A measure of optimism is traditionally conveyed as being whether a glass is viewed as half empty or half full.For the oil and gas industry, the coming year is colored by legitimate concerns—the commodity outlook as indicated by the oil futures strip, the risk of regulatory reform, and more—but the glass of opportunities is hardly being drained.Indeed, if overall E&P fortunes are being assessed, the ancient saying, “my cup runneth over,” is closer to the mark.

For one, several E&Ps that were early into the best resource plays are approaching what is commonly called “manufacturing mode.” The time when they will be able to generate free cash flow (that is, cash flow beyond their capex needs) is near.Meanwhile, another set of E&Ps in less mature basins is draining their cash.But often, this is because their cup of geologic opportunities has been re-molded into something much larger—maybe a bowl—in which the opportunity set and optimal capex have also spiraled higher.

For the former, the onset of free cash flow typically begins several years into a resource play, after acreage is held by production, infrastructure has been put in place, and the transition to pad drilling is under way.The challenge becomes optimization of drilling and completion practices and, in turn, the maximization of cash flow, raising questions about uses of cash.After capex has been set, does it make sense to use cash to lower debt?Introduce or raise a dividend?Repurchase shares?

For those E&Ps in less mature plays, and perhaps in less control of their own destiny, fortunes may depend on how obliging the capital markets may be—and here the signs have turned markedly more favorable as 2013 draws to a close.With multiple stacked pays, and talk of the effect of “acreage multipliers,” E&Ps with promising prospects have been able to access capital markets as they seek to de-risk the dramatically growing, but as yet undefined, resource potential of their properties.

But whether it is organically generated cash flow, or cash raised from open capital markets, E&Ps' financial flexibility does not immunize them to countervailing forces.And so, taking a broader view of the landscape, what lies ahead for the industry in 2014?

Tom Petrie, an industry veteran and chairman of Petrie Partners LLC, Denver, provides a balance of pros and cons facing the industry.In the latter category, he points to the likelihood of “somewhat limited” growth in oil demand in light of a far from robust economic backdrop and geopolitical concerns pushing recent prices for oil over $100 per barrel.

“I would not be surprised to see headwinds in the final demand for oil,” he says.Even with continued progress in backing out crude oil imports, the industry likely faces “challenges in how we accommodate all the new supply.” This is already reflected in the downward slope of futures prices for oil, he points out.“That backwardation of the forward curve is real.”

On the positive side, the “industry has never been as healthy as it is now,” observes Petrie.Costs of capital are “very manageable,” and the industry is well positioned to weather commodity price weakness if it materializes.Moreover, with the land grab largely over and acreage mostly held by production, “the structural requirement for the industry to overspend is diminishing.”

And although the atmosphere in Washington is polarizing, regulatory issues are unlikely to become an overwhelming negative to the point of tripping up the private sector.

“The transformational nature of unconventional resources is too big to be stopped,” Petrie says.

Toward free cash flow

Bill Marko, managing director at Jefferies & Co., points to several trends he sees unfolding in the wake of the sweeping unconventional resource play phenomenon.

One is the rationalization of assets by companies that stepped up with gusto to the unconventional resource table and are still trying to digest—sometimes with discomfort—all that they ordered.Of late, he notes, buyers often have a better understanding of what constitutes their core acreage, and have marked for sale other assets that can be turned into cash to fund drilling of the core.

“We've gone from speed of accumulation of assets to now a more efficient harvesting of assets,” says Marko.“What I see for next year is more coring up of assets, where companies look at what they own and decide if it is core or noncore, based on their strengths and the qual-

ity of the rocks.A lot of companies need to raise money for drilling, and they certainly need to sell assets to clean up their portfolios.”

After a slow 2013 in acquisitions and divestitures in which transaction values may reach only half the annual run rate of the past several years—roughly $100 billion—Marko suggests asset rationalizations will provide a spark to the property market.With several large-cap E&Ps anticipated to follow moves by Chesapeake Energy Corp. to shed properties, “it feels like everybody could come to market around the same time.I think next year could be a super-active year.”

But in what is acknowledged to have been a buyer's market for properties, with a few exceptions, who would be the likely acquirers?

“The most interesting buyer group would be the big private-equity sponsors,” says Marko, naming a handful of players—among others, Apollo Global Management, Blackstone Group and KKR—with the wherewithal to make billion-dollar commitments to buy assets and build a company.And paving the way is Apollo, he says, with its acquisition of EP Energy Corp. (owner of the upstream assets previously held by El Paso Corp.), which filed to go public in September.

Another theme is the emergence of free cash flow among the ranks of independent E&Ps who are entering the third year or more of an unconventional play, Marko says.

“It's starting to happen with a lot of the companies that are in the sweet spots of core plays,” says Marko.“And it's good news for the industry, because before, we always put so much money back into the ground looking for the next field.Now, we know the resource is in place, and it's more a matter of developing the field, and doing it as efficiently as possible.”

In the Marcellus, free cash flow is perhaps mostly closely associated with Cabot Oil & Gas Corp. The company not only grows production by above-average industry rates—40% for 2014 at the midpoint of guidance—but simultaneously generates substantial free cash flow.Using consensus estimates of 2014 capex and cash flow, the company's website recently showed an implied free-cash-flow estimate of $278 million for next year.Earlier this year, before issues impacting Marcellus pricing differentials, the 2014 free-cash-flow estimate was almost $100 million higher.

In the Denver-Julesburg Basin's Niobrara play, Anadarko Petroleum Corp. is generating free cash flow, driven by the 100% pretax rates of return on its wells and its mineral ownership advantage from the railroad land grant.Noble Energy Inc. also expects to be cash-flow positive in the basin starting next year, and estimated at its 2012 analyst day meeting that its operations in the Niobrara would generate $2.4 billion of free cash flow for the five-year period through 2017.This represented a 59% increase from its prior-year estimate.

Other examples include EOG Resources Inc., with major plays in the Bakken and Eagle Ford, which is expected to be generating free cash flow for the first time next year.Marathon Oil Corp. generates significant free cash flow, helped by the ramp in its Eagle Ford operations, while small-cap Aurora Oil & Gas Ltd. expects to be cash-flow positive on its Sugarkane Field in the Eagle Ford near the end of 2014, assuming commodity prices stay around current levels and a drilling program similar to 2013.

In the Permian Basin, where Pioneer Natural Resources Co. has had a leadership role, the company expects to spend most of 2014 in de-risking its acreage in the northern Midland Basin.With full development plans due to be in place by 2015, and payout on wells in eight to 12 months, it expects to be generating free cash flow in its northern operations in two to three

years.In its southern Midland Basin operations, where the company has a joint venture with Sinochem Petroleum, Pioneer expects to have completed drilling to hold acreage by the end of 2013.Its operations in the south are already cash-flow positive, benefiting from a “drilling carry” as part of the joint-venture terms, under which Sinochem funds 75% of Pioneer's portion of drilling and facilities costs up to a specified limit.

When Evan Calio, managing director with Morgan Stanley, looks at the US E&P sector's opportunity set, combining visible drilling inventory with nascent free cash flow, he likens it to “haves and have-mores.”

“We believe that the drilling inventory, the visibility of growth, and the visibility of positive-free-cash-flow inflection as you move through the development of unconventional plays have never been greater among the US E&Ps,” he says.

“If we assume there is two million barrels of production growth over the next four to five years—largely in line with consensus views, assuming an accommodating commodity price—there is almost $300 billion of additional market capitalization that would support that production growth,” he says.(This is based on two million barrels per day, multiplied by a $60-per-barrel cash margin, times 365 days per year, valued at a six multiple of cash margin, to total approximately $262 billion.)

“That is essentially the prize for North America,” he says.“We think the lion's share of the US resource to support that growth has been claimed.A lot of the companies that will capture more of the prize have ring-fenced the acreage to support that growth.We look at those as the resource 'have-mores,' and they're also the companies that have beaten analyst expectations consistently.We see those as the big winners, because these multibasin, large-cap players have not re-rated like their single-basin, mid-cap peers.” Among his favorites: Anadarko Petroleum, EOG Resources and Noble Energy.

What obscured the trend of more E&Ps becoming free-cash-flow inflective until now?

In 2012, capex levels and finding costs rose dramatically due to the inefficiencies of drilling to hold acreage and increasing infrastructure costs.Since then, capital efficiency has improved, as infrastructure investments have been monetized relatively easily, and drilling costs have declined as companies move to pad drilling and refocus on sweet spots in plays.

“That changes the free-cash-flow profile of the industry,” says Calio.And with the US offering lower geopolitical risk than other countries, highly visible growth prospects, and having progressed part way through “the painful capex spend period,” the US E&P sector is—subject to the usual caveat of commodity prices holding up—“the best place in the world to be.”

On the mergers and acquistions front, however, Calio does not foresee acquisitions by the integrateds or large international operators.

“I don't think it's going to be one of the majors or someone from Europe,” he says.“Everyone has been forecasting this gigantic wave of M&A.I think it's a couple of years down the road and that it's going to come from within.

“It's going to be when one of the bigger guys trading at higher multiples, with deeper inventories, buys out people with smaller acreage positions who can see their production topping out.The natural acquirer in that basin is going to be the higher-multiple guy, as with master limited partnerships (MLPs).That's the natural consolidation.”

De-risking stacked pays

Commanding today's spotlight, however, is the push to de-risk multistacked pays in less mature basins—at least in terms of horizontal development—with greatest attention focused on the Permian Basin and, to a lesser extent, Ohio's Utica shale.

The Permian, with roughly 3,500 feet of potential stacked pay, holds a natural advantage over other basins that boast only a few hundred feet.It is here that Calio and other analysts expect to see the biggest delta in 2014 in terms of drilling to support E&P valuations after the dramatic upward moves in Permian players' stocks in third-quarter 2013.

As better well construction and completion design helped improve estimated ultimate recoveries (EURs) for Permian producers, and raised confidence in testing more than just a single primary interval of the multistacked pays, the focus turned to “the potential value of the whole layer cake,” recalls Calio.“The story is inventory.Inventories exploded.”

Companies' progress in de-risking resource potential helped the E&P sector handily outperform the broader market in the third quarter, notes Dave Kistler, managing director and co-head of E&P research at Simmons & Co. International.Compared to a 4.7% gain by the S&P 500, the EPX (SIG Oil Exploration & Production Index) was up 15.6%, while Simmons' Oil Weighted Equity Index gained as much as 26%.

While West Texas Intermediate (WTI) prices of $105.55 per barrel also helped performance, Kistler says that “if you look at what's been working in the E&P space, the best-performing companies have been those that are able to de-risk resource.They're getting significant

amounts of credit from analysts and very strong performance associated with de-risking these multistacked-pay intervals.”

He points to what the industry sometimes calls the “acreage-multiplier” effect of having multistacked pays—in this case, in the Midland Basin, where potential pay zones exist in the Wolfcamp A, B and D, plus Jo Mill and middle and lower Spraberry.

“If you look at a company like Pioneer Natural Resources, with 800,000 acres exposed to potentially six zones in the Midland Basin, you have the capacity to have potentially 30,000 viable drilling locations on 160-acre spacing,” he says.“And if each of those wells costs $7 million, that's $210 billion of capital that you would need to extract all those hydrocarbons.Now, you are not going to spend $210 billion right away, but you do want to de-risk that inventory and get credit for the fact that they hold all that resource in inventory.”

Kistler acknowledges that earlier in 2013, against a weaker commodity backdrop, “there was definitely a move to greater capital discipline, to a commentary on a return of capital to investors, and dividends being boosted.”

Has the market now switched to rewarding spending to de-risk resources?

“If E&Ps de-risk that resource potential, analysts have a tendency to start extrapolating that into their models and driving up the net asset value of the company.In order to retain the value of that extrapolation, you have to at least prove up that acreage conceptually.You might not be getting your best economic return on an individual well, but you're de-risking a significant amount of inventory.And the stocks are getting credit for de-risking resource, not for near-term return of capital.

“But, to be clear, it's de-risking what I would argue is a high-rate-of-return asset,” he says.“It's not go spend capital anywhere.It's go spend in areas like the Permian that arguably could be economic down to $60 to $65 oil at the wellhead.These are high-margin basins with prolific, multistacked pay zones.”

Due to the third-quarter strength in equities continuing into October, Kistler says the firm's coverage universe has less-than-normal upside to its average NAV-based target price.As of mid-October, average upside for the group was less than 20%, as compared to 30% typically, and 40% to 50% when valuations are at their most attractive.However, this was based on a terminal price for oil of $86 per barrel, starting in 2016.If a more bullish oil price assumption is taken than is reflected in the forward commodity curve for oil, and terminal oil prices were set at $90, $100 and $110 per barrel, average upside would be 29%, 69% and 109%, respectively.

In terms of individual names—and reflecting a “less offensive posture”—Kistler prefers E&Ps like Anadarko Petroleum, EOG Resources and Noble Energy.In addition, one name offering “excellent value” with “solid near-term catalysts” is Newfield Exploration Co.

Kistler highlights emerging free cash flow from the Niobrara as one reason he likes Noble Energy.“The Niobrara represents 35% of their production, growing at 20% year over year, and is expected to be free-cash-flow positive by 2014.So, it's a self-sustaining asset that can increase activity as cash flow increases, and it's a very high rate-of-return asset for them.”

Simmons expects the trend to outspend discretionary cash flow—but by a narrowing margin—to continue for its E&P coverage group.For 2014, the company forecasts drillbit capex to rise by 8%, representing a drillbit reinvestment ratio (drillbit capex as a percent of discretionary cash flow) of just 101%.This is down from a drillbit reinvestment ratio of an estimated 108% in 2013 and more than 120% in 2012.If future revisions are made, however, the bias is expected to be toward a somewhat higher drillbit reinvestment ratio, more in line with 2013 levels.

Receptive markets

As for capital access, the coming year should see a more receptive market for C-Corp offerings—including a heightened appetite for initial public offerings in the energy sector—as well as continued opportunity for MLPs to tap the equity market on a broad scale, says Tim Perry, head of oil and natural gas investment banking in the Americas for Credit Suisse Group.

“We expect to see additional IPOs in the US,” says Perry, noting the success of Antero Resources' public offering in October that raised more than $1.5 billion, net to the company, and evidenced renewed interest in oil and gas from generalist funds.“I think this is going to start a wave of IPOs.We're seeing not only energy funds, but also significant generalist funds direct their investment dollars toward E&P.”

Perry sees significant capital being raised mainly for five basins: the Bakken, the Permian, the volatile oil window of the Eagle Ford, the Marcellus/Utica and the Niobrara.But the

focus is on the Permian, which already underpinned the successful completion by several E&Ps of secondary offerings in the latter half of 2013.

“A lot of the buzz on the oil side is the rebirth of the Permian,” he says, “It's pretty amazing, the amount of capital we're raising for the Permian right now, to increase production from an almost century-old basin.”

How is fundraising being received by investors?Can E&Ps go back to the well?

“The capital markets are rewarding those companies that have acreage in the right areas and are de-risking it quickly,” Perry says.

“Even though they're outspending cash flow, it doesn't mean they're trading at a lower valuation; in fact, if they're in the right basin, they tend to trade at a higher multiple.If the capital markets take an abrupt U-turn, the story could change.On the other hand, those outspending cash flow are for the most part operators, and they could just slow down their capex.”

Not surprisingly, IPOs are likely to originate “first and foremost” in the Permian, with others likely from the Marcellus and Utica in the wake of Antero's successful market debut.Its stock closed at $52.01 on its first day of trading, up from its IPO price of $44.

In the MLP sector, Perry expects to see a steady stream of issuance to include not just limited partnership but also general partner interests.As an example, he cites the IPO in October of Plains GP Holdings LP, an offering that was upsized to yield proceeds of about $2.8 billion.“We're expecting great things out of general partners of MLPs going public.”

After brief headwinds from a short-lived spike in interest rates, MLP valuations remain attractive, according to Perry, who sees no evidence of MLP issuance weakening.“Indeed, we're seeing even more interest in MLPs.We see a number of companies thinking about MLPs that haven't before, typically involving E&Ps considering dropping down a midstream asset.”

In terms of the scope of opportunity ahead for the US E&P sector, Perry references work by the Credit Suisse research group projecting an increase in US oil production to slightly more than 11 million barrels per day by 2020.Using 2012 production as a base, this represents an increase of just over 5 million per day.Valued at about $84,000 per flowing barrel, this translates to a potential addition in enterprise value of more than $420 billion.“The E&P pie is poised to get significantly larger,” conclude the Credit Suisse analysts.

David Tameron, senior analyst with Wells Fargo Securities, thinks two major trends will define 2014: greater capital efficiency, involving optimization of drilling and completion practices, and resource delineation, as in de-risking the Permian and other basins' stacked-pay potential.

At the same time, he is keeping both feet firmly on the ground: “This is still a commodity

business.”

E&Ps pursue greater capital efficiency by moving to pad drilling, drilling laterals more efficiently, and optimizing drillbits, as well as improving completion techniques.These should help companies in manufacturing mode ramp up production and cash flow and attain free cash flow.Tameron uses as an example a single rig running in a play, typically taking four years to become cash-flow positive.

“If you think about the evolution of the shale plays—in the Bakken, in the Permian and so on—over the next three to five years you're going to have these big production tails that are going to be spinning off all this free cash flow.It becomes a manufacturing process.

“Now, if you individually continue to accelerate production at that pace, that's one thing.I happen to think it's a commodity business, and if it starts working for one, it starts working for all.And then you're reminded by prices why it's a commodity business,” he says.“The nature of that just unnerves me.”

For E&Ps, the question becomes what to do with the cash at that inflection point.Do they dividend it out?Do they reinvest it?

“Historically, E&P managements have not done very well handling excess cash flow.They start taking more risks,” says Tameron.And paying dividends is somewhat rare outside some of the larger E&Ps.“Maybe the larger independents are a little different, but by and large the E&Ps are still wildcatters at heart.They love doing deals, they love building things.”

As for overall sentiment in the energy sector, “Near term, it feels a little heated,” says Tameron.“You've seen a lot of generalist money come into the sector over the last few months.”

Tameron says his favorite basins continue to be the Permian, followed by the Bakken.

“Both basins have tremendous resource in place and provide decades of drilling.As companies continue to climb the learning curve, we think there remains significant upside.This is particularly true in the Permian, which is in its infancy and has yet to be delineated.With the Permian's areal extent and its multistacked pay potential, we believe the Permian will be a dominant basin for at least the next decade.”

Under a manufacturing scenario, Tameron favors companies with a combination of best rock and/or ability to execute.A number of companies have that combination, he notes, but in the Wells Fargo universe his current outperform-rated stocks include Anadarko Petroleum, Concho Resources, Diamondback Energy, EOG Resources, Kodiak Oil & Gas and Whiting Petroleum.

Taking a longer-term view of natural gas, Tameron also likes Range Resources Corp., although it carries a market perform rating.

“Gas probably doesn't go much lower from here.If you want to take a longer-term view on gas, there's probably more upside on the gas side than on the oil side.”

Global Hunter Securities senior analyst Mike Kelly has been at the forefront of research on developing resource plays, including work on the Utica and the Permian basins (notably, a “Permian Delineation Guide”), as well as his long-running advocacy of the Tuscaloosa Marine shale, in which Goodrich Petroleum Corp. was his top pick last year.

Kelly continues to seek out the next big developing play—he currently favors the southern Delaware basin—but adopts a distinctly more cautious tone about the macro overlay he sees for energy.

“As we move into manufacturing mode, it has some pretty drastic repercussions on price, because the supply reaction will be so strong,” he says.“We really see the disequilibrium in the market between supply and demand in the second half of 2014, and that's when you probably start seeing the reaction in oil prices.I wouldn't be shocked if we see prices overreact to the downside, which we know tends to happen.”

Kelly acknowledges that accurately predicting commodity moves—and their timing—involves a huge number of variables that may change in the interim.“That's the million-dollar question,” he says.

“If you hold commodity prices constant, these stocks have tremendous running room with delineation of their currently undeveloped assets.A stock like Pioneer has a lot of NAV that it can potentially capture if it can demonstrate it has as many as five or six zones it can actually produce from on its acreage in the Midland Basin,” says Kelly.So far, he notes, rather than taking gains, investors have been inclined to hold on to positions to see the next potential leg up in the stock as a result of forthcoming tests of its two Spraberry zones or from downspacing tests.

So how is he adjusting his approach to stocks, given fast-rising NAVs in a stable price environment, but diminishing NAVs if oil prices slide significantly and acreage loses value?

Kelly uses a more conservative approach, with less emphasis on NAVs based on 3P reserves (proved, probable and possible, and factoring in acreage value), and more placed on other metrics, such as enterprise value to PV-10; multiples of cash flow or EBITDA (earnings before interest, depreciation and amortization); and an assessment of the visibility and quality of an E&P's inventory of locations.He cited as an example Whiting Petroleum Corp., which in late October was trading at around $62, a two EBITDA multiple discount to its peers.

In terms of plays, “we think that the southern Delaware Basin could be the next portion of the Permian that really proves to be extremely good,” says Kelly.“The play now has 16 rigs running in Reeves County, and has attracted “really high-quality players in there—

Anadarko, Cimarex Energy, Concho Resources, EOG Resources, Energen, Rosetta Resources—all speaking very highly of the potential.” His top pick at the time: Rosetta Resources, with 40,000 acres in the play, trading around $56.

On the issue of US laws banning the export of crude oil, except to Canada, Kelly sees little sign of any change, except perhaps the possibility of selective exemptions.

“I would be shocked if there were a sweeping revocation of the current export ban.What I've heard from some informed guys on the policy front is that they would expect to see some one-off exemptions happen first, where you would request a waiver to be able to export crude if you couldn't get an acceptable economic price in whatever regions you are in.”

With talk of growing North American self-sufficiency in oil—and possibly excess supply in certain oil grades—questions about the oil and gas industry's outlook are almost invariably answered with an accompanying oil-price caveat.

Morgan Stanley's Calio suggests that some concern about weakening oil prices may be misplaced, in that the US may be better positioned than anticipated to absorb the next two million barrels per day of production growth, projected through the end of 2017, by continuing to displace imports and export light oil to Canada.

Concern about oil prices “gets over-amplified by US analysts because US production growth forms so much of our identity, our story,” he says.The US is a factor in the global picture, but “it's going to come down to Iran and Iraq.They're the bigger, material places that can really change the balance to make an optimistic forecast turn out wrong.And we'd expect that the Saudis, producing at all-time highs, would still be willing to pull crude off the market to make room for US production.”

With the oil price picture beyond the control of the average E&P, what can the sector do to ensure things go well?

Assuming oil prices stay at reasonable levels, “developers of these assets should remain at least somewhat disciplined with their capital spending growth, so they don't put themselves in an environment of deteriorating returns associated with moving too quickly, which negatively affects their capital efficiency,” says Simmons & Co.'s Kistler.“It's the whole argument of do you go from 15 rigs to 50 rigs overnight?You're going to lose capital efficiency if you do that.”

Coincidentally, Pioneer, another name favored by Kistler, plans to go to 50 rigs in the Permian—but over several years.This reflects not only the size of the prize, but also the importance of optimum development efficiency.

What inning is Pioneer in?“We're really in the batting cage before the game, taking a few pitches,” said Tim Dove, president and chief operating officer of Pioneer, at a recent Hart Energy conference.

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