Setting goals each year can sometimes evoke the Sisyphean image of rolling a massive boulder uphill. Ahead lies the challenge, once again, but this time the hill may be steeper, or the path more tortuous, and the potholes more numerous and dangerous.

But with the US industry transitioning to what some call “hydrocarbon manufacturing,”

Oil and Gas Investor asked key players—CEOs and thought leaders at energy-focused think tanks—to step a little farther back and reassess the terrain ahead of them.

What are the “Big Issues” facing the industry, both positive and negative, in the coming year or two? And how would companies position themselves to best exploit upcoming opportunities and deal with expected challenges?

Not surprisingly, responses encompassed a broad spectrum of views. For some, the focus is firmly on execution and the need to maximize drilling and completion efficiencies. Another view is decidedly bearish on oil, warning of a loosening in worldwide supplies coinciding with a potential end to sanctions and strife-driven shut-ins of production. There are gas bulls and bears. The oft-overlooked need for marketing muscle, in addition to traditional E&P strengths, is another subject.

One thread—not always spoken—connecting many discussions is how the drive for ever greater efficiencies in ever expanding “manufacturing mode” operations can act as something of a two-edged sword for US producers. In the US, rising output is such that 2014 and 2015 are widely forecast to deliver a second and third year of production gains of 1- to 1.1 million barrels of oil per day. In its early days, resurgent US production was more easily absorbed as OPEC volumes fell short of expectations.

But continued visibility of US supply opens up a Pandora's box of other questions. What if the Nymex futures prices are correct, and we are headed toward $85 per barrel based on the West Texas Intermediate (WTI) strip for 2015, and then $80 for 2016?Many US E&Ps use hedging strategies to protect their capex programs, with close to 50% of 2014 production hedged at $94.23 per barrel, according to a Simmons & Co. International survey of firms in its E&P coverage. But as hedges are rolled forward, how much protection will they afford, if the futures strip is correct?

Geopolitically, of course, there are many uncertainties that could also affect pressure on oil prices. Taking just a few: Will Iran gain a fuller reprieve from international sanctions after an initial six-month relaxation of measures is concluded; and will Libya put more barrels on the market if and when internal strife is resolved? And what of prospects for quelling increasing conflicts in Iraq? And disruptions in Nigeria? And South Sudan? The list goes on.

And how does all this unfold if burgeoning US production forces a reexamination of antiquated laws banning the export of US crude oil—a debate that has picked up surprising speed, even though policy changes are considered by many to be, at best, a late 2014 or subsequent event. This would obviously help narrow the divergent course between WTI and Brent crude prices.

2014—a year of operational efficiency

Now that the land grab for unconventional resources is complete, operators are turning their attention to development programs and maximizing returns on investment. However, their ability to reduce costs, while simultaneously increasing production and recoveries, will define those that succeed and those that don't, according to Apache Corp. chief executive Steve Farris.

“An awful lot of money is chasing these ideas, and unless you can execute on the operational side, sooner or later you'll go broke,” Farris says. “There are going to be real winners and losers.”

Farris believes the most pressing issue for the industry is to decipher how to wring more production out of each well drilled. “We're drilling a tremendous amount of horizontal wells, and the real question is, how do we get 10% more EUR [estimated ultimate recovery]? You're leveraging your capital across billions of dollars being spent.”

While that statement may present a picture of the industry in its entirety looking to fund shale development, Apache itself serves as an example. In 2013, Apache spent some $4.3 billion in the Permian and Anadarko basins, where together the company controls 2.6 million net acres and 9.2 billion barrels of net resources. It estimates it has approximately 67,000 drilling locations onshore US before further downspacing.

Execution is the key: not every shale well drilled will be economic, he notes, and costs will continue to squeeze returns.

“You're going to end up with folks that can do it and folks that can't,” says Farris. “You get production out of every shale well you drill, but only if you can do it economically over a long period will those be the winners. If there is anybody that can execute in the kind of plays that we're executing in North American onshore, it's somebody that gets costs down and production up. Put us in that briarpatch.”

Devon Energy chief executive John Richels agrees. “One theme moving forward will be the ability to develop these resources as efficiently as we can—and there is going to be some differentiation between companies.”

The industry has effectively mapped out the most prospective areas for oil and natural gas in the US, he says, and the challenge to the industry now is to be able to drill hundreds or thousands of wells quickly, safely, at low cost and while respecting the environment.

With the advent of unconventional resources, the industry is in a high-cost setting, he says. “That's why focusing internally on how to do things best, the fastest and most efficiently while at the same time doing it safely and with respect for the communities we operate in are the things that give a competitive advantage to certain companies.”

Devon is high-grading its portfolio by focusing in five high-growth areas that “can move the needle,” including a new acquisition in the heart of the Eagle Ford shale. “We're not chasing production,” says Richels, and notes controlling costs of existing opportunities through scale and efficiencies trumps capturing new resources.

“We're investing in practices that will increase our margins and cash flow, because returns ultimately will make us successful.”

Jeff Ventura, CEO of Range Resources, is positioning his company to focus on returns. “This year and beyond, one of the real keys will be companies that can consistently execute and perform well.”

In recent years, he says, share price was driven by companies that could drill and demonstrate horizontal opportunities in new plays. “At this point, for the most part, people know where the plays are and what the potential is.” Companies that can consistently drive up production, reserves and cash flow per share will move to the top. “You have to have acreage in the core of the play, and you have to be able to consistently execute.”

The company has approximately 1 million net acres in the Marcellus—which with stacked pay “is more like 2 million net acres”—including 530,000 net acres that are in the “core” southwestern Pennsylvania part of the play. Range says the greatest estimates of “hydrocarbon in place” in the basin occur in the latter area, with Marcellus, Utica/Point Pleasant and Upper Devonian all prospective.

Pressure on prices

With the upswing in American crude production, won't successive years of 1 million barrels a day of annual US production growth—spurred by E&Ps' combination of aggressive volume growth and relentless efficiency gains—result in incremental oil supply and put pressure on world markets?

For Leonardo Maugeri, a senior associate at Harvard University's Belfer Center for Science and International Affairs and chairman of Iron-bark Investments LLC, the recent march higher in US unconventional production is likely to bring to a head an oil and gas “spending spree” that began in 2003 and has “skyrocketed” from 2010 on. He sees oil prices going lower, and thinks the recent WTI futures strip does not adequately reflect downside risks.

Maugeri, who served with Italian integrated Eni SpA as senior executive vice president of strategies and development, expects “the second half of 2014 will probably represent a key test of oil prices' ability to withstand the growing pressure from excess oil capacity.”

Global production is “growing much faster than demand,” says Maugeri, with year-end 2013 capacity estimated to approach 99 million barrels per day, including biofuels, condensate and natural gas liquids (NGLs). Of this, about 6 million barrels a day is untapped, due to geopolitical factors as well as action by Saudi Arabia in its role as a swing supplier. Global production is estimated to be at a little more than 93 million daily barrels, while demand is estimated at about 91 million, says Maugeri.

In terms of incremental supplies potentially coming onto world markets and pressuring oil prices, Maugeri points to Iran's interim six-month agreement with the Group 5+1 countries, initially allowing some relaxation of sanctions.

“If at the end of the six-month agreement, Iran respects the conditions indicated by the international community, Iran could probably start exporting all the oil it's capable of producing. Maybe this takes time, but it means more than 1 million barrels a day could come back onto international markets,” says Maugeri, estimating a rise in Iranian export volumes to 2.7 million barrels from around 1.5 million barrels a day.

If conflicts besetting Libya were to be resolved, a similar ramp in exports could occur, with Libyan exports potentially reaching 1.6 million barrels, up from around 500,000 barrels per day recently, continues Maugeri. In total, he estimates politically and militarily driven tensions have taken some 3 million barrels off world markets from producers in Iran, Libya, Nigeria, Sudan and other countries.

“With 99 million barrels per day of capacity and demand of around 91 million barrels per day, the imbalance will sooner or later affect oil prices, unless there are major political crises again resulting in production shocks and new disruptions.”

But won't Saudi Arabia act in its traditional role as swing supplier?

“There is a limit to the ability of Saudi Arabia to act as swing supplier for the whole world,” says Maugeri. If Iran and Libya cite historical issues for resuming full production levels, “I don't think the problem of overcapacity can be solved just by Saudi Arabia.”

He estimates that Saudi production has been running at somewhat more than 9 million barrels, down from 10 million per day this past autumn. “Saudi Arabia will likely never accept a production cut to less than 8 million barrels per day,” he says.

Maugeri's bearish tone stems from his view that the spending spree begun by the majors in 2003 has accelerated, as shale oil producers ramped operations, to the tune of $2.4 trillion in pure upstream expenditures in the four years from 2010 to 2013. Current oil capacity reflects in part the earlier investments, with the latter investments yet to be fully felt.

A combination of hedging strategies and the ability to continue to drive down costs makes Maugeri believe shale oil companies are unlikely to take their feet off the gas pedal if oil price begin to falter. “Shale oil companies, in particular, are heavily hedged, much of it at prices over $90 per barrel,” he says. And with economic breakevens varying from $40 to $80, depending on the play, much of it can be produced at more than $60 per barrel, he says.

With many oil producers having already put in place hedges to protect their cash flows and lock in economics, does the forward oil curve already reflect the risk of a drop in WTI toward $80 a barrel over the next several years?

“I don't think the oil futures fully reflect the risk that is in the market, because the sentiment among many analysts is that there are so many potential disruptions in supply due to political factors,” he says. “The problem is that when there are changes in perception, generally it's too late, and the market tends to overshoot.”

Choose crude, nonetheless

Concern over the oil outlook seems to be treated somewhat more routinely by E&Ps themselves.

“As an industry, we are concerned about oil prices,” says Apache's Farris, quickly adding: “I don't necessarily share that outlook; I'm not nearly as bearish. In any case, we run our long-term project economics on a pretty conservative price at Apache. We use $85 per barrel flat forever.”

Chip Johnson, president and chief executive of Carrizo Oil & Gas, also isn't ringing the alarm bells.

“To me, in a 90-million-barrel-per-day world, there's no huge threat that we're going to be greatly oversupplied with oil,” he says. “There's a contingent that always says we'll straighten out these political problems, and you'll have Iran and Libya and South Sudan all come back on line.

“But then you have the Energy Information Agency talking about constant growth in demand. China has slowed down a little but is still adding demand each year, and so are a lot of other developing countries.”

As far as oil futures' reliability as a forecasting tool, Johnson expresses skepticism.

“If you look out a year on the futures, it says $85 a barrel. But if you look back to where the futures said we were supposed to be today, it was supposed to be $85, and now it's $93,” he says. “It's been that way for a couple of years. The futures curve has been backwardated, and it hasn't come true. Oil tends to rise out of the backwardation, and gas seems to drop from the contango.”

And in terms of setting his company's strategy, Johnson has little doubt about choosing crude oil.

“Our biggest theme is to stay as crude-focused as we can, and as far away from natural gas and natural gas liquids [NGLs] as we can,” he says, interviewed in mid-January. “There's a methane glut, and now there is an ethane glut. We'd rather take our chances with oil. I have a lot more faith we can transport oil around and make adjustments as part of a bigger international market than we can with our constraints on natural gas—at least until 2017-2018, when we can start exporting LNG.”

Little hope for a gas spike

Does that translate into a progressively more bullish view of natural gas as 2017-2018 draws closer, bringing with it new sources of demand: gas-fired power generation in place of coal, petrochemical and other industrial demand, and rising exports of natural gas to Mexico and as LNG?

“The gas bulls will tell you that all these new sources are going to begin and run up demand. I don't know if they will or not; but I do know how easy it is to add supply,” says Johnson. “If you look at the Marcellus and Haynesville, and you look at the number of locations that just one company like Chesapeake can drill, it's an awesome amount of gas.

“We already know where the gassy Eagle Ford is. Now we're figuring out where the gassy Permian is. And the Utica looks like it could have the biggest dry-gas wells in the country, and they sit on top of the Rockies Express pipeline. It's just hard for me to believe we can't add gas in a hurry. We keep adding pipes to move all this gas around, but what we need are more burner tips.”

“We've got an awful lot of gas,” echoes Farris. He cites Apache's own assets in the Horn River and Liard basins in Canada as potential gas supply awaiting future demand. The Liard could have 50 trillion cubic feet (Tcf) of reserves, he estimates, “and the minute we get to where we could make a lot of money up there, we could have a couple of Bcf (billion cubic feet) per day coming out of those fields.”

So what's Farris' natural gas price forecast for the next 12 to 18 months? He offers a wide range, $3 to $5.50. “And $5.50 is stretching it.”

Robert Bryce, senior fellow at the New York-based Manhattan Institute for Policy Research, offers a more expansive view of natural gas, colored by what he calls the “war on coal” being waged by the Obama administration, which buoys prospects for gas but may risk upsetting the balance in fuel choices available to the power industry.

In essence, Bryce argues that new regulations are driving power generation away from coal—of which the US enjoys a “super abundance”—to the point that the only fuel option available to it near term is natural gas. He cites projected increases in demand related to power alone of 3.2- to 5.6 Bcf per day by 2020, according to Simmons & Co., with demand increases from all sources potentially reaching 12- to 20 Bcf per day.

Could the pendulum swing too far in one direction?

“As pro-natural gas as I am,” says Bryce, “my fear is that we're putting all our eggs in the natural gas basket, and that could lead to shortages and price spikes. Those outcomes would not be beneficial to natural gas producers over the long term.”

For Ventura, leverage to natural gas and NGLs has been part of Range Resources' makeup for many years. His instincts are that projections for new gas demand by 2020 of 12- to 20 Bcf per day from all sources will gravitate toward the high end of that range. If so, what is his outlook for gas?

“With markets being forward looking, I think gas in a $4 to $5 world is where we'll be in the next few years,” he says. “We're a low-cost producer, and I think we'll do well anywhere in that range.”

Markets for NGLs

Another key attribute—often overlooked—is having a “very good marketing team,” says Ventura, who notes its increasing importance to Range as production has grown in dry, wet and “super-rich” areas and has brought with it varying amounts of NGLs: ethane, propane, butane, etc.

“There's been so many hydrocarbons found on the gas side, and now on the oil side, that it's important not only to execute on production plans, but also to move it to market and get a fair price for it.”

Nowhere has this been more evident than in Range's early-mover prowess in finding markets for its NGLs—at good prices. This has proven particularly far-sighted as regards ethane in light of recent weak ethane market conditions, in which peers have tended to simply leave ethane in the gas stream. An alternative midstream proposal reportedly involves making ethane simply “go away” by processing it at no cost—but no revenue—which would allow companies to keep wells flowing, meet pipeline specifications and continue to strip out higher-value NGLs.

Range's head start in NGL marketing has led to 15-year contracts covering three ethane shipments to industrial users. One is for 15,000 barrels a day of ethane via the Mariner West pipeline to Nova Chemicals in Sarnia, Ontario. The second is for 20,000 barrels per day via the ATEX pipeline to Gulf Coast buyers. The third contract is via the Mariner East pipeline and then tankers to Ineos Group Holdings in Europe for 20,000 barrels per day. The Mariner East pipeline arrangement also includes 20,000 barrels per day of propane deliveries to Pennsylvania's Marcus Hook harbor that can be marketed to the Northeast US or exported, as Range has for the past year in partnership with MarkWest Energy and Sunoco Logistics. Deliveries on the first two ethane projects began late last year, while overseas shipments to Ineos are scheduled for 2015.

Prices embedded in Range's portfolio of ethane contracts will translate to about $4.70 per thousand cubic feet equivalent (Mcfe) of gas, based on recent indices, according to Ventura. Also, in extracting ethane, there is additional propane recovery, adding a further $0.50 to 0.60 per Mcfe, taking a realized price projection to $5.20 to $5.30 per Mcfe. Importantly, the initial ethane contracts, coupled with subsequent condensate and propane contracts, “have cleared a path allowing Range to produce more than 3 Bcfe per day net from the Marcellus alone.”

Several well-known Gulf Coast ethylene cracker projects are due to start up, mainly in 2017. But are there other sources of demand for ethane that Range and others can tap into?

“I think there's room for expansion and growth,” says Ventura. “But if we never replicate it, it's been a great deal for us and a great deal for the companies we work with. It's a win-win for both sides.”

Range's marketing team has had equally impressive results marketing the company's natural gas. In addition to marketing gas in the Northeast, in 2013 Range added 25 new customers in the South, Southeast, Mid-Atlantic and Midwest with firm transportation and sales, and hedged price and basis. Range has created a strong portfolio by tying the sales price of its gas to about nine different indices.

Federal overreach

In his State of the Union address in late January, President Obama lauded that the US is closer to energy independence today than it has been in decades, giving a nod to booming oil and gas production and the jobs it has created. But in the same discussion, he also criticized the industry.

Referring to gains in the solar power market, he said, “Let's continue that with a smarter tax policy that stops giving $4 billion a year to fossil fuel industries that don't need it, so that we can invest more in fuels of the future that do.”

Federal overreach into the oil and gas industry has been an ongoing concern under the Obama administration, and continues to be, says Devon's Richels. Particularly worrisome, he says, is the threat of changing the deductibility of intangible drilling costs, or IDCs, which the president alluded to in his speech.

“This industry requires a huge amount of capital that needs to be reinvested every year in order to not only replace the decline in our reserves, but to add new reserves,” says Richels.

Intangible drilling costs are anything but intangible, he emphasizes, and include the ordinary costs of drilling and completing wells. These costs are currently tax deductible in the year incurred, as they are with other industries. Proposed rules would have them amortized over years, carving off about 20% of current cash flows, he estimates.

“That puts a capital-intensive business like ours at a disadvantage, and would reduce the amount of funding available for reinvestment for developing these terrific resources. We have to be vigilant to make sure our policymakers understand that.”

Another political hot topic is the industry's practice of hydraulically fracturing wells in unconventional plays. Fear-mongering has made the decades-old practice target No. 1 among anti-industry activists, who are having some success in selling their message to the general populace. While the industry believes it has history and factual data on its side, the risk remains that the federal government could step in to add an extra layer of costly and time-consuming regulation in the path of resource development.

Says Richels, “I believe strongly that the states are the right governmental body to have jurisdiction over this. They've been doing it a long time, and topography and geology change from state to state.

“To put another layer of regulation over hydraulic fracturing at the federal level where rules have broad applicability rather than being tailored to a certain area is adding a duplication of regulation that will do nothing to add to quality, and will do a lot to add costs and delays without any positive outcome.”

Rather than a uniform approach, discussions continue to put in place regulations for hydraulic stimulation on federal and tribal lands. “We avoid federal leases at all costs,” Carrizo's Johnson says.

Although producing states such as Texas, Oklahoma, Louisiana and New Mexico have grown experienced with the proper balance of regulations for the oil and gas industry, emerging unconventional plays are forcing other states to catch up, and the residents are not necessarily comfortable with what the industry considers common practices.

Northeastern states such as Pennsylvania and Ohio are prime examples, where regulatory bodies are working overtime to update policies as the industry has lighted en masse within their borders.

“That's one of the reasons we shied away from that part of the US,” says Apache's Farris. “Not because there wasn't oil and gas there, but there are fewer [established] regulations as to how to do business with the state or the community.” Apache's portfolio is weighted in the Permian and Anadarko basins, traditionally industry-friendly regions.

The tide may have turned in the industry's favor, however. Farris says industry transparency on well-completion procedures has gone a long way toward making the public and policymakers comfortable with industry practices.

Rail safety—is it enough?

With sometimes slow development of traditional pipeline infrastructure, significant inroads have been made in transporting oil by rail, helped by the relatively greater flexibility and optionality that rail often offers shippers.

Rail offtake has proved a saving grace for tight-oil explorers waiting on pipe, and Bakken shale producers in particular, but recent high-profile rail accidents resulting in fiery crude explosions and spills have officials at federal, state and local levels concerned about safety. Producers in these plays should be concerned as well, says the Manhattan Institute's Bryce.

“If new rules were promulgated that require different designs for tank cars, then that could slow the oil-by-rail trend,” he warns. Five major accidents in recent months have tarnished the crude-by-rail practice, eliciting fear from those who live near tracks. The culprit in these explosions is older tank cars prone to puncture, but also mislabeling. The volatility of the Bakken shale crude that erupted following a derailment in Lac-Megantic, Quebec, largely destroying the town center, caught officials by surprise due to it being mislabeled. In response to these accidents, US Transportation Secretary Anthony Foxx has promised tougher federal standards for tank cars. In January, he launched a Call to Action between the rail and oil and gas industries for proposals to enhance safety. “There is a spotlight on the industry with regard to safety,” says Bryce. “If there are restrictions on movement—in particular out of the Bakken—then we may well see a lack of offtake capacity that would force some producers to shut down their wells or perhaps be forced to use higher-cost transport options like trucking.” Like with the airline or nuclear industries, “any accident is one too many. From the wellhead to the burner tip, there has to be an unrelenting focus on safety. That's just part of the deal,” he says.

A North American marketplace?

Bruce Bullock, director of the Maguire Energy Institute at Southern Methodist University in Dallas, envisions a North American common marketplace for hydrocarbons, with the Keystone Pipeline the first common link. “Sooner or later we're going to have to integrate between the US, Mexico and Canada,” he says. “Look at the Eagle Ford shale; the geology doesn't stop at the Mexican border, but the wells do. There is no reason additional infrastructure can't be built and shared there.” Canada, too, is an important ally. “We already trade crude with Canada, and export crude into eastern Canada. It's a relationship we want to maintain. The Keystone Pipeline, while somewhat symbolic, is an important first step at integrating.” He doesn't expect any decisions regarding the Keystone until after the 2014 elections. “In 10 years we're going to have an integrated North American infrastructure and industry. It will benefit all US producers because we have the capital and we have the expertise.” Devon's Richels emphasizes the importance of ties that bind with our northern neighbor via the Keystone. “The opposition to Keystone is to keep the oil sands in Canada from being deveoped, but that development is going to happen. It's just a question of where that oil is going to go. Will we get oil from our biggest trading partner—our best friend? Or from other places around the world while our neighbor ships theirs to other countries? There's a certain lack of logic to me for that to occur.”