If a new film titled “Oil in the New World Order” came to town, at least some critics would be sure to carp that its cookie-cutter plot resembled earlier releases. But labeling the oil movie that is playing on screens around the world today a replay or sequel would be inaccurate.

In fact, there have been plenty of plot turns and fresh faces in the latest version, with the focus on global oil’s rebalancing moving from one theme to another with surprising speed. Each oil downturn has its cast of characters, but this one has more than most.

Early on, discussion centered on when growth in U.S. oil production would decelerate and roll over. Next, a rapid rise in Mideast production stole center stage, as Saudi Arabia and Iraq combined to push up 2015 volumes by as much as 1.5 million barrels per day (MMbbl/d) through the middle of the third quarter.

Saudi Arabia raised crude production to about 10.6 MMbbl/d in part related to expanded refinery capacity, but predominantly by pursuing a strategy of garnering greater market share. For its part, Iraq increased output to almost 4.4 MMbbl/d in what one analyst called a “surprising and somewhat inexplicable” surge in production. Both countries were hitting the highest production levels in decades.

Then came the P5 + 1 (China, France, Russia, U.K. and U.S. plus Germany) nuclear agreement with Iran, which paves the way for Iran to increase exports. The magnitude and timing of higher exports remain open to debate, but several observers have gravitated to a potential increase in Iranian exports of 0.5 MMbbl/d, adding an overhang to an already oversupplied market.

As if that weren’t enough to thicken the plot, doubts have surfaced on the demand side of the oil equation—even though global consumption was remarkably robust throughout the first part of the year—prompted by questions as to the health of the Chinese economy and its implications for overall Asian demand. Concerns were exacerbated by the wild action of the Shanghai Composite Index, which in the five and a half weeks ending Aug. 26, 2015, tumbled 28%. From its June 12 peak, the index was down more than 40%.

The silver linings for oil and gas producers and their investors have been few and far between. One possibility is that elevated OPEC production means available spare capacity is close to historical lows, raising the likelihood of resurgent crude prices in the event of a geopolitical event and disruption in supplies.

Another is that from a commodity price viewpoint, the net short speculative position in Brent futures reached record levels in late August, leaving the oil market “primed for a short squeeze on any material positive headlines,” said Adam Longson, CFA, who leads Morgan Stanley’s commodity team. Further, bearish pressure on oil futures may be tempered now that Mexico’s state-owned Pemex has concluded a huge 2016 hedging program at a $49/bbl average price, according to Longson.

Given these factors, what are the prospects for bringing supply-demand fundamentals in crude markets into closer equilibrium over time? And, what time frame is needed, now that Saudi Arabia has shaken up global markets by pursuing its market share strategy instead of playing its traditional swing producer role?

Analysts increasingly expect a longer process to re-balance global markets, with some thinking it may stretch into 2017. As the moving parts have multiplied, optimists who at one time predicted a V-shaped rebound in oil prices now look for a U-shaped recovery. Others forecast a still further elongated, or prolonged, “bathtub-shaped” recovery.

Forecasting presanctions production declines to the present, Iran should have 3.3 MMbbl/d total productive capacity, an incremental 500,000 bbl/d higher than the current 2.8 MMbbl/d.

The rally that wasn’t

A factor in the need to revise timelines was the too hasty interpretation of the declining U.S. rig count that began last year, coupled with government estimates showing a steeper production decline than was borne out by E&Ps’ quarterly reports. The declining rig and production data prompted a fleeting move up to $60/bbl for West Texas Intermediate (WTI); this wound up stifling prospects for a durable recovery as E&Ps prematurely put additional rigs to work.

The incipient move in crude prices was “the rally that killed the rally,” according to Amrita Sen, chief oil analyst with research consultancy Energy Aspects.

“The second-quarter rally we saw in prices is actually what’s causing the damage today,” she said on Bloomberg TV. “Had we had low prices for a sustained six to eight months, we would have started seeing a [downward] supply response. We had that rally, [and] people said, ‘You know what, this is it; the bottom is in. …We can bring the rigs back.’”

The view that crude prices will stay “lower for longer” is now shared by many analysts, in some cases as part of a broader thesis.

Goldman Sachs’ global head of commodity research, Jeff Currie, has argued that a framework of three “reinforcing macro trends” means commodity imbalances may take years, not months, to resolve. The trends are deflation in commodity prices; divergence in countries’ rates of economic growth, with consequent impact on currencies; and deleveraging, specifically related to emerging markets.

Connecting the three is a “negative feedback loop,” according to Currie. In essence, deflation caused by lower commodity prices reinforces a stronger dollar in the U.S., where the economy is expanding faster and interest rates are higher. In turn, higher interest rates raise the cost of funding for emerging market countries. This reinforces the need for emerging markets such as China to deleverage and “ultimately reduces the demand for commodities.”

Although fewer, voices of optimism remain. Executives of Core Laboratories NV have forecast strengthening oil prices by early 2016, citing a 500,000 bbl/d year-over-year decline in U.S. production by the end of this year, a 10% drop in annual output at Pemex and unnamed sources suggesting output in Russia could perhaps be down by 800,000 bbl/d. The Domestic Energy Producers Alliance, meanwhile, has projected a 700,000 bbl/d decline in U.S. production from mid-2015 to mid-2016.

The research house view

Evan Calio, managing director with Morgan Stanley, expects to see the scales tipping in favor of the demand side of the oil equation by late 2016. This assumes the reintegration of Iran into world markets with an incremental 500,000 bbl/d of supply, Iraqi production approaching peak levels and a continued upward trend in China’s oil demand.

He is quick to part company with those he sees as having a “narrow-sighted” industry view that is based on recent events, as if these events will remain constants. For example, the idea that oil prices might hover around $50/bbl for the next several years is “folly,” he said.

“The entire system is dynamic, and it’s going to remain dynamic from both a supply and demand perspective. To the extent there is growing demand, which is our view, and that China is not imploding, you’re going to need a higher price to produce those volumes, because companies aren’t making enough money at these levels.”

While U.S. production declines have been slow to materialize, Calio anticipated the first sequential decline would take place in the third quarter of this year. He projects output falling by a combined 200,000 bbl/d in the third and fourth quarters, with onshore declines offset in part by growth in the Gulf of Mexico.

He ascribes the relative resilience of U.S. production to its ability to move down the cost curve at a faster pace. “The ability to extract more resource economically has been improving at some of the fastest rates, and part of those improvements have been recycled into their capital budgets,” he said.

However, as hedges roll off going into late 2015 and early 2016, production declines may accelerate, he added. “The absence of hedges for 2016 means that there will have to be a more dramatic realignment of cash flow and spending, not only in the U.S., but also worldwide.”

While Morgan Stanley employs strip pricing in its current financial modeling for E&Ps through 2017, Calio pegs WTI pricing at $75 to $85/bbl for 2017 if a balance is reached between supply and demand in late 2016, in line with the earlier forecast. Progression toward that price range would, of course, begin earlier if global inventories start to be drawn down.

As for the commodity strip, “people look at the strip as if it is gospel,” Calio commented. “But the strip historically has had an R-squared regression to actual realized pricing that is insignificant. That is to say that the strip is not, and has never been, an accurate forecaster of forward prices.”

In terms of the U.S. energy sector’s readiness to raise output—assuming an appropriate price signal were given to meet rising demand projected at 1.2 MMbbl/d next year—Calio views the U.S. as “a very inefficient swing producer” as compared to Saudi Arabia, which has the ability to “make a few phone calls and control a pretty large quantum of the oil market in a very short time frame.”

The U.S. energy sector is made up of a “bunch of disaggregated companies,” he said. “I don’t disagree that the U.S. will respond to price. I just think people don’t fully understand how much time it will take to execute, given the trauma experienced in having to shut down whole divisions, lay people off, repair balance sheets, etc. It won’t be an immediate reacceleration.”

Regarding Iran, the projected 500,000 bbl/d increment in production is likely to be skewed to the back end of 2016, given the time needed for the final cessation of sanctions, discovery of the proposed fiscal terms and a resumption of activities, Calio noted. And the question of funding remains unanswered.

“The question is, where is the money coming from?” asked Calio. “If the industry is not making money, who is likely to go into Iran and further impugn a balance sheet? And if the terms are so great that Iran attracts capital, it’s going to pull capital from somewhere else. People will have to make hard decisions, and generally it is going to be funding for lower-return projects that will have to dry up.”

M&A activity is on the horizon, but pinpointing when it might commence is “challenging.”

“I think it’s inevitable that there will be consolidation in the U.S.,” he said, noting that unconventional resource plays represented some 4 MMbbl/d of growth over the last four years. These plays offered “lower geopolitical risk and an improving science outlook” in terms of continued improvements in internal rates of return (IRRs) and lower breakevens. With the large-cap E&Ps now having shed their international assets and restructured their portfolios around domestic resource plays, “I think it’s setting up for M&A,” he said.

The nature of that consolidation is debatable.

“I think the two U.S. integrateds—Exxon Mobil Corp. and Chevron Corp.—are viewed as the most likely consolidators, given their balance sheets and how competitive the resource is relative to the balance of their portfolios,” said Calio.

“And unconventional is a scale game. Aggregating scale and basins provides a tremendous advantage, so there is a natural reason why there should be consolidation in the end.”

In addition to integrated producers targeting select large-cap names, Calio expects to see mergers involving E&Ps, whether it be a large-cap acquiring a medium-cap or a merger of equals between two mid-caps. Overseas integrated producers are less likely to be in the forefront of M&A, in part due to their need to sustain dividends and in part because of their prior “mixed experience” in joint ventures that, in hindsight, were suboptimal.

More aggressive outlook

Dave Pursell, managing director responsible for analyzing global oil and gas markets at Tudor, Pickering, Holt & Co., is well aware that his firm’s commodity outlook is perhaps the most aggressive on the Street. The firm projects WTI prices at $80/bbl for the third and fourth quarters of 2016, and says the outlook for 2017 may be analogous to a coiled spring being released, with prices jumping higher.

U.S. production began rolling over around mid-year and should continue through the third quarter, since E&Ps have spent 70% of their full-year capex in the first half, he said. Globally, there is definitely oversupply, but rebalancing the market is not expected to prove as daunting a task as many believe.

“The market is oversupplied, but it’s oversupplied by a little, not a lot,” he said. “It won’t take as much to turn the market as consensus believes.”

Earlier this year, there was considerable caution among investors about oil demand, recalled Pursell, but first-half demand “has been crushing it—way better than anybody anticipated.” Global oil demand increased at a rate of 1.8 MMbbl/d in the first half, and Tudor, Pickering is forecasting global demand growth of 1 MMbbl/d for both second-half 2015 and full-year 2016.

Are global crude markets as oversupplied as International Energy Agency (IEA) data would indicate?

Perhaps not. Looking at IEA data that show global supply exceeding demand by 3 MMbbl/d in the second quarter, Pursell notes this represents an increase of 2.5 MMbbl/d versus a normal inventory build of 500,000 bbl/d in the second quarter. He then compares this to IEA data on crude and product inventory builds for OECD countries, where the build was 1 MMbbl/d in the second quarter, an increase of only 500,000 bbl/d versus a normal build.

“If I only built inventories by 1 MMbbl/d, I’m just not that oversupplied,” he said.

The divergence in data may be due in part to the “missing barrels” phenomenon, which refers to a line item officially termed “miscellaneous to balance” (MTB) by the IEA. The MTB line is the plug number used by the IEA when its changes in measured global supply and demand do not add up to its measured changes in inventories. (Note: A positive missing barrels number typically occurs when the initial data reflect either: 1) demand being understated; 2) supply being overstated; 3) inventories being understated; or 4) some combination of the prior three.)

Importantly, changes have most frequently occurred to lower the missing barrels number when the IEA’s global demand estimate has been revised higher over time.

Bottom line: “We’re not that loose,” said Pursell. “The market is oversupplied, but closer to 500,000 bbl/d and not 2.5 MMbbl/d. And just as a small amount of oversupply can crush price, the flip side is that a small amount of undersupply can get prices moving higher very quickly.”

Pursell predicts prices will begin climbing in advance of an undersupplied market in the second half of next year. His underlying assumptions are that global oil demand will grow at a “mid-cycle” rate of 1 MMbbl/d, while U.S. supply in 2016 will fall by 400,000 bbl/d. In this scenario, non-OPEC, non-U.S. production would come off by 300,000 to 400,000 bbl/d next year.

The expectation that Iran will boost supply by 500,000 bbl/d is based on the trend line of Iranian production over the period of 2008 to 2011, which, if extrapolated to today, suggests a capacity of around 3.3 MMbbl/d versus current production of 2.8 MMbbl/d.

While increases in exports will happen quickly once sanctions are lifted, the bump in Iranian production is likely to be limited to 500,000 bbl/d in the short term. “That’s all they’ll be able to do,” said Pursell. “They clearly have underinvested in these fields over the last several years.”

He models OPEC production for next year at 31.5 MMbbl/d. Saudi Arabia has signaled its intention to ease back production by 500,000 bbl/d as seasonal power generation demand wanes. Coincidentally, this might represent an unspoken offer to make room for the 500,000 bbl/d that Iran plans to bring to market, he noted. Other OPEC producers, Nigeria and Venezuela, are assumed to maintain current capacity, even as trendline production indicates declines of around 100,000 bbl/d.

Among non-OPEC, non-U.S. producers, Russia is the “big uncertainty,” he said. It is suffering from sanctions but benefiting from the weak ruble on the cost side. Its production is currently modeled to decline by 200,000 bbl/d in 2016, according to Pursell. Eurasia Drilling, which drills almost one-quarter of all wells in Russia, has released first-half results indicating a significant drop in drilling activity by Russia’s second largest oil producer, Lukoil.

As for OPEC spare capacity, Pursell contrasts today’s slim margin of supply versus 1986, when 14 MMbbl/d of spare capacity overshadowed a 60 MMbbl/d market. Assuming that total Saudi capacity is 11.5 MMbbl/d (versus the official 12.5 MMbbl/d), he estimates OPEC spare capacity at around 2.5 million bbl/d, including 500,000 bbl/d for Iran as it awaits the sanctions repeal.

Like others, Pursell questions the usefulness of the forward commodity curve in predicting oil prices.

“If the forward curve were accurate, there’d be no reason to hedge,” he said. And if you hedge, “you should hedge when you want to, not when the banks want you to.”

Bumps on the road to inflection

Dave Kistler, managing director and co-head of exploration and production research at Simmons & Co. International, offers a measured evaluation of the road to rebalancing, seeing the market approach an inflection point in the third quarter of next year that could lead to a more balanced market in late 2016 and into 2017. But he cautions that there still are speed bumps ahead.

The Simmons research team has developed two paths of analysis based on differing commodity price assumptions. One is founded on the WTI forward commodity curve as of August 7 of this year, which it calls scenario one. The second is based on an assumed price deck of $60/bbl and $65/bbl, respectively, for 2016 and 2017, which it calls scenario two or its “normalized scenario.”

In the first of these, in which E&P models are adjusted to reflect pricing in line with the August 7 commodity curve for WTI, companies’ cash flows are “eviscerated,” said Kistler. Drillbit capex is projected to drop by 40% in 2015 and a further 23% in 2016, before flattening out in 2017. From recent levels, the rig count falls by 94 rigs by year-end 2016, while year-over-year U.S. oil production decreases by 160,000 bbl/d in 2016 and holds flat in 2017.

The second scenario offers more benign results by assuming a more optimistic commodity price outlook. Under the normalized scenario, drillbit capex is projected to decline by 5% in 2016 and then increase by 13% in 2017. Some 143 rigs are added through the end of 2017, while U.S. oil production falls by 70,000 bbl/d in 2016 and then rises by 280,000 bbl/d in 2017.

But the U.S. does not operate in isolation, of course. Other forces are helping to shape U.S. and global oil market conditions, and may be playing a part in pushing a rebalancing of oil to the right.

Surprisingly strong supply growth has come from both OPEC and non-OPEC, non-U.S. sources, according to Kistler. In particular, Saudi Arabia and Iraq have accounted for the vast majority of the OPEC increase, with each adding 800,000 bbl/d since November 2014.

“Earlier in the year, we were not convinced that OPEC had the capacity to increase as much as they have in fact done. So in addition to deciding not to cut, the surprise has been in their ability to increase, which to a large extent has offset increases in demand that have taken place,” he said.

Production for non-OPEC, non-U.S. producers also outperformed in the first half, with output rising by 560,000 bbl/d against IEA expectations that it would hold flat with the prior-year period. For full-year 2015, Simmons projects production growing by 300,000 bbl/d but then losing momentum, with year-over-year declines of 400,000 bbl/d in 2016 and 500,000 bbl/d in 2017.

On the global demand side, first-half demand growth was robust at 1.8 MMbbl/d, and Simmons is projecting above-trend demand growth of 1.45 MMbbl/d in second-half 2015 followed by growth of 1.4 MMbbl/d in 2016 and 1.3 MMbbl/d in 2017. However, the firm’s confidence is restrained by “less than robust recent economic growth trends in China, Japan, Brazil and Russia.”

Comparing supply and demand, global balances under both of Simmons’ scenarios reflect “material oversupply” through mid-2016, with current OPEC production of 31.8 MMbbl/d exceeding the “call on OPEC” production of about 30.2 MMbbl/d in the latter part of 2015, as well as a call of some 30.7 MMbbl/d in the first half of 2016.

In addition, following the planned relief of sanctions on Iran, Simmons estimates that an incremental 500,000 bbl/d of Iranian supply could potentially delay a rebalancing of the oil market through the second half of next year.

Ostensibly, the first instance of rebalancing (setting aside the Iranian export issue) would occur in the third quarter of next year, when the Simmons model, under its first scenario, shows the call on OPEC, at 31.9 MMbbl/d, narrowly exceeding OPEC’s current production of 31.8 MMbbl/d.

Kistler is reluctant to emphasize this as an inflection point, however, partly because of the heavy buildup of inventories of both crude and refined products. More realistically, supply and demand balances are likely to shift to an undersupply in 2017, he said.

“We don’t want to fool ourselves that at that moment there would be an inflection point,” said Kistler. “But if people can do the math, and can anticipate inventories drawing down, then the commodity price should start to work higher to ensure that you don’t end up in a dramatically undersupplied environment in the second half of 2016 and in 2017.”

At issue is the near-term concern about above-average refinery turnarounds during the fall of 2015 and the spring of 2016. Given aggressive refinery runs during the peak driving season, maintenance has been deferred at some refineries, leading to increased downtime when refineries go down. This is expected to result in headwinds for refinery crude demand, with inventories expected to build from already high levels and contribute to another round of storage capacity limitation concerns.

“We still have a lot of production that needs to go through what storage is available and be converted into refined products for the consumer,” said Kistler. “You have to have low oil prices to incent all that to happen and to clear the market.”

Looking at the industry’s mid- to longer-term fundamentals, however, the outlook is considerably more constructive, said Kistler.

OPEC capacity has not grown in three years, and Iraq is the only member that is expected to materially add productive capacity over the next five years. Foreign producers in Iraq are cutting back investments, as Iraq faces fiscal challenges and struggles to make payments. Further, the security situation in Iraq is described by Simmons as “incendiary and unstable.”

Moreover, as OPEC countries have ramped production, effective spare capacity has fallen to nearly the lowest level in five years, at 2.2 MMbbl/d, or 2.3% of global demand. This is an “exceptionally thin” margin of spare capacity at a time when geopolitical tensions have escalated across the Middle East and North Africa, largely uncoupling a historical relationship between oil prices and spare capacity.

“I do not believe there is a sufficient risk premium in the commodity price for what could be a geopolitical event that rebalances the market rapidly,” said Kistler. “Any major geopolitical disruption will have a much more volatile impact than it has in the past.”

Looking at non-OPEC, non-U.S. production, which exceeded expectations in the first half of this year, signs of a reversal are on the horizon. Producers that helped drive first-half output resilience included Brazil, Canada and, in particular, Russia among the Big Three, as well as countries contributing to base production. For example, the North Sea, which increased production in 2014, looks set to grow production again this year for its first consecutive years of growth since 1999-2000.

However, the outlook for production, especially that of the Big Three producers, has become less clear as evidence mounts of sustained lower capital investment associated with the oil price collapse.

In particular, visibility has begun to “evaporate” beyond 2017 as regards the pipeline of long lead-time non-OPEC projects. Whereas the backlog of major projects in 2015-2016-2017 is up 12% versus the prior three-year period, the period of 2018-2019-2020 shows planned project start-ups totaling 3.3 MMbbl/d, a 45% drop from the 2015-2016-2017 period.

Importantly, since last year’s OPEC meeting, Simmons counts about 5 MMbbl/d of major projects that have been cancelled or delayed, adding to a prior tally of some1.4 MMbbl/d for a total of 6.4 MMbbl/d cancelled or delayed projects. This includes about 3 MMbbl/d of Brazilian projects, 1 MMbbl/d of Canadian oil-sands projects and 1.3 MMbbl/d of deepwater projects outside Brazil. Significantly, of the 6.4 MMbbl/d, 4.05 MMbbl/d of projects were delayed indefinitely or cancelled outright (i.e., not just subject to rescheduling).

Simmons notes the duration of such capital contraction or stagnation is a key issue in arriving at non-OPEC, non-U.S. base decline rates. And, longer term, this deferral and cancellation of major projects will tend to create “a meaningful reduction in supply during the 2018-2020 period, creating potential for a production shortage later in the decade and forcing reliance on shorter lead-time U.S. shale production and OPEC to fill a potentially substantial gap.”

As for short-term prospects for rebalancing the market, Kistler identified several important variables. Would the forward strip stabilize at recent levels? Is OPEC close to having reached maximum production? Will oil demand growth maintain at recent levels? If these hold, prospects for a more rapid rebalancing—and commodity price appreciation—are improved.

But the U.S. shale industry will also play a role.

“The question is: If the commodity moves up too quickly, as happened in the second quarter, will E&Ps put rigs back to work too soon, or will E&Ps be disciplined enough to allow the market to correct itself?” asked Kistler. “If history repeats itself, they tend not to be. And that’s why cycles tend to take longer to work through.”