It's hard to deny that 2016 has been a remarkable year.

After crude found a bottom early in the year, energy stocks moved higher, reflecting not just commodity price gains, but a variety of factors. Drivers include repaired balance sheets, greater capital efficiency and, importantly, technological advances that have dramatically lowered unconventional finding and development (F&D) costs for E&Ps.

Beginning in the first quarter, when industry stalwarts issued equity to retain an investment grade rating, well over $30 billion in equity has been raised to date by the energy sector. And yet, as observed in a recent research note by Tudor, Pickering, Holt & Co., energy investors are still awaiting conditions that would “help determine when broader, big money rotation in energy really takes off.”

After successive years of underperformance by energy in 2014 and 2015—and broader market indices trading at sometimes lofty valuations— investors turned to publicly traded equities to initiate or add to energy positions ahead of an anticipated rebound. Fund managers with substantial monies to invest have had regular opportunities to increase exposure simply by participating in the many overnight offerings by E&Ps tapping the equity market.

Are we in the midst of an upswing in sentiment favoring energy equities? Is more investor money waiting in the wings?

“Interest in the sector is probably higher now than over the last two-and-a-half years,” said Ted Davis, portfolio manager of Fidelity Investments’ Select Natural Gas Portfolio. After a “healing period,” the sector has become more “investable,” he said, and interest has broadened from mainly energy sector specialists to include diversified fund managers and retail investors.

Fidelity Investments is one of Boston’s biggest asset managers, with mutual fund assets alone totaling $2.1 trillion as of September 30, 2016. While Davis collaborates with other energy team members at Fidelity, his primary responsibility is managing the Select Natural Gas Portfolio. The fund’s mandate offers greater scope than its name might suggest. Its top five holdings, as of September 30, were: Baker Hughes Inc., Anadarko Petroleum Corp., ConocoPhillips, Encana Corp. and Devon Energy Corp.

Risks of rebalancing

In terms of the supply-demand dynamics of the oil market, the outlook now is “more constructive than it has been for some time,” said Davis. In addition, relative to three years ago, the industry has “bent the cost curve down by anywhere from 15% to 30%,” principally in the U.S. unconventional sector, but also to a lesser extent in large-scale offshore projects. “The long-term price needed to incentivize new production is lower than it was three years ago. And there is permanence to that.”

Industry prospects are clouded by key issues. One is whether OPEC can build on its initial agreement in Algiers and reach a subsequent accord that its members can adhere to. A second is whether non-OPEC members, primarily Russia, will join in on—and stand by—the terms of whatever deal came out of the Vienna OPEC meeting on November 30.

Davis recognizes risks in both directions. On the one hand, “we could easily be at much higher prices next year,” he said. But if talks break down and Gulf OPEC members revert to fighting for market share, a prolongation of the recent “purgatory environment” is possible. However, pushing out a rebalancing of global oil markets would carry risks of its own, noted Davis. “That would likely set us up for another year of starving an industry that needs capital simply to keep producing at current levels, and it would be another year in which you would create the risk of much higher prices down the road given the underinvestment.”

At what point does the risk of repeated underinvestment—potentially for a third consecutive year—overshadow the relentless focus on the industry’s swollen crude and product inventories? “It may be starting now; it’s not entirely clear,” said Davis. “What’s important is to look for a trend of counter-seasonal inventory draws. Historically, one of the better predictors of oil price in the short term is days-to-forward cover; that is, the current inventory level relative to forward demand. When that inflects, and the rate of change of inventories is no longer tracking seasonal norms, it typically doesn’t take long before people start to think, ‘We haven’t been spending money on large-scale oil development.’”

Such an eventuality, said Davis, would in turn highlight a looming supply deficit of “millions of barrels by 2019 and 2020”—a void most likely filled by the U.S. unconventional sector.

“It’s the only source of shorter cycle production that is out there if OPEC is maxed out,” said Davis. “But you’re going to need a price signal that’s much higher to incentivize enough drilling to drive that production growth. Assuming reasonable demand and the absence of an OPEC cut, you could see that toward the end of next year. If you get an OPEC cut, or some kind of freeze, it could happen sooner.”

The price signals needed to stimulate increased activity would vary by sub-sector, noted Davis.

“At $50 per barrel, I think you’ll see a good deal more activity in the unconventional sector—and you’re already seeing some of it—but the larger players are going to want to see $55-plus per barrel. And they’re going to want to believe that $55-plus is here to stay. It won’t be as if, once we touch $55, you’ll see a lot of rigs coming back. It’ll be when you see $55 with the idea we’re moving into the $60s.

“For deepwater, where you’re making a multi-year commitment—and may not see a dollar back on capital investment for four to six years in some cases—you’re likely going to have to see mid-$60s and higher for that to happen,” continued Davis. “Brazil is economic at prices much lower than that, and large-scale projects in parts of Norway are economic at lower prices. But it’s difficult to make the numbers work for complex, Lower Tertiary projects in the Gulf of Mexico unless your base case is at least $65.”

Attractive opportunities

Given the right price signal, what kind of supply response can come from unconventional producers?

Assuming oil prices in the $50s, a reasonable scenario would be for production to continue its decline through 2016 and then flat-line in the first three to six months of next year, according to Davis. Then, growth is likely to resume in the second half of 2017, he said, with output probably increasing at a rate of about 500,000 barrels per day (bbl/d) per year.

“And if you assume world oil demand grows at an annual rate of 1 MMbbl/d to 1.2 MMbbl/d, then in this scenario we’d supply half of it, and the rest comes primarily from OPEC.”

In the meantime, what are the most attractive investment opportunities?

Davis describes himself as “very constructive” on Lower 48 shale, as well as parts of the Canadian unconventional sector. With higher oil prices and activity levels, some cost savings will go back to the oilfield service sector, which in some cases is operating at or below cash breakeven. “But, overall, a lot of the efficiency gains are here and they’re real, and this part of the production base is likely going to be much more competitive. There should be a lot of room to run in some of these basins, particularly the Permian.”

While the Permian and the Scoop/Stack plays are “very much in vogue,” Davis offered the Bakken as a basin that is often overlooked. “There are companies with a good amount of locations for their size, that are economic, and in some cases have better economics than in a lot of the Permian. But people don’t immediately quite see the growth or resource upside, so they don’t look at them very closely. A number of companies are flying under the radar there.”

As for Permian metrics, “you’re seeing a lot of big deals for big numbers,” said Davis. “You can rationalize these acreage prices by making, in some cases, aggressive assumptions about downspacing, and thus well locations per pad, and the number of zones you’re able to tap in a formation. In hindsight, some of these will look very smart, but I have trouble believing that they’ll all look smart.”

In terms of natural gas, Davis viewed the outlook as “cyclically attractive” over the next 12 to 18 months, but predicted there are scenarios in which prices could be capped at around $3.10 to $3.30 per thousand cubic feet (Mcf) thereafter.

“In the short term, natural gas prices could go higher because of the pipeline constraints in the Northeast,” he said, noting several sources of growing demand: exports to Mexico, LNG exports, new petchem demand and so on. But as pipeline constraints are loosened toward the end of this year and into 2017, “the long-term normal price to pull gas out of the Marcellus and get it to market is still not higher than $3.10 to $3.30/Mcf."

Conventional’s role

Dan Rice is the lead portfolio manager of energy strategy at GRT Capital Partners in Boston. Rice joined the firm in early 2013, after many years of managing the BlackRock Energy & Resources Fund. He is bullish on energy, so much so that he counts higher oil prices as just one of at least three ways to win with energy.

The dramatic drop in F&D costs enjoyed by the E&P sector has been, and continues to be, of prime importance, according to Rice. In a commodity market where the focus is on being “the low-cost supplier,” a wide gap has opened up in terms of F&D costs prevailing between unconventional and conventional producers, with the latter lagging their more nimble U.S. shale competitors.

“The key change in the industry is that capital is migrating from high-cost conventional production to low-cost shale production,” said Rice. “In the old days it was conventional or deepwater production that was low-cost. Today, low-cost is the Middle East, which is tough to get into, or it is U.S. shale.”

Rice’s bullish stance reflects, in part, a belief that crude markets are skewed by being too U.S.-focused and not fully grasping the impact of declines in non-OPEC, ex-U.S. conventional production.

“Right now, the market is U.S.-centric, it’s shale-centric,” said Rice. “Market observers just look at what potential production increases could come from shale, and then the media tends to highlight that as a threat to OPEC. Well, that’s not a threat to OPEC if the rest of the world is not offsetting enough of the natural production declines and, as a result, overall world supply is not growing.”

Global oil production can be divided into three approximate categories, according to Rice: roughly 50 MMbbl/d of conventional output, including deepwater, oil sands, etc.; 40 to 41 MMbbl/d from OPEC, including condensates and other natural gas liquids; and about 4.5 MMbbl/d of unconventional production from U.S. shale. Rice assumes a decline rate on the conventional component of about 6%. (This is higher than estimates from some consultants, which factor in regular maintenance capital.)

“U.S. shale is the one getting all the attention, but it’s actually dwarfed by the amount of oil that needs to be replaced due to conventional oil declines of around 3 MMbbl/d per year,” he said.

“My estimate is that the industry is replacing roughly 2 MMbbl/d of that per year, comprised of about 1.1-1.2 MMbbl/d from major projects and the balance from infill work done on existing field production. But it’s still about 1 MMbbl/d less than the decline rate.”

In predominantly conventional production from non-OPEC, ex-U.S. countries, Rice sees a steepening decline, with output falling by 700,000 bbl/d, 1 MMbbl/d and 1.2 MMbbl/d in 2018, 2019 and 2020, respectively. Output in 2017 is now expected to be flat relative to 2016, largely due to the recent “one-off” event of the Kashagan project coming online in Kazakhstan. The much-delayed project was originally due to be commissioned in 2005.

The projected decline in conventional production reflects “the impact of long-lead-time projects that have been canceled or deferred,” noted Rice. “What’s left of the major projects that are going ahead is not going to fill the void, and I don’t think there’s really any way to reverse that.”

What are the commodity price implications of the supply gap potentially widening?

“You’re not going to see much additional conventional production coming onstream until $65/bbl or higher,” said Rice. “The conventional world needs $70/bbl or $75/bbl to make a profit. If oil prices are below that, you’re going to have a tough time replacing production. If they’re above that, it will spur development. But even then it’s going to be with a two to three year delay.”

Rice pointed to the conventional producers’ inability to match the unconventional sector in lowering F&D costs as an ongoing issue. He cited F&D costs for conventional producers reaching $50/bbl in 2014. And while F&D costs ostensibly retreated to about $44/bbl in 2015, this reflected only 70% of production being replaced, with a move up the cost curve required to replace 100%.

“And on top of that, you would need about $20-$25/bbl in oil prices to make a 10% rate of return over the life of the project,” he said.

Even assuming ongoing progress in reducing conventional F&D costs, the comparative advantage in favor of the unconventional sector is remarkable, as U.S. shale F&D costs have fallen to “crazy” levels.

“F&D costs for U.S. shale have gone from around $35/bbl in 2010-2011 in some of the best areas of the U.S. to less than $10/bbl in certain areas today,” said Rice. “And overall F&D costs for unconventional production in the U.S. are probably close to $12/bbl, which is crazy. Even in the much maligned Bakken, F&D costs have dropped by half to below $15/bbl.”

Finding balance

Fidelity Investments’ Davis comes up with directionally similar, if slightly less aggressive numbers. From levels of $25-$30/bbl three or more years ago, he estimated unconventional F&D costs have come down to $10-$15/bbl in the “better areas.”

Allowing for overhead and other expenses, what do these economics portend for production growth?

“The economics are great, but the E&Ps that own U.S. shale have balance sheets that limit them to driving up production by only 500,000-700,000 bbl/d—and that’s it,” said Rice. “That’s not enough to balance the market if conventional production is dropping by 1 MMbbl/d, or if demand grows by about 1 MMbbl/d. And that’s how you end up with prices going up.”

So far, major oil companies, with some exceptions, have not played a significant unconventional role.

“The majors have a presence, but they’re not there on a significant scale,” commented Rice. “What’s amazing is that we’ve had $30 billion of Midland and Delaware transactions in the last six months, and none of it has gone to the majors. The majors are in almost every data room, and they’re getting outbid by the independents.”

How is that possible, with the majors having much stronger balance sheets and a lower cost of capital?

“The finding costs are coming down extremely fast,” said Rice. “The independents are nimble and are on the cutting edge in terms of where the technology is today, whereas the majors are slower and probably three to six months behind on finding costs. If you’re a major, you may have taken your unconventional F&D costs from $15-$18/bbl down to $12/bbl, but the independents have already taken their F&D costs down to $7-$8/bbl. It makes a huge difference to what the acreage and deals are worth.”

However, if the majors were to enter the unconventional sector on a larger scale, there is the risk that their greater balance sheets would prove to be too much of a good thing, according to Rice.

“Near term, you don’t want the majors owning U.S. shale,” he said. “There’s a difference between, on the one hand, Pioneer Natural Resources spending approaching $3 billion per year in the Permian, and on the other hand one of the majors taking out someone like Pioneer and spending $12 billion per year. “If a major were to acquire a significant shale player and triple or quadruple its capex, you could have industry-wide growth of 1.5 MMbbl/d—maybe even as much as 2 MMbbl/d— and that would wreck the world oil market.”

Ways to win

Rice believes the move higher in E&P stocks to date is due more to improving efficiencies—and less directly to higher oil prices—as unconventional F&D costs have come down and acreage has become more valuable “by multiples.” However, he suggested there is still more than one way to win in the E&P sector, in which GRT manages four funds.

First, F&D costs can continue to come down. Second, further progress may be made in proving up tighter downspacing or additional zones. The Delaware Basin has as many as six to eight zones, for example, but is typically given credit for three. Third, oil prices may go up beyond what is currently discounted in the market. And lastly—a “more conjectural” issue—is if the entire unconventional sector “gets taken out by the majors as they seek to own low-cost supply,” said Rice.

“Of these three or four factors, if any one of them materializes, it could push the stocks up by another 30% to 50%,” he predicted.

Shaji John, vice president with Pioneer Investments in Boston, began 2016 with a “mildly overweight” position in energy and has increased his weighting through the year as he has gained comfort with the outlook for energy. John is co-manager of the Pioneer Select Mid Cap Growth Fund and is responsible for the fund’s energy, basic materials, industrials and financials sectors.

John relied in part on his experience in other commodities, such as building materials, to recognize that oil prices in early 2016 were unsustainably low. “When the price of a commodity falls below the variable costs of the lowest cost tier of producers, you have to step in,” he recalled.

In addition to favoring E&Ps with strong balance sheets and acreage in the best basins, John focuses on companies’ ability to “control their destiny” with regards to unit costs. With E&Ps essentially “price takers” in selling their product, the “only thing they can control is their unit costs. So you look for companies that are aggressively using technology and superior completion techniques to lower their unit cost by increasing the recovery rate of their wells.”

This points to E&Ps that are not only in the most prolific basins, but also have assembled a contiguous acreage position that lends itself to drilling wells with longer laterals, said John. Drilling and completion costs are higher for longer lateral wells, but are more than offset by increases in estimated ultimate recoveries (EURs), he noted. Early entrants in a play are typically beneficiaries of contiguous acreage, he said, citing Pioneer Natural Resources Co. and Cimarex Energy Co. in the Permian, and Continental Resources Inc. in the Scoop/Stack.

John views Cimarex Energy as promising in that it has contiguous acreage in both the Permian and the Midcontinent. It is also prosecuting additional zones in the Permian and conducting a variety of density tests. Although carrying more debt, Continental is seeing gains in capital productivity that over time will allow it to right-size its balance sheet. And its Stack acreage is far more prospective than many realize, said John.

In oilfield services, John views Forum Energy Technologies Inc. as also promising. About 50% of the company’s product line is comprised of “consumables,” with fluid ends and mud pumps amongst its key products expected to see rising demand as inventories are depleted and restocking resumes.

Looking beyond 2017, with the decline in major oil projects, John termed the outlook for oil as “very positive,” but recognized possible headwinds. These included U.S. dollar appreciation, potentially less rapid Chinese demand growth and possible overlooked brownfield capacity globally.

“The crystal ball is not exactly clear; it’s somewhat cloudy,” he said. “But when the turn comes, I do think U.S. production will surprise to the upside. During the last few years there was a lot of drilling for HBP reasons; but now, much of the HBP work is done, and a lot of companies are going into full-bore development mode.”

Taking a longer-term view of an E&P’s prospects is important for Katharine Jackson Hobbs, Boston-based MFS Investment Management’s energy equity research analyst, who assumed coverage of the sector in the fall of 2010. Hobbs follows primarily small and mid-cap stocks, looking for names that meet MFS’ investment criteria of quality and growth. In a tumultuous commodity market in recent years, this has put a premium on stock picking.

“I’m always looking for quality and duration of growth,” said Hobbs, “and I’m always looking for opportunities that can generate alpha.”

With stock indices near all-time highs, Hobbs indicated energy has found renewed investor interest.

“Any time you have a sector with multiple years of underperformance, it garners interest,” she said, “especially with energy having faced so many challenges over the last two years and the broader market trading at near all-time highs.”

How is sentiment among basins beyond the Permian and Scoop/Stack?

“There have been exciting developments across the board in terms of efficiencies and de-risking,” she observed. “I’m excited to see how many benches end up working in the Midland and Delaware basins, and likewise to see the impact of new frack techniques in the Bakken and what that means for wellhead returns. And I’m excited to see continued development and consolidation in the Eagle Ford.”

In the Haynesville, Hobbs foresaw an improving natural gas differential, as the supply-demand balance was expected to tip in favor of the producer—a development that, with no costs, would allow funds to “drop directly to the bottom line.” The Haynesville’s proximity to several new sources of gas demand—Mexican markets, LNG export terminals and incremental petchem demand—is driving the development.

As for the oilfield services sector’s positioning for a rebound, “pressure pumping companies, in particular, gave up a lot of price in the downturn,” noted Hobbs. “As they have adjusted to the lower activity level, and sought to preserve their ability to respond to incremental demand, I would expect them to want to recoup in the recovery some of the concessions they gave up earlier.”

Will E&Ps be able to secure enough frack sand as activity levels rebound?

“I think it’s not just a question of ‘Will there be sand?’ but rather ‘Will there be sand where we need it?’” said Hobbs. “We’ll have to wait and see how that plays out as demand tightens.”

Easing exploration

Jeremy Javidi calls himself an “intermediate to long-term bull on oil prices looking out past a couple of years.” Javidi serves as lead portfolio manager of Columbia Management’s Small Cap Value Fund I in Boston, which he has co-managed for over 10 years.

One factor for Javidi’s bullish stance on oil is the industry’s recent dismal exploration results, which ultimately foreshadow a supply shortfall. Javidi cited Wood Mackenzie data indicating that 2015 exploration activity resulted in the least reserves found since 1947. This year’s results are expected to be even worse, and 2017 is shaping up to be lackluster, too, based on likely budget levels, he noted.

Another positive for energy stocks is that capital markets have been “wide open for oil and gas this year.” This has allowed the industry “to use mainly equity to fund acreage acquisitions, and then they fund drilling primarily out of cash flow to grow their production. That’s a lot healthier than in the last couple of years, when it was driven largely by the lowcost debt available to it,” he said.

“You never want to waste a crisis,” he added. “Using equity to buy attractive, adjacent properties at near the low of the cycle is a valid allocation of capital. That’s a story a lot of investors can get behind.”

With the downdraft in crude early this year, Javidi repositioned his fund so that it owned E&Ps with core acreage: Callon Petroleum Co. in the Midland Basin, Rice Energy Inc. in the Marcellus/Utica, and WPX Energy Inc. in the Delaware. The fund was able to establish the positions with a “single-digit” cost basis.

Since then, Rice Energy has been sold because its market capitalization increased beyond the fund’s mandate. In addition, the fund has several industrial sector holdings that stand to benefit from not only a recovery in activity in oil and gas, but also proprietary advances in technology.

hese include: Dynamic Materials Corp., which makes “shaped charges” and other components used in perforating gun systems; Flotek Industries Inc., whose nanofluids have provided an uplift in EUR in Permian wells; and Timken Steel, which makes seamless mechanical tubing for drillpipes. In large part, these non-traditional investments reflect an ongoing trend to harness new technologies to attain rising recovery factors and, in turn, achieve the lowest cost production, according to Javidi.

Further, near-term upside is more favorable with these investments than with traditional oilfield service plays, such as land drillers, where ample capacity exists even if the oil rig count rises by 130 rigs to hold production flat in 2017, he said. At the end of the day, the outcome facing the industry will depend heavily on the responsiveness of the unconventional sector.

But do observers overestimate its flexibility and underestimate its dependence on third parties?

“I don’t think it’s a question of resource,” said Fidelity’s Davis. “To me, the question as to the sector’s ability to grow in a meaningful fashion relates to, ‘Can it happen efficiently?’ When you’ve had a collapse in the rig count, you’ve lowered the head count, and you’ve laid up a lot of equipment, it’s unclear whether—as the sector ramps from 450 oil rigs to, say, 700 rigs—you lose more of these efficiencies than I expect.

“We’re making a lot of assumptions on this industry getting back on its feet in relatively short order. But do we get congestion in hiring people? Do we get congestion in rebuilding the supply chain? We just don’t know until it happens whether it’s going to happen smoothly or not. No one knows for certain.”

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