raised the possibility that all gas pipeline projects will need to clear a new — and potentially challenging — hurdle before they can secure a final OK from the Federal Energy Regulatory Commission (FERC). In its late-August ruling in Sierra Club, et al vs. FERC, the U.S. Court of Appeals for the District of Columbia Circuit said FERC’s environmental impact statement for the Southeast Market Pipelines Project, which includes the 1.1-Bcf/d Sabal Trail pipeline from west-central Alabama to central Florida, should have considered greenhouse gas emissions from gas-fired power plants the new pipelines will serve. Today, we explore the potentially far-reaching effect of the decision on midstream companies and the utilities that depend on them.
Last week Hurricane Harvey roiled the entire energy complex, with NGL markets suffering substantial disruption — curtailed natural gas liquids production from gas processing in the Eagle Ford and other basins, reduced operating rates at Mont Belvieu and other fractionation sites, shuttered LPG and ethane export docks, widespread refinery closures and a virtual shutdown of Gulf Coast petrochemical plants. While little major damage to facilities has been reported and several plants are now restarting, operating conditions continue to be extremely difficult for both the supply and demand sides of the market. Today we continue our look at how high winds and days of torrential rain affected the U.S. energy industry, this time focusing on NGLs.
