The U.S. market for distillates has been crazy the past few months — especially in PADD 1 — and given all that’s going on, it’s likely to stay that way for months to come. Inventories of ultra-low-sulfur diesel, heating oil and other distillates are at their lowest levels for this time of year since before the EIA started tracking them 40 years ago and diesel prices are in the stratosphere, all despite diesel crack spreads being in record-high territory — a strong incentive for refineries to churn out more distillate. In the encore edition of today’s RBN blog, we discuss the many factors affecting distillate supply, demand, inventories and prices and take a look ahead at where the market may be headed next.
Daily energy Posts
Though crude oil prices have been rebounding lately, this spring’s price crash sent shockwaves through the U.S. midstream industry, which not too long ago had emerged from a decade of massive infrastructure investment in response to unprecedented upstream production growth. Just as midstreamers were looking forward to steady earnings growth, waves of huge capex cuts and well shut-ins by producers shattered forecasts and shifted strategic instincts toward survival instead of growth. Every company is different, of course, but a lot can be learned by examining a single firm in detail to see how it will fare in the current market environment, given its particular set of assets and arrangements. Take Targa Resources. An analysis of its performance provides insights into the outlook for integrated natural gas and NGL assets, especially in the Permian Basin, as well as the value of forming joint ventures. Today, we preview our Spotlight report on Targa.
Chesapeake Energy’s announcement yesterday that it has filed for Chapter 11 bankruptcy protection is only the latest sign of how much the seismic economic shocks from the pandemic-triggered demand destruction have roiled the U.S. E&P sector. With equity prices plummeting to historic lows, oil and gas producers have focused their efforts on shoring up their balance sheets and share prices, by tightening their belts going into 2020, reducing capital expenditures by an average 14% in order to boost free cash flow and increase shareholder returns. So, it’s no surprise that the industry has aggressively battened down the hatches operationally and financially, mothballing rigs, suspending completions, shutting-in producing wells, slashing dividends, and suspending share repurchase programs. First-quarter 2020 earnings releases and investor calls provided a clear picture of the dimensions of the cost-cutting by the 41 U.S. E&Ps we track. But continued uncertainty about the course and duration of the COVID-19 pandemic, the pace of economic recovery, and the outlook for commodity prices have triggered reluctance on the part of oil and gas executives to issue production guidance for the remainder of 2020 and beyond. Today, we review the current capital expenditure reductions by U.S. E&Ps and piece together clues on their impact on oil and gas production.
March’s crude oil price crash hit the E&P sector like a tsunami, shattering capital and operating budgets, upending drilling plans, and eviscerating equity valuations. The initial responses by producers to the price collapse included a flood of capex reductions, corporate belt-tightening, and scattered production shut-ins. But first-quarter earnings reports issued in late April and early May provided the first detailed insight into the financial wreckage the crisis unleashed on U.S. E&Ps. It wasn’t pretty. The plunge in the WTI oil price to $20/bbl at the end of the first quarter triggered a combined $60 billion in impairments of oil and gas reserves across the 41 E&Ps we track, as well as a 16% decline in average revenue per barrel of oil equivalent (boe) from the pre-pandemic fourth quarter of 2019. More trouble may be ahead: the average oil price in the second quarter is on track for a 35% decline from the first quarter, which will dramatically impact the cash flows that allow companies to pay their staff, keep the lights on, and hold creditors at bay. Today, we analyze the first-quarter earnings results of our representative sample of U.S. producers and take a look forward to the potential effect of lower pricing on second-quarter earnings.
Though crude oil prices have been rebounding lately, this spring’s price crash sent shockwaves through the U.S. midstream industry, which had just emerged from a decade of massive infrastructure investment in response to unprecedented upstream production growth. Just as midstreamers were looking forward to steady earnings growth, waves of huge capex cuts and well shut-ins by producers shattered forecasts and shifted strategic instincts toward survival instead of growth. Every company is different, of course, but a lot can be learned by examining a single firm in detail to see how it will fare in the current market environment, given its particular set of assets and arrangements. Take Targa Resources. An analysis of its performance provides insights into the outlook for integrated natural gas and NGL assets, especially in the Permian Basin, as well as the value of forming joint ventures. Today, we preview our new Spotlight report on Targa.
COVID-related demand destruction and the oil price meltdown have engulfed energy markets and companies in a thick, pervasive shroud of doom and gloom. But investors and analysts have hit upon a potential bright spot for one segment of the industry: Gas-Weighted E&Ps that had been battered by the decade-long shift of upstream capital investment to crude-focused resource plays. The massive cutbacks in 2020 capital investment by oil producers triggered by the recent, dramatic decline in refinery demand for crude will reduce not only oil output, but associated gas production as well. That drop in supply raises the prospect of meaningful increases in natural gas prices in 2021 –– hence Wall Street’s new interest in Gas-Weighted producers, whose equity values have taken off in recent weeks after a big plunge earlier this year. There’s a lingering concern though, namely that LNG exports — a key driver of gas demand for U.S. producers — may be slowed by collapsing gas prices in key international markets. Today, we discuss what’s been going on.
E&Ps have long been accustomed to negative investor sentiment and the depressed stock valuations that come with it. But who among them could have anticipated the first quarter’s devastating one-two punch of coronavirus-related energy demand destruction and the collapse of the OPEC+ supply-management effort that for more than three years had propped up crude oil prices? E&Ps responded by slashing their 2020 capital spending plans and touting how much of their 2020 production is hedged. But there’s no doubt about it, the E&P sector is in for particularly hard times, as evidenced by Whiting Petroleum’s Chapter 11 filing last week. A major impediment for Whiting and other already hobbled E&Ps is a cost structure that, for many, significantly exceeds the current price of oil. Today, we discuss what an examination of more than 30 E&Ps’ lifting, DD&A and other costs reveals about the companies’ ability to stay afloat in rough seas.
You wouldn’t know it yet from outright crude oil production volumes, which stood at 13.1 MMb/d last week, but with crude oil prices in the cellar, the situation for U.S. E&P companies has rapidly gone from bad to worse. The double whammy of the coronavirus and the Saudi’s decision to flood oil markets with new production has cast a pall over the U.S. E&P sector, sending share prices plummeting. Producers had already taken a stripped-down approach to 2020 investment, with previous guidance reducing capital expenditures by 14% in order to boost free cash flow and hike shareholder returns. That was on top of the 7% decline in capex seen in 2019. But in the last 10 days, about half of the 42 E&P companies we track have announced further, substantial cuts in planned capex. And with West Texas Intermediate prompt crude oil futures settling at $25.22/bbl yesterday — well below breakeven for many producers — and still-lower prices a real possibility, more industry-wide reductions are looming as first-quarter earnings are announced in April. Today, we break down what the recent announcements mean for capex and production volumes.
The fortunes of U.S. midstream companies in 2020 and beyond will be largely determined by how shrewdly they invested during the frenzied infrastructure build-out of the past few years. One of the most interesting case studies is San Antonio-based NuStar Energy, a master limited partnership born in 2001 to hold refiner Valero Energy’s midstream assets and spun off as a separate entity in 2007. In May 2017, as the industry was still recovering from the late 2014 plunge in crude oil prices, the MLP made a major play to capture growing Permian production through the ~$1.5 billion acquisition of Navigator Energy, which owned a crude oil gathering, transportation, and terminaling system in the Midland Basin. The purchase was widely panned as overpriced by analysts and investors, and NuStar’s unit price plummeted by 60%. But by 2019, the company’s Permian acquisition — and soaring exports from its Corpus Christi terminal — drove big year-on-year gains in NuStar’s fourth-quarter 2019 operating income and EBITDA. Today, we preview our new Spotlight report on NuStar.
The Shale Revolution created enormous opportunities for U.S. midstream companies. But opportunities are only that. It’s what individual midstreamers did with those opportunities through the 2010s — the decisions each made on where to invest and what to invest in — that will help determine how well they will do over the next decade and beyond. And the best way to assess the wisdom of these investments is to examine them one by one, and consider their locations, their exposure to risk and their potential for growth. Today, we discuss highlights from the newly released company-by-company portion of East Daley Capital’s “Dirty Little Secrets” report.
After a decade in which unprecedented upstream production growth triggered massive investment in infrastructure to get crude oil, natural gas and NGLs to market, 2020 is a major inflection point for the U.S. midstream industry. The good news is that after peaking at a whopping $37 billion in 2019, midstream capital expenditures are forecast to steeply decline over the next few years as the lion’s share of the infrastructure needed to gather, transport, process, and store current and expected hydrocarbon volumes has already been built or is nearing completion. And, despite continued cutbacks in capex by exploration and production companies, output is still forecast to rise in 2020, which should boost earnings growth for the midstream sector. But all midstream companies aren’t alike, and the prospects for individual entities vary widely because of the specific basins and hubs where they’ve decided to build, acquire, expand or divest. Today, we analyze the headwinds and tailwinds these companies will experience, and how their decisions over the past few years will help determine their prospects.
For much of the 2010s, the U.S. midstream sector has been on a development spree. New or expanded everything — pipelines, gas processing plants, fractionators, storage facilities, liquefaction trains, export terminals and more — all to keep pace with the production gains of the Shale Era. But now, at the start of the 2020s, the build-out frenzy appears to be fizzling and flickering. Midstreamers’ capital spending plans are on the decline, at least for now, as most of the infrastructure needed to handle current and expected volumes for the next few years is either in place or under construction. But that doesn’t mean things won’t stay interesting — far from it. This new decade brings with it a period of midstream-sector strategizing and portfolio rejiggering. Today, we discuss highlights from East Daley Capital’s newly released “Dirty Little Secrets” report about the next phase of midstream strategy.
There has always been an aura of excitement, adventure and risk surrounding the quest to unlock natural resources, from the California Gold Rush to the early days of Texas oil wildcatting. Today’s exploration and production leaders may be just as passionate as their predecessors, but the “riverboat gambler”-type days of reckless spending in pursuit of growth now seem like a distant memory. In the brutal aftermath of the oil price crash in late 2014, producers have been forced to follow their heads instead of their hearts, adopting a far more careful approach to investment that prioritizes portfolio rationalization over expansion, and cash flow above growth. E&P companies in 2019 slashed capital investment, and, according to early guidance, they will again in 2020. Underscoring this more conservative attitude is the release of the 2019 Securities and Exchange Commission price deck, which impacts the economics of booking oil and gas reserves. It showed the WTI oil price for SEC reporting purposes declined about $10/bbl, or 15%, to $55.69/bbl in 2019, while the Henry Hub SEC price declined by 17%, to $2.58/MMBtu. Today, we examine a representative group of U.S. E&Ps’ spending plans for 2020, which reflect the impacts of a lower-price environment.
As a most eventful decade for the U.S. energy industry draws to a close and 2020 looms, it’s a perfect time to consider what’s ahead for the midstream sector — and, more important from an investor’s standpoint, for the individual companies within it. The last few years have driven home the point that while all midstreamers are impacted to some degree by what happens on a macro-level, the relative success of each company is tied to the myriad decisions its leaders make over time regarding which basins and hubs to focus on and which assets to build, expand, acquire or divest. Assessing these micro-level assets and the contributions they each make to a company’s bottom line requires particularly deep analysis. Today, we discuss key themes and findings from East Daley Capital’s newly issued 2020 Midstream Guidance Outlook.
With oil and gas prices drifting lower and markets continuing to pummel exploration and production companies, shareholders and analysts approached the third-quarter 2019 earnings season with the sense of impending doom akin to awaiting the results of an IRS audit. There was a lot of talk that the Shale Revolution was fizzling out and that the industry was approaching yet another financial Armageddon, like the 2014-15 oil price crash crisis. But the results belied the worst fears: while lower commodity prices did reduce profits and cash flows, E&Ps as a group remained solidly profitable in the third quarter, with 40 of the 47 companies we track ending up in the black. The reductions in operating income and cash flows were generally in line with lower realizations from oil and gas sales, although lower commodity prices did trigger some write-downs of properties that could no longer be profitably developed. Once again, E&Ps held the line on costs, continuing the financial discipline that fueled the industry’s recovery after the mid-decade price crash. Although producers generally cut back expenditures in line with lower cash flows, increases in drilling efficiency allowed production to keep growing. Today, we examine the financial health of the 47 E&Ps we track in this analysis and the ways they are navigating the price downturn.
Extreme makeovers by exploration and production companies over the past five years have resulted in higher crude oil and natural gas production, lower costs and more money for shareholders in the form of dividends and share buy-backs. Despite all this, investors have continued to abandon the E&P sector, with the S&P E&P index sliding to a series of record lows: down 75% from its 2014 peak, down 51% from a year ago, and down 5% from this time last month. Why the major disconnect? Today, we examine the improving financial health of most of the 48 E&Ps we track in this analysis and the reasons why investors remain wary of E&P equities.