After posting huge pretax operating losses in 2015-16, the nine U.S. natural gas-focused exploration and production companies (E&Ps) we’ve been tracking returned to profitability in the first quarter of 2017. This reversal of fortunes in peer group performance was driven mostly due to higher natural gas prices, which ended a massive flow of red ink that had principally resulted from big reserve write-downs. Now, with higher profits and cash flows, these producers are ramping up their 2017 capital budgets and planning for long-term production growth. Today we continue our series on the financial performance of 43 U.S. E&Ps, this time zeroing in on companies whose hydrocarbon reserves are mostly natural gas.
Daily energy Posts
Over the past few weeks, publicly traded independent refining companies reported their latest quarterly results, and nearly all lamented on a common theme: the cost of Renewable Identification Numbers (RINs) is out of control. However, the financial burden is not felt equally across the industry, as companies with integrated marketing operations (refining, blending and retailing) don’t face the same RINs-cost albatross as merchant refiners who don’t have retail operations. Today we review the escalating RIN costs that obligated parties have endured this year and explain how the degree of financial pain depends on the level of refiners’ downstream integration.
Global demand for motor gasoline is on the rise, and U.S. refineries—as a group, still the most sophisticated in the world—are poised to play a critical role in providing much of the needed incremental gasoline supply to Asia, Latin America and other growing markets. This important topic was the focus of a recent talk at the Center for Strategic and International Studies (CSIS) by our good friend, Dr. Fereidun Fesharaki, chairman of international energy consultant FGE, who also discussed the International Maritime Organization’s (IMO) new (and controversial) decision to limit sulfur in bunker fuel to 0.5% by January 2020—a move that will test the capabilities of refineries worldwide. Today’s blog provides highlights from this presentation.
The shale boom breathed new life into East Coast refineries that were under threat of closure by their owners between 2009 and 2012. Now some of those same refineries are under threat again, this time due to poor margins as well as the high cost of compliance with environmental regulations. After enjoying three years of improved margins through access to advantaged domestic crude delivered by rail from North Dakota, five East Coast refineries are now paying international prices for imported crude again in 2016 after differentials between domestic benchmark WTI and international equivalent Brent narrowed to less than $1/bbl in the wake of the crude price crash and an end to the federal ban on most crude exports. Today we discuss PADD 1 refinery prospects.
New “Tier 3” requirements to limit sulfur content in gasoline are set to take effect in just over two months — on January 2017. In March 2013, the Environmental Protection Agency (EPA) proposed to limit the sulfur content of gasoline produced or imported into the U.S. to no more than 10 parts per million (ppm) from the current “Tier 2” 30 ppm standard by January 1, 2017. With these upcoming “Tier 3” requirements, refiners have been developing their strategies to meet the regulations and in some cases have already invested hundreds of millions of dollars in their facilities. Today, we look at the various approaches refiners can take for compliance and their impacts on the industry.
For the past month, WTI crude oil prices have averaged $49/bbl, trading within a relatively narrow $7/bbl range. Two years ago, this price would have been devastating for producers, but not so in late 2016. The crude directed rig count is up by 127 since May, +11 just last week. U.S. crude production is down about 1.2 MMb/d since April 2015, but over the past three months has stabilized at 8.5 MMb/d. On the gas side, since the second quarter of 2016 a combination of lower natural gas production and higher demand (from the power, industrial and export sectors) has worked off a big inventory surplus. Consequently, U.S. natural gas prices are up more than 70% since March, even considering the big price drop over the past week. NGL prices are at the highest value relative to crude for any October since 2012. Is this it? Is this what a Shale Era recovery looks like? In today’s blog, we consider a possible road map for the next couple of years. Warning, we have also included a short infomercial for RBN’s School of Energy next week in Houston.
The increase in waterborne flows to the East Coast in response to the recent Colonial Pipeline outage illustrated the flexibility of supply in the U.S. motor gasoline market. At the same time, the lack of a lasting impact from the loss of 8.3 million barrels of gasoline to a key U.S. demand region highlighted the degree of oversupply in the market. Today we look at how waterborne flows helped to mitigate the effects of the Colonial Pipeline outage, and how flexibility in the East Coast motor gasoline market enabled it to handle unexpected supply constraints with minimal disruption.
U.S. crude oil prices languish below $50/bbl, but the oil-directed rig count is up by 90, an increase of almost 30% over the past 12 weeks. Natural gas production is down less than 1% from the all-time high hit back in February even though the price of natural gas remains below $3/MMbtu. The price spread between U.S. propane and international markets is far below a level that should justify exports, but LPG exports to overseas markets continue at astronomical levels –– approaching 700 Mb/d, most of which is propane. What’s wrong with this picture? Why does it seem that relationships between energy production, demand and prices have broken down, or at least have undergone some fundamental shift? That is what our upcoming School of Energy Fall 2016 is all about. Warning: Today’s blog includes a commercial for our upcoming Houston conference, scheduled for November 2 and 3 at The Houstonian Hotel.
Higher gasoline imports to the U.S. East Coast and weaker demand in the region have combined to bloat gasoline inventories, raising the question, what would it take to bring the market into balance? East Coast refinery output is down from this time last summer in response to somewhat lower crack spreads, but not enough to make a dent. Part of the problem is that while gasoline demand turned anemic in the Maine-to-Florida region, it is even weaker in many overseas markets. Also, the skill of East Coast blenders in dealing with a wide variety of supplies has always made the region an attractive destination for international product flows. Today, we continue our look at petroleum product cargo flows, and what they are telling us about the health of the market.
West Texas Intermediate (WTI) crude oil at Cushing is languishing back in the low $40s/bbl after a brief period of exuberance in the late spring. The blame for this latest oil-price retreat has shifted from high inventories of crude oil –– both on land and on tankers floating offshore –– to bloated petroleum-product inventories. There is some debate about how concerned the market should be about the increase in product stocks. In the opening episode of this blog series, we take a look at petroleum product cargo flows, and what they are telling us about the health of the market. We start today with middle distillates –– diesel and jet fuel.
Renewable Identification Numbers (RINs) have grabbed the attention of refiners this spring and summer, and for good reason. The price of RINs –– ethanol credits used by refineries to prove compliance with the federal Renewable Fuel Standard –– have soared, and the credits are having an outsized negative effect on some refiners’ costs and profitability. Part of the RIN price spike can be attributed to concerns that there may not be enough to go around this year, and that the situation in 2017 may be far worse. But the rocketing cost of the credits is also raising questions about whether the largely unregulated and opaque RINs market is being manipulated or even cornered by those hoping for a quick, Powerball-size profit. Today, we continue our review of the RINs market with a look at which types of refiners are hit hardest by high RIN prices, and at whether we might be heading off a RIN-availability cliff.
The rising cost of Renewable Identification Numbers (RINs) –– ethanol credits used by refineries to prove compliance with the federal Renewable Fuel Standard –– is putting added financial pressure on the refining sector, which already is squeezed by too-high inventories and thin crack spreads. In fact, for some refiners RIN expenditures may soon be their biggest single operating cost category. (Yes, you read that right.) The cost of ethanol credits is being driven up to record levels by several factors, chief among them the concern there may not be enough to go around this year and next. And things may only get worse from there. In today’s blog, we begin a two-part examination of the 2016-17 market for RINs, a regulatory must-do that rankles and vexes most refiners and gasoline importers.
We are getting into the peak summer driving season and gasoline demand has been hitting all-time highs. You might think that inventories would be drawing down and that the U.S. would need to import more gasoline and gasoline blending components. But not so. U.S. refineries are cranking out the products. Gasoline stocks are up 10% from a year ago—15 million barrels (MMbbl) higher than the top of the five-year range—and last week gasoline inventories made a contra-seasonal move upward, increasing by 1.4 MMbbl. Net exports for the first quarter were up almost five times the same period in 2015. But what does all this mean for refined product markets in general, and gasoline balances in particular? Today, we examine the state of U.S. petroleum product markets.
A few weeks back Rusty Braziel sat down with Don Stowers, Chief Editor of Pennwell’s Oil & Gas Financial Journal, to talk about the big picture – some of the most important issues facing the oil and gas industry, the lasting impact of the Shale Revolution, and Rusty’s thoughts from 40-plus years in the energy business. It turned into the cover story of their June 2016 issue. Today, we recap a few of the interview questions. You can download the full article (along with Rusty’s smiling face on the cover) at the bottom of the blog.
After the $5 billion-plus expansion of the Panama Canal is dedicated this Sunday, June 26, the first “New Panamax” vessel scheduled to pass through the canal’s new, longer, wider locks will be the Lycaste Peace, a Very Large Gas Carrier (VLGC) that is transporting propane from Enterprise Products Partners’ Houston Ship Channel export terminal to Tokyo Bay in Japan. What remains to be seen, though, is how many other supersized vessels carrying propane, liquefied natural gas (LNG) or other hydrocarbons will follow, and how soon. Today, we mark the formal opening of the newly enlarged Atlantic-Pacific short-cut with a look both at the game-changing potential of the expanded canal and the realities of today’s energy and shipping markets.
Crude oil and natural gas prices are back from the abyss, but does that mean the long awaited recovery is underway? Maybe so. But maybe not. Energy markets are fickle, driven by a chain of interactions where one market event triggers another, and then another. Rusty Braziel’s best-selling book, The Domino Effect, explores 30 such market events, which are represented by dominoes – hence the title of the book. More dominoes are falling now and still more will fall in years to come. This book explains the interconnectedness of energy markets through an analysis of energy market fundamentals: prices, flows, infrastructure, value, and economics. And good news for fans of audio books: The Domino Effect is now available on Amazon in Audible format. Today’s blog, an advertorial for the audio book, highlights what The Domino Effect has to say about what’s going on now.