The blind man’s request in the Bible—“that I may see”—is reminiscent of many of us struggling to look beyond the wall of inventory that has obscured crude oil fundamentals. Certainly, recent crude oil prices that have tested levels last seen in the financial crisis of 2008-2009 are unsustainable. But when will we gain greater visibility as to when long-term fundamentals are likely to realign, given the now blurred picture of bulging inventories that are holding crude prices down near term?
Admittedly, negative sentiment is driven by factors other than just inventory levels. Macquarie Capital, for example, describing its outlook as “short-term bearish and long-term bullish,” enumerated various factors contributing to deeply negative near-term sentiment. These include geopolitical factors that tend to “perpetuate an oil production arms race,” as well as “nearly magical powers attributed to U.S. shale.” In addition, demand growth concerns include a slowdown in Chinese consumption.
With the struggle for market share continuing unabated, major producers—Saudi Arabia, Russia, Iran and others—have competed for customers, pushing supply that is simply in excess of demand.
Then there are the technical factors. After West Texas Intermediate (WTI) broke through a key $40/bbl support level, followed by the August 2015 low of $37.75/bbl, technical observers indicated further risk to the downside. The next major support level of $32.40/bbl, which helped form a bottom during the 2008-2009 financial crisis, was broken through in January, opening the way for a test of $30/bbl.
With the macro outlook posing steep challenges—and many energy players now implementing multiple rounds of cost-cutting initiatives—in what condition does the U.S. industry find itself as it moves forward in 2016? Or more to the point, in how bad a shape does most of the industry find itself?
The multiplicity of negative factors could hardly have been greater, according to J.P. Morgan E&P equity analyst Arun Jayaram.
“Nearly everything has gone wrong,” observed Jayaram. In addition to the slowdown in China, “an Iranian nuclear deal was reached, the dollar has strengthened and of course OPEC has abdicated its role as the swing supplier,” he said. Moreover, with U.S. shale output having previously outperformed expectations, helping pressure domestic prices lower, “our analysis suggests that most of the U.S. cost curve is uneconomic at the 2016 futures strip.”
Analysts at Tudor, Pickering, Holt & Co. are more blunt, calling the oil industry “fundamentally broken” at prices around $40/bbl in the wake of the OPEC meeting in December.
In its post-OPEC meeting note, Tudor, Pickering, Holt & Co. analysts commented that although the outcome was in line with expectations—no change in OPEC measures or lack thereof—the organization’s “self-imposed confusion surrounding quotas/no quotas was red meat for the lower-for-longer crowd. Make no mistake,” they said, “the industry is not just impaired under the lower for longer … it is fundamentally broken. So we are left waiting for supply and demand fundamentals to fix the oil market.”
As expected, lynchpin producer Saudi Arabia offered little movement in terms of a possible change in course away from what is an essentially laissez-faire policy, letting market forces continue to determine crude prices. “OPEC is not a cartel,” said Saudi oil minister, Ali al-Naimi, ahead of the meeting in Vienna. He is reported to have left the meeting without offering any public comment.
For producers and investors alike, the recent more Darwinian oil and gas environment has made finding one’s bearings all the more difficult.
“I won’t say it’s panic, but there’s a high level of concern among producers,” said David Tameron, senior analyst with Walls Fargo Securities, on his return from the firm’s 14th Annual Energy Symposium late last year in New York. E&Ps tended to discuss plans for 2016 in a “very noncommital framework,” in which they emphasized “maintaining flexibility” and “making adjustments” as conditions warranted.
In informal fall budget discussions, according to Tameron, most companies “probably ran their 2016 budgets on a $45 to $50/bbl assumption for WTI. But then they woke up in mid-December to find crude prices sliding toward the mid-$30s/bbl.” Even E&Ps with some hedges in place typically didn’t have much price protection beyond the first couple of quarters of 2016, and most large-cap producers were relatively unhedged, he said.
And while the commodity curve is well-known as a sometimes unreliable forecaster of future crude prices, the 2016 futures strip had fallen more than $2 to under $40/bbl in the space of a week, said Tameron. As a result, looking out along the commodity curve provided little comfort, as it was not until 2020 and later that the futures strip indicated an average annual WTI price of $55/bbl, he added.
For investors, the indicators were similarly confusing. While E&Ps generally talked in terms of matching 2016 capex closely in line with cash flow or EBITDA, the lack of visibility in terms of commodity prices in the short term, together with production guidance generally at risk of being revised lower, offered little incentive for investors to commit to the sector in the absence of a strong view as to the commodity rebounding longer term, according to Tameron.
In addition, such has been the decline in energy—and likewise energy sector weightings in various indices—that not carrying a full energy position is viewed as carrying little risk in terms of holding back portfolio managers’ overall performance. Just how far energy has fallen out of favor is illustrated by the EPX Index (SIG Oil Exploration and Production Index), which broke through the prior all-time low set during the March 2009 financial crisis. The new all-time low for the EPX index of 176.01 was set on December 21, 2015, and represented a decline of 49% for the near full-year of 2015. The EPX closed out the year at 182.63, down 47.1%.
Tameron described the pullback in crude as having left energy investors “dazed and confused.”
While the dedicated energy investor may have a better feel for how production guidance offered by E&Ps may fall out at $40/bbl—that is, E&Ps generally won’t be able to generate production growth at $40/bbl—Tameron questioned whether the same understanding was shared by the generalist investor.
“We still believe the generalist investor or portfolio manager does not understand how tough the treadmill is and just how bad the numbers may look,” he said. “We think the Street will be surprised by the magnitude of the production declines. If the strip holds at $42/bbl, we think the ensuing guidance is going to be downright ugly. At these prices, the industry can’t grow, and it can’t generate free cash flow. If you can just hold production flat, you’ll likely be in the top decile in terms of production.”
Following an estimated 38% decline in capex for E&Ps under coverage by Wells Fargo in 2015 versus 2014, Tameron forecast a further 25% reduction in capex this year if crude prices average $50/bbl. If prices average $40/bbl, he is forecasting a drop in capex “closer to 35% to 40%.”
If commodity prices remain at $35/bbl for oil and $2/Mcf for natural gas, however, any priority given to production growth “gets thrown out of the window” in favor of taking care of the balance sheet, he said. “If commodities get so low that it’s an Armageddon-type scenario, you can say, ‘We’re shutting it all down,’ and almost be given a pass.”
This shift in priorities is underscored by Tudor, Pickering, Holt & Co., whose recent conversations with energy investors “point to a preference for balance sheet preservation” over that of production growth.
“While operators are hesitant to allow production to decline, investors are no longer focused on growth, given the level of distress emerging in the debt and equity markets. The magnitude of capex relative to market cap shows that the benefits of maintaining/growing production may be outweighed by building cash to protect balance sheets or potentially buying in deeply discounted debt,” said the Houston-based energy research specialist.
Strategies for survival
How are producers devising a strategy—using these tactics and others—to prepare themselves for the dramatically uncertain landscape that lies ahead of them in 2016?
Diamondback Energy Inc. has, admittedly, perhaps greater flexibility than many independents, given a balance sheet that is among the strongest in the industry. It calculates its net debt to EBITDA at 1.0x as of Sept. 30, 2015, using an annualized EBITDA projection based on its third-quarter 2015 adjusted EBITDA. Liquidity at quarter-end was $529 million.
“What does 2016 look like? There’s a lot of uncertainty, there’s a lot of macro events that still need to play out in front of us,” said Travis Stice, CEO of Diamondback. Accordingly, he has had the company develop a scenario analysis, identifying the number of gross locations that the Midland Basin producer deems to be economic to drill at varying crude prices, as well as plans for the number of rigs it would run on its northern Midland county acreage.
The scenario analysis shows, for example, an inventory of 700 gross locations economic to drill at WTI prices of $35 to $45/bbl, rising to 1,250 gross wells at $45 to $55/bbl and 1,500 wells at $55 to $65/bbl. Scaling up activity with each step-up in price band, Diamondback would plan to run two to three rigs at $35 to $45/bbl, rising to three to four rigs and four to six rigs, respectively, at $45 to $55 and $55 to $65.
“That means we’re poised to respond to varying oil prices,” said Stice. “Our capital flexibility allows us to have some outstanding leverage ratios. Under each one of these scenarios our balance sheet remains really strong.”
Sliding oil prices clearly present budgeting challenges, even as E&Ps have made major strides in lowering oilfield service costs and improving operational efficiency in an ongoing effort to preserve margins.
With oil prices dropping from $100/bbl to $60/bbl in late 2014 and early 2015, Oasis Petroleum Inc. reacted quickly, reaching a goal of generating free cash flow in its core Williston Basin operations at a WTI price of $60/bbl, and later lowering the breakeven cash flow price to $50/bbl as prices continued to fall in the second half of 2015. Throughout the drastic price decline, the company has maintained a strong liquidity position of over $1.3 billion, and it has a hedging strategy in place that provides protection for just over half of its production in 2016 at levels north of $50/bbl.
For 2016, according to CEO Tommy Nusz, the original plan was to be free-cash-flow positive at a WTI price of $50/bbl, with output for the early part of the year holding roughly flat with the fourth quarter of 2015, and then ramping up so that year-end 2016 production tops that of the prior year. Free cash flow is defined as adjusted EBITDA less capex plus cash interest, and Oasis’ capex assumption excludes expenditures on midstream infrastructure.
But when crude slides below $40 in a matter of weeks, conditions may call for renewed flexibility.
“Balancing capex and cash flow is extremely important to us as we look to protect the balance sheet,” noted the Oasis CEO.
In the current low price environment, with production growth subject to a commodity recovery, Nusz said Oasis has three areas of focus: balance sheet and cash flow balance; solid operational execution; and capital and operating efficiency. Growth was one of several goals, but involved tradeoffs.
“It all starts with, ‘Do you have an inventory of economic projects at a given price deck?’ And, ‘Can you maintain production and live within cash,’ which we’re trying to do,” said Nusz. “Maintaining production and being well-positioned for a turnaround is an important thing, but it’s not the only thing.
“You also have to consider where you are with the balance sheet. And keep in mind that if you’re not growing, or are contracting, there’s a knock-on effect with your revolver. For us, we think maintenance capex for 2016 is about $300- to $350 million, but that will depend on where costs ultimately shake out. Bear in mind, too, that, as you step down activity, you progressively lower your decline rate with that lower activity, and the required capital to replace production drops as well.”
At the middle of last year, Oasis dropped down to three rigs from as many as 16 rigs in late 2014. Having laddered its drilling contracts, the company has incurred only $3.9 million in rig termination fees. Oasis has been in the process of transitioning the three rigs to its Wild Basin project ahead of the scheduled start-up of the new gas processing plant there in the second half of this year. Planned infrastructure capex for the project in 2016 is about $150 million.
Ideally, Oasis would like to monetize a portion of its Oasis Midstream Services assets, including Wild Basin. Nusz underscored the significance of midstream to Oasis and emphasized the importance of striking the right type of deal.
“It’s not necessarily our core business, but we’ll invest in midstream where we need to protect our inventory and our assets and manage our business risk,” said Nusz. “You’re now seeing the importance of infrastructure to margins in a low price environment. The question is how to manage spending relative to the midstream business.”
Diamondback has developed multiple scenarios to allow it to respond to varying commodity price levels.
While monetizing a portion of the asset value would help, Oasis won’t rush into the wrong kind of deal.
“The right deal is more important to us than the timing,” said Nusz. “Doing the right deal with this asset is the most important thing in terms of control, service and costs. We have an extremely attractive asset, with annual EBITDA in the range of $60- to $70 million. That could double in two years with the Wild Basin project coming on.”
If a midstream deal doesn’t emerge, or if crude prices don’t rebound, how does Oasis square the circle?
Nusz, a veteran of numerous commodity cycles, is unruffled: “Let’s see what the market gives us, but in that case we may work to move out some of our drilling and completion capital and look for options to defer portions of the Wild Basin Project. We have the luxury of a revolver that is effectively undrawn, but we want to protect that and will look to other means to balance cash flow. Fortunately, we have a tremendous asset base that provides us with a lot of flexibility.”
Private equity’s stance
With public capital markets largely shut, it’s no surprise to find private equity sources closely following—and engaged in—the flow of oil and gas transactions that are getting done. Even though 2015 ended up as one of the worst years recently in A&D, there is a newfound urgency in the tone of those seeking to transact, according to Wil VanLoh, CEO with Quantum Energy Partners.
“We spend a lot of time visiting with CEOs and CFOs of public companies to gauge their interest in whether they may need capital from us, or if they have assets that they would like to divest quickly and quietly. On all fronts, the level of activity has picked up materially, starting in the fourth quarter of last year,” recalled VanLoh.
“A big driver of this is that the public companies, which were moderately hedged through the end of 2015, are now staring into 2016 with their production largely unhedged. And all of a sudden their debt-to-EBITDA numbers are going to go from 3.5x to 5.5x or 6.0x, so they are going to have to do something. And in many cases, that ‘something’ is going to be to sell assets.”
VanLoh said he recognized a marked worsening in sentiment with the continued downtrend in WTI prices, with the latest leg down taking crude below $40.
“Early last quarter, I remember a lot of executives saying, ‘Yeah, we’re going to make it through, we’ve hunkered down, we’ve cut our costs, and we’re going to get a rebound and be fine,’” he said. “But more recently, for the first time in this downturn, I think there are a fair number of executives who are genuinely scared and concerned about the long-term viability of their companies.”
VanLoh didn’t exclude the possibility of some E&Ps going into “survival mode” and making critical decisions as to whether they should “merge to survive. That’s something we haven’t seen much of yet. The change in sentiment could be the final straw, if you will, enabling some of these large-cap mergers to happen, as well as forcing a lot of small- and mid-cap companies to take radical steps to survive.”
For Quantum, which has about 20 active E&P portfolio companies, the flow of recent transactions has been “more robust than it has been in many, many years,” said VanLoh. “Our current portfolio companies are incredibly active, and our deal flow for new portfolio companies is very high, given that many executives no longer have on golden handcuffs in the wake of the meltdown in public company stock prices. Our existing portfolio companies signed several purchase and sale [PSA] agreements in the final quarter of last year to buy assets.”
As an example of the improved quality of assets now coming onto the market, VanLoh pointed to a purchase by a Quantum portfolio company of assets from a very large producer that involved a “complete basin exit” by the seller. While probably not considered “core” by the seller, the transaction involved “the juiciest set of assets that we’ve probably seen in this particular basin in 10 years,” given the multitude of workovers, behind pipe recompletion opportunities and overall running room.
In terms of transaction metrics, “If we’re buying assets, we’re just going to look at the strip,” according to VanLoh. “We’re not going to price in a recovery. We don’t know when a recovery is going to happen. It could happen in two months; it might not happen for two years. Assets have to be able to generate a modest return in this price environment—something like a levered 15% to 20% return at strip prices.”
Quantum has about 80% of its assets in four main basins: the Midland and Delaware basins, the Scoop and Stack plays in the Anadarko Basin and the Marcellus-Utica play in Appalachia.
While VanLoh termed the vast majority of Quantum’s portfolio companies as “healthy,” he acknowledged that a few of them had “cost structures and well economics that would cause us to lay down rigs in 2016. But overall, we probably drilled as many wells in 2015 as we did in 2014 at most of our companies. And that stems from being in the right rock with teams that are great at execution.”
Even in the depressed natural gas price environment, great rock in the core of the play allows Quantum to earn “solid” returns, said VanLoh, citing performance of Marcellus wells in Greene County, Pennsylvania, where netbacks are around $1.10 to $1.25/Mcf off a $2.25 Nymex Henry Hub price.
“Once we get into an area where the acreage is well-delineated, we’ll typically hedge out 75% to 80% of projected production for the next three to four years,” he said. “We make a decision to commit the capital based on the current strip and current service costs if it generates an acceptable rate of return, and then do whatever we can to lock that in.”
With investors having to go back years—and more than a decade with natural gas—to find comparably depressed commodity prices, it’s easy to understand the tendency to push out a rebalancing of demand and supply in crude toward the end of 2016—or later. But amidst the multitude of factors potentially posing headwinds for a crude recovery, it is also worth noting some of the early steps in the long march toward reaching an equilibrium in the demand/supply balance.
Although bearish on oil near term, Macquarie Capital is more optimistic long term, seeing a path to rebalancing by year-end 2016, assuming further OPEC growth is limited to Iran. One area of optimism it has found relates to the often-overlooked segment of higher cost, conventional onshore production, where it says conventional production is rolling over in the U.S., Canada, China and other countries.
Since the end of 2014, Macquarie has observed a collective decline of about 420,000 bbl/d across a subset of higher cost, conventional onshore non-OPEC fields with an initial production of roughly 9.2 million barrels per day (MMbbl/d). While acknowledging these declines may in some cases be offset by production from longer lead time offshore and oilsands projects, Macquarie viewed “the response in these regions as a key milestone in the rebalancing of non-OPEC supply.”
In the U.S., onshore conventional production from vertical/directional wells in the first half of 2015 declined by more than 200,000 bbl/d, “a surprisingly large amount,” according to Macquarie. The base decline was as much as 14% for wells online at year-end 2014, whose output experienced “effectively a full year’s worth of decline in six months.” This appeared consistent with a historical trend of increased declines “in years following price routs,” when typical workover and maintenance activity is neglected.
China, universally recognized as a major crude oil importer—but sometimes forgotten as the #5 world oil producer in BP’s 2015 Statistical Review—is expected to see its onshore production drop by 250,000 to 330,000 bbl/d over the two-year period through the end of 2016. Such declines are already happening, but have “been masked at the country level by CNOOC delivering 131,000 bbl/d worth of new offshore oilfield start-ups in the first half of 2015,” according to Macquarie.
“This is a one-off gain that is the result of five years of investments, and will not be repeated in 2016,” said Macquarie, noting a 33% cut in CNOOC capex for the current year.
As to the idea that “no one cares about return on equity in the world of China state-owned enterprises, the reality is that the state is applying intense pressure on state-owned enterprise management to stop value-destructive capex and deliver positive returns on equity that allows dividends to be paid,” observed Macquarie. It added that PetroChina freely admits the bulk of incremental drilling at its Daqing Field, the company’s largest with an output of 775,000 bbl/d, has a breakeven price of over $80/bbl.
In the realist camp
Describing itself as in the “realist camp” as to the timing of a rebalancing of world crude markets, Simmons & Co. International points to supply and demand realigning in late 2016/first-half 2017, with “incipient pricing normalization” occurring in the second half of 2016 as the visibility of forward supply diminishes over the course of 2016.
Simmons’ timeline for the realignment comprises three main phases: a period of continued global oversupply through the first half of 2016; then a period in which global demand and supply approach “leading edge equilibrium” in the second half of 2016; and subsequently a period in which global markets are “undersupplied relative to leading edge equilibrium in 2017.”
“Normalized pricing will likely only unfold when we begin to witness cathartic, sustainable inventory draws,” projected for 2017, according to Simmons.
While Simmons outlined numerous near-term headwinds facing the oil and gas industry, it also cited a litany of long-term factors that would collectively—and eventually—create the foundation for improved industry conditions.
Near-term threats to oil cited by Simmons include record inventory levels; non-OPEC major project start-ups; seasonal realities in refinery maintenance; likely Iranian production increases post-sanctions; relative U.S. dollar strength; and decelerating global demand growth.
Long-term factors favoring “redefined” oil prices (mostly reflecting constraints on supply) include the industry’s impaired capacity to reinvest due to diminished cash flows, strained balance sheets and rising cost of capital; decelerating/contracting non-OPEC production growth; exploration activity/results that have been “eviscerated”; non-OPEC major project backlog that is “evaporating” beyond 2017; OPEC’s depleted spare production capacity; and oil demand growth, spurred by lower crude prices, but subject to a decelerating global economy.
Simmons uses two price decks in modeling its U.S. production forecasts—one based on strip pricing, another based on “normalized” oil prices—but “leans toward the normalization scenario,” especially with regard to the second half of 2017 and into 2018. Simmons’ normalized price deck projects $55/bbl in 2016, $60 in 2017 and $70 in 2018. This compares to strip pricing, at $42.50, $48 and $52, respectively, for 2016, 2017 and 2018, which in its view is “unsustainably low.”
Under the normalized price deck, Simmons projects a peak-to-trough contraction in U.S. production of 610,000 bbl/d, with production bottoming at 8.975 MMbbl/d in June of this year, and then rebounding to the tune of 1.4 MMbbl/d by December 2018. The strip pricing scenario foresees a peak-to-trough contraction of about 1 MMbbl/d, taking production down to 8.654 MMbbl/d in June of this year, and then recovering by only 230,000 bbl/d by December 2018.
In both scenarios, however, changes in domestic production may be overshadowed by the global outlook. Simmons cited OPEC production running at 32 MMbbl/d versus an estimated “call on OPEC” of 30.2 MMbbl/d, resulting in 1.8 MMbbl/d of oversupply. Under both price decks, said Simmons, “we do not have the call exceeding 32 MMbbl/d until the first quarter of 2017.”
And this ignores the reintegration of Iran. Assuming Iran produces an incremental 500,000 bbl/d of supply, this would boost oversupply to 2.3 MMbbl/d. To balance, the call on OPEC would then have to exceed 32.5MMbbl/d, which is not modeled by Simmons to occur until second-half 2017.
For investors, Simmons strikes a cautious tone, given E&P stocks were discounting (as of Dec. 11, 2015) commodity prices of $60 to $63/bbl and $3/Mcf, “prices which do not appear on the forward strip until deep into the future.” In addition, earlier corporate growth and spending indications for 2016 were predicated on expectations for WTI of $50/bbl, “which is no longer a reality.”
Several other Wall Street firms have similarly severe first-half forecasts that give way to more benign commodity forecasts in latter part of 2016 or early 2017. For example, Edward Morse, Citigroup’s global head of commodities research, has forecast the price of WTI reaching $55/bbl by the end of 2016—but doesn’t rule out WTI trading down into the $20s along the way.
“We think WTI is going above $55,” said Morse, better known for his more bearish views on the oil market. Speaking on Bloomberg TV, he predicted progressively lower inventory builds each quarter over the first nine months of the year, with the fourth quarter showing a drawdown in inventory. In addition, from an M&A viewpoint, “We’re very close to a cathartic moment when oil is priced in the $30 range,” he said.
Just how heavily oversupplied the global crude market has become—as talk of nearly 3 billion barrels of OECD inventory would imply—is a subject tackled in depth by, among others, Tudor, Pickering, Holt & Co. Factoring in assumptions on the “missing barrel” issue, the firm stands out from the crowd in calling for a close-enough market balance to justify an $80 WTI price in the second half of this year.
“The market is oversupplied; there’s no issue there. It’s a question of magnitude,” said Dave Pursell, Tudor, Pickering, Holt & Co.’s managing director responsible for analyzing global oil and gas markets. “If it’s not oversupplied by very much, then it can tighten up pretty quickly.”
The average year-over-year decline in U.S. onshore output will probably be around 600,000 bbl/d in 2016, according to Dave Pursell, managing director with Tudor Pickering Holt. “Declines are happening,” he said.
The key difference separating Tudor, Pickering, Holt & Co. from the consensus is the former’s view that the global crude market “is not massively oversupplied,” according to Pursell. “If the market is indeed tighter than consensus believes, then modest demand growth coupled with some supply declines will create an undersupplied market. And if that’s the case, prices are going much higher.”
But how to explain analysts’ divergent conclusions from essentially the same set of circumstances?
Most likely, said Pursell, is that consensus is relying primarily on reported demand and supply numbers, whereas Tudor, Pickering, Holt & Co. is working off OECD inventory data and the issue of “missing barrels,” typically resolved by upward revisions in demand and/or downward revisions in supply (see Oil and Gas Investor, October 2015).
For example, second-quarter 2015 International Energy Agency (IEA) demand and supply figures show crude markets were oversupplied to the tune of 3.3 MMbbl/d. However, IEA data indicated a build in OECD inventories of only about 1 MMbbl/d.
“Either somebody outside the OECD countries is hoarding crude, which is unlikely given developing countries’ lack of available money or infrastructure, or the demand and supply numbers are wrong, and the inventory data are telling us what the ground truth is,” said Pursell.
For the third quarter of 2015, when seasonal builds are typical, global inventories as estimated by the IEA came in somewhat higher than the 700,000 bbl/d build that had been modeled by Tudor, Pickering, Holt & Co., noted Pursell. However, the trend in inventories is expected to be increasingly influenced by declining production, as exemplified by projected declines seen by the firm in U.S. onshore production (i.e., excluding Alaska and the Gulf of Mexico).
Tudor, Pickering, Holt & Co. outlined two scenarios to illustrate the impact of onshore production declines.
One scenario illustrated a monthly decline in production of 35,000 bbl/d, while a second called for a monthly decline of 75,000 bbl/d, a rate closer to declines actually occurring, said Pursell. In terms of an average year-over-year production decline, the first trend line showed a decline of slightly over 400,000 bbl/d in 2016 versus 2015, with a drop of almost 950,000 bbl/d from peak output in April 2015 through year-end 2016. The second showed an average year-over-year production decline of nearly 850,000 bb/d, with a drop of 1.67 MMbbl/d from peak output to year-end 2016.
In the end, the average year-over-year decline in production in 2016 will probably fall in-between the two scenarios at around 600,000 bbl/d, estimated Pursell. “Declines are happening,” he emphasized.
And, longer term, there are plenty of other reasons to support higher oil prices, according to Pursell, arguing that the economics just don’t work for large parts of the industry at sub-$50 to $60/bbl levels.
“There is no scenario in which $60 oil makes sense long term,” said Pursell. “At $60/bbl, much of non-OPEC doesn’t work. Long-term prices of around $85/bbl are needed to be cash- flow breakeven.”
Top, some 13 MMbbl/d of liquids production has been deferred, a bullish signal for medium-term oil prices given this is almost 15% of global supply. Bottom, some production and project deferrals offer hope for a supply response.
For U.S. E&Ps, which have enjoyed significant service cost savings and achieved very material drilling efficiencies during the downturn, there is still only a handful that can hold production flat near cash flow at $50/bbl. Most of the industry needs to see $60 to $65/bbl to generate enough cash flow to keep output flat on a sustained basis. And for the U.S. industry to grow, $80 to $85 is needed, said Pursell.
In addition, in the medium term, the deferral of numerous oil and gas projects may take a bite out of future crude production of about 13 MMbbl/d of liquids (equivalent to about 14% of 2015 global liquids supply), according to a survey by Tudor, Pickering, Holt & Co. The survey found that, of roughly 350 projects under review, approximately 150 projects due for final investment decision (FID) had suffered delays or had been put on indefinite hold.
While deferrals would have minimal impact in 2016-2017, the impact on production of the project deferral is estimated at 1.5 MMbbl/d in 2018, 3.5 MMbbl/d in 2019 and 5 MMbbl/d in 2020.
Total production from the deferred projects, including natural gas and liquefied natural gas (LNG), is estimated at about 19 MMboe/d. Of the 13 MMbbl/d of liquids production, Iraq and Canada together account for roughly 60% of the deferrals. Many of the Iraqi projects were uncertain even before the oil price downturn. In Canada, a large number of deferrals, with production of about 3 MMbbl/d, involved oil-sands projects. Other notable project deferrals were Kazakhstan, Nigeria, Brazil and Angola.
The key issue for rebalancing global markets will be the timeline for Iran’s reintegration into the crude market following the lifting of international sanctions, according to John Paisie, executive vice president with Stratas Advisors in Houston. Assuming verification of compliance, this is expected to take place in stages, starting late in the first quarter or early in the second quarter of this year.
“Once sanctions are lifted, we anticipate Iranian crude exports to increase initially by 250,000 bbl/d, followed by further expansion of another 250,000 bbl/d by the end of 2016. For the first half of 2017, an additional 250,000 bbl/d of production is anticipated as further investment is made, bringing overall incremental output to 750,000 bbl/d,” said Paisie.
While Iran is eager to attract long-term foreign investment, Stratas Advisors noted international oil companies may wish to be wary of investments beyond a 10-year horizon.
The question investors may well ask themselves, it said, is whether they “will want to risk long-term investments in a country whose government, according to the terms of the nuclear agreement, now expects that it is simply required to demonstrate patience for a decade before the EU+3 is obligated to concede the reality of its nuclear weapons threshold status.”
The EU+3, also known as P5+1, refers to France, Germany and the U.K., plus China, Russia and the U.S.
Elsewhere, Iraq is forecast to achieve 3% to 4% annual growth in oil production in a low-price environment, held back by the cost of fighting ISIS and its impact on investment in its southern infrastructure. Russia’s oil production is projected to decline by about 1% annually in 2016-2017. While a depreciating ruble has lowered lifting costs in U.S. dollar terms, Russia’s ability to squeeze more oil from mature fields—in the absence of exploration success—will eventually lose steam, according to Stratas Advisors.
Domestically, U.S. crude production in 2016 is expected to decline, albeit more moderately than the Energy Information Agency’s recent projected drop in annual production for next year of about 570,000 bbl/d, according to Paisie. For those basins projected to grow—limited to the Permian Basin on the oil side and Marcellus/Utica on natural gas—production growth is expected to be weighted to the back half of 2016. Year-end exit growth is forecast to be up 2% for the Permian and 3% for the Marcellus/Utica, with the Bakken, Eagle Ford and Rockies forecast to be flat to down 2%.
2022-05-13 - At stake with the new Texas law are assets including $1.4 billion that Man Group of London runs for the Teacher Retirement System of Texas, and $59.7 million the system has with abrdn of Edinburgh.
2022-03-03 - “Russia supplies around 30% of Europe’s gas and oil imports and accounts for around 11% of world oil production,” AMP’s Shane Oliver said adding that investors are worried about a stagflationary shock.
2022-04-12 - API’s Amanda Eversole and Rystad’s Emily McClain, both of whom are honorees of the Oil and Gas Investor Influential Women in Energy program, weigh in on the most pressing regulatory matters facing the oil and gas industry today.
2022-04-14 - The New York Attorney General launched an investigation to determine if the oil and gas industry has engaged in price gouging following testimonies from oil executives in Congress last week.
2022-03-18 - It is clear that the Biden administration is facing considerable pressure when it comes to its policies toward natural gas.