Oil and Gas Investor Blog

As for the Marcellus, it’s developing rapidly, but it’s still a good ways from play maturation, he adds.

Amongst resource plays, next in line for advancement, since the Barnett, into oil- and gas-producing MLPs’ portfolios is the Fayetteville shale play, followed by the Haynesville, says Jonathan Hough, director, energy investment banking, for BMO Capital Markets.

On a scale of resource-play maturity-that is, its advancement from science experiments and early exploration to more of a methodical, manufacturing mode-the original shale play, the Barnett in the Fort Worth Basin in North Texas, is the most advanced, Hough notes. He presented to attendees at Hart Energy’s workshop in Pittsburgh on Marcellus and Utica finance and M&A, preceding the fourth annual DUG East conference.

Already, EV Energy Partners LP and Atlas Resource Partners LP have bought into the Barnett, which was proven by Mitchell Energy & Development Corp. in the late 1990s. Also, Fort Worth-based Quicksilver Resources Inc. plans to form an MLP, Quicksilver Production Partners LP, for the purpose of dropping into it its developed Barnett portfolio.

Meanwhile, the Fayetteville in Arkansas that was founded by Southwestern Energy Co. in 2004, hosts one MLP, Vanguard Natural Resources LLC, already. The Haynesville in northwestern Louisiana that was proven in early 2008 by Chesapeake Energy Corp., hosts Memorial Production Partners LP.

MLPs (master limited partnerships) are built to produce oil and gas-paying out earnings as pre-tax distributions to investors-and exploit known new-well targets, rather than to explore for oil and gas as do traditional E&P companies. “Basin maturity is critical to meet the MLP model,” Hough says.

Next on the MLP course? Far along, but still needing more capital-intensive investment and further de-risking, are the Marcellus, Bakken/Upper Three Forks, and Eagle Ford condensate window, Hough says. These remain best suited to traditional E&P companies, including slightly lower-risk-taking public-equity-backed E&Ps.

“The Marcellus is still in early-stage development versus the Barnett, which has matured,” Hough says. However, it is advancing much more rapidly. “It took more than six years for Barnett production to grow from 1 Bcfe (billion cubic feet equivalent) a day to 5 Bcfe a day.” Meanwhile, Marcellus grew to that rate in only two years of exploration and he estimates there are still 100 years of drilling left to be done in the rock at the current pace. In contrast, drilling inventory in the Barnett has declined to a 30-year supply, particularly at the current-gas-price pace.

Another distinction is that Barnett wells hit their MLP-appropriate decline rate-some 10% a year-in their fifth year of production, while Marcellus wells might not reach this until their seventh year.

And, existing Marcellus producers are not motivated to sell: Keeping exploration companies at work there-rather than casting off this inventory to MLPs as a means of funding a next great play-is that they can better afford to do this there than in the Barnett.

At a $4 gas price, Marcellus wells produce an average 44% internal rate of return (IRR), Hough says; Barnett, 28%. At $5, the Marcellus generates an average 75% IRR; the Barnett, 54%.

“Given strong economics of the Marcellus, producers are likely to continue development drilling. Monetizations will be more frequent as the basin matures.”

For most MLPs, they want more Marcellus production results to define areas with high concentrations of PDP (proved, developed, producing) reserves that are ready for infill drilling. Meanwhile, there are plenty of other, mature property packages for them to consider in basins elsewhere, he adds.

“Buyers and sellers agree that MLP M&A activity in the Marcellus will happen, but it’s too early,” Hough says.

For potential Marcellus sellers, they still have plenty of wells to drill, the Marcellus has superior economics and they can divest properties elsewhere to continue to fund Marcellus exploration. “Currently there is no pressure (for a producer) to find ‘the next asset’ to replace the Marcellus.”

The Marcellus itself is still a next, great asset. He notes that Range Resources Corp., which founded the Marcellus play in 2007, sold its Barnett acreage and production under and around its Fort Worth headquarters in just 2011 to fund development of its new Marcellus play.

Last in line for MLPs? Resource plays best suited to remain in the hands of public-equity-funded E&Ps-in terms of continued nascence, thus higher capital risk-for some time longer are, in order of most to least risk,

–The Lower Three Forks formations, which sit under the Bakken/Upper Three Forks play in the Williston Basin and hosts only a few wells yet, albeit each highly successful,

–Cline and Wolfbone in the Permian Basin,

–Utica in Ohio and northwestern Pennsylvania,

–Niobrara in eastern Colorado and Wyoming,

–Eaglebine in southeastern Texas,

–Bone Spring/Avalon in the Permian Basin,

–Mississippi Lime in northern Oklahoma and southern Kansas,

–Horizontal Wolfcamp in the Permian Basin, and the

–Eagle Ford oil window.

Perched on the border of being best suited for a traditional E&P-either publicly or privately funded-is the Eagle Ford’s dry-gas window, Hough says.

Drilling inventory? Hough estimates the

–Marcellus’ 15 million acres have 175,000 locations remaining to be drilled or a 100-year inventory at a rate of 1,650 wells a year,

–The Eagle Ford, across all windows, consists of some 10 million acres with 100,000 remaining locations or a 40-year supply,

–The Haynesville, 3.5 million acres, 50,000 locations remaining or a 50-year inventory, and

–The Barnett, 4 million acres, 30,000 wellsites remaining or 30 years.

“As (traditional E&P) C-corps continue developing new resource plays, legacy assets in blow-down stage will be divested, and MLPs are likely buyers,” he concludes.

But not just yet for most.

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

NOTE: For news tweets from DUG East 2012, search #DUGEA2012.

Producers are more interested in reaching waterborne-oil-priced, coastal markets.

Oneok Partners LP’s withdrawal of its 1,300-mile, 200,000-barrel-per-day Bakken Crude Express pipeline plan from North Dakota to Cushing may reflect that

–Producers want flexibility of rail, instead, in the markets they can reach,

–Producers don’t want to send their oil to the WTI-priced Cushing market,

–The price of using the Oneok pipe wasn’t competitive with the flexibility of rail or other pipeline plans and/or

–More than enough pipe is already planned for Bakken take-away.

These are suggestions from myriad U.S. E&P analysts upon the Oneok news this week.

“We are not sure what the required terms were for the deal from Oneok,” says David Tameron, senior E&P analyst for Wells Fargo Securities LLC. “But the price could have been a deciding factor. We have heard from some producers that they are hesitant to make long-term commitments at this point as options multiply and producers see sufficient capacity via existing and in-process pipe and rail.

“As rail capacity continues to expand in the basin, providing access to additional markets outside of Cushing, we have seen refinery demand for Bakken crude stretch to the (East, West and Gulf) coasts, bringing along with it premium pricing.”

Analysts with Tudor, Pickering, Holt & Co. Securities Inc., report, “The abundance of rail is the likely culprit.” They estimate there are some 750,000 barrels of daily oil-by-rail capacity currently, plus some 450,000 a day of pipe. Also, some 1 million of additional pipe capacity is expected to come online by year-end 2015, they add.

Bernstein Research senior analyst David Vernon says, “Anecdotally, we understand producers are taking a wait-and-see approach in regards to shipping from the Bakken shale to Cushing, given the price differential between WTI-Cushing and (the coastal price). As such, it appears producers are reluctant to sign multi-year-approximately 10-year-pipeline contracts when railroads are offering flexibility of destination and one-, two- or three-year deals.”

In a report earlier in November, Vernon estimated U.S. oil carloads grew from fewer than 5,000 in first-quarter 2010 to nearly 90,000 in the second quarter of 2012. While rail provides producers with flexibility in the markets they can reach, he expects Bakken-by-rail will decline by 2014 as more pipe capacity comes online.

“A valid question is if other pipelines are at risk,” Vernon concludes. “We will be watching and asking industry contacts about other pipelines, though we suspect that one of the reasons the Oneok pipeline was cancelled was because there wasn’t enough (Bakken) crude oil production to justify its completion.

“Now it seems production and pipeline take-away capacity are better matched and, as such, we would expect the remaining pipelines to have a higher chance of being built.”

The WTI price-that is, the Cushing price-for oil has been less than the coastal price by $15 to $30 a barrel for most of the past 22 months.

Estimates are that North Dakota currently gives up some 700,000 barrels a day and the figure is growing at great speed, while formations in addition to the Bakken are coming online. The play’s founder, Continental Resources Inc., also proved the deeper Three Forks play to be a prolific oil producer. Since then, it has also proved the lower Three Forks II bench in 2011 with the Charlotte 2-22H that has made 87,000 barrels of oil equivalent (BOE) in its first 10 months. A second Three Forks II producer, ConocoPhillips’ Sunline 11-1TF-2SH, has made 85,000 in six months.

Continental is now drilling a first test of the yet-deeper Three Forks III zone with its Charlotte 3-22H. In accessing different markets, some of the company’s roughly 62,500 BOE a day of Bakken production is now going via rail to a refinery on the West Coast at Anacortes, Washington.

Bakken oil is also making its way to the East Coast, and more for that destination is planned. A day prior to the Oneok news, pipeline operator Enbridge Inc. announced a plan begin railing 80,000 Bakken and other barrels a day to a former coal-offloading terminal at Eddystone, Pennsylvania, south of Philadelphia. Two of a power-generation plant’s six generation units there had operated on coal until they were retired in just the past 18 months, thus retiring the coal-offloading terminal; the balance of the power-gen units use natural gas as feedstock.

Steve Wuori, Enbridge president, liquids pipelines, says of the rail plan, “Rail is the fastest way to provide increased export capacity out of the Bakken, creating a near-term solution to transportation bottlenecks and the resulting oil-pricing differentials.

“Eddystone is an important step in our longer-term strategy to accommodate the anticipated growth of light crude-oil supply and to provide Bakken producers and PADD I (that is, U.S. Northeast) refiners with cost-effective capacity to premium markets on the eastern side of North America.”

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

NOTE: For a full report on Bakken take-away to the East Coast and West Coast, in addition to the Gulf Coast, see “Tri-Coastal Bakken,” December, Oil and Gas Investor, at OilandGasInvestor.com.

“It’s time for the protesters to come down out of the trees, take a bath, and hit the road.”

Here, Texas Land Commissioner Jerry Patterson, elected to a third term in 2010 by Texans, provides his opinion of protests that are against the completion of the southernmost leg of the Keystone XL pipeline, which is to carry some 1.3 million barrels of oil per day from Canada to U.S. Gulf Coast refiners. -Nissa Darbonne

“As Texas Land Commissioner and the elected head of the General Land Office, my job is to generate income from state land and mineral resources that are constitutionally dedicated to funding public education, provide veteran’s benefits through the Texas Veterans Land Board, and protect the environment associated with state owned land, particularly along the Texas coast.

“In fact, Commissioner of the Texas General Land Office is the oldest continuously existing office in Texas government, having been established in 1836.

“I’ve recently learned that a bunch of out-of-state, self-appointed “eco-anarchists” think they know better than Texans and have arrived to save us from ourselves. They’re trying to block the Keystone Pipeline Gulf Coast Project, the pipeline that’s under construction in East Texas that will create thousands of jobs and lessen our dependence on foreign oil.

“Fortunately, they’re not succeeding.

“The only thing they’ve managed to do so far is get arrested and waste the time and resources of local law enforcement officers. They have also generated publicity for a clueless Hollywood actress who was recently arrested, and thanks to her mug shot, probably received more press than she’s received since she played a mermaid in a movie a couple of decades ago.

“The protesters are under the misguided notion that they know better than Texans about what’s good for Texas. I’ve got news for them: they don’t.

“Their scare tactics and misinformation won’t work in Texas. Gangs of tree sitters who trespass and defecate on landowners’ property don’t understand Texas values and culture. Their antics aren’t going to convince Texans to “rise up” and abandon our energy industry, an industry that has made this state the economic envy of the United States.

“If anything, they’re going to convince most Texans to tell them to shut up and go home.

“TransCanada has worked responsibly to ensure it has the legal authority and regulatory approval needed to build the pipeline and will diligently work to restore property to its original condition. Along the way, the company has treated Texas landowners with integrity and respect, which is more than I can say about the protesters and their trespassing, tree climbing, drum beating antics.

“Like all Texans, I expect TransCanada to meet high expectations regarding environmental and safety standards. As an elected steward of the land, a proponent of responsible energy production, and an advocate for private property rights, I expect TransCanada to continue to treat landowners fairly and respectfully.

“Texas is a proud leader in the development and transportation of oil and gas in a safe and environmentally responsible manner. As part of the Keystone Pipeline System, the Gulf Coast Project will be constructed using industry-best practices and will meet or exceed all regulatory standards. TransCanada also has agreed to meet 57 additional safety and operating standards above and beyond existing codes.

“One last point: If you think these folks are motivated by private property rights, think again. They are simply part of the environmental lunatic fringe that hates the oil and gas industry and is attempting to co-opt their message using the private property rights tradition that Texans hold dear. If you don’t believe me go to their website: www.tarsandsblockade.org.

“Given all those indisputable facts, it’s time for the protesters to come down out of the trees, take a bath, and hit the road.”

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Colorado’s Niobrara play has the best NGL economics today, says KeyBanc’s Deckelbaum.

As prices for NGLs (natural gas liquids) decline, whose going to start feeling the pinch first? “Looking at possible slowdowns, we see the most risk for the Cana/Woodford and Eagle Ford (wet-gas-window) plays,” in terms of percent of production that is wet gas, says David Deckelbaum, senior E&P research analyst for KeyBanc Capital Markets.

Production from each play is roughly 30% NGLs. “At $90 (oil) and (as NGLs are getting) 40% of WTI, if NGL pricing comes down to 30% or so, the Cana and wet portion of the Eagle Ford become marginal at best,” Deckelbaum says. The third-ranked play would be the wet-gas window of the Marcellus, which produces 22% NGLs.

“A year ago, when you were at about 55% WTI, you were getting about $2.50 an Mcf equivalent uplift for having NGLs in your gas stream. We think that has compressed today to about a buck.” So, at the Nymex price for natural gas, “instead of getting $2.70, you’re getting about $3.70.” A year ago, at the Nymex prices for oil and gas, producers may have been getting more than $5.50.

Deckelbaum addressed attendees at a KeyBanc-sponsored industry program in Houston recently. He and fellow senior E&P analyst Jack Aydin cover some 34 oil and gas producers with roughly $140 billion in market capitalization, ranging from $200 million to $13 billion.

The best wet-gas play today is the Niobrara in the Wattenberg Field in Colorado, he says. “It has the best economics in the entire U.S. It’s tough to get some (acreage) positioning there, but we’ve seen some very reasonable acreage valuations…You can still lease at attractive pricing, compared with the returns you can get.”

Deckelbaum suggests that NGL producers hedge the heavier portions of the NGL barrel. “Consider hedging some of your propane…To some extent, we believe the lack of hedging reflects the attitude that some of this (down-pricing) is seasonal, that it’s going to be short lived, but I think we’ve all lived through attitudes like that before with natural gas-where we waited for a cold winter or a hot summer and it doesn’t do enough to really work down that excess supply.”

Demand for ethane is some 900,000 barrels a day while supply has grown to some 1 million a day. “We should see bringing on another 50,000 barrels a day of demand, but we still see a situation where we’re going to be oversupplied on the ethane side.”

Hedging is the best solution, he concludes. “Propane is a product you can hedge effectively. Hedging is at least something that many of our best-in-class names hedge well over 50% of production.”

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

“They’re not getting done with the buyers we’re used to….”

With natural gas prices below $3, how do gas buyers get deals done? Year to date, 15 publicly announced, gas-weighted deals-that is, with proved reserves of more than 50% gas-valued at $25 million or more have been done, notes Sylvia Barnes, managing director and head of oil and gas investment banking for KeyBanc Capital Markets.

In the past 12 months, there have been 26 of these deals, she adds.

“They’re not getting done with the buyers we’re used to-the traditional oil and gas companies. Rather we’re seeing foreign entities, trading houses, the big private-equity firms with a contrarian view like an Apollo (Global Management LLC) and Riverstone (Holdings LLC et al.), such as in the $7.15-billion El Paso (Corp. E&P) deal.”

Barnes addressed attendees at a KeyBanc-sponsored industry program in Houston recently. “We are also seeing a lot of deals done where there is an advantage of cost of capital, like a flow-through MLP vehicle.”

These buyers, such as Linn Energy LLC and EV Energy Partners LP, use low-cost equity capital to buy producing properties that require little reinvestment in contrast with traditional, C-corp E&Ps, which must replace and grow production.

“We also draw your attention to how effective these flow-through MLPs are in their hedging strategy. The poster child for that is one of our clients, Linn Energy.” Among the 26 gas-weighted deals industry did for U.S. gas-weighted properties, Linn did 15%. “And every time they make an acquisition, they hedge 100% of the proved reserves for four years-100%. This has given them a strategic advantage.

“So to do deals in this market, you need to do something out of the ordinary. You have to challenge conventional thinking. This is the type of strategic thinking we’re seeing the successful players use to navigate the storm of these commodity markets.”

Amongst MLPs, the average gas-hedging level for 2014 is half that of Linn’s. “Even more interesting is, if you look at the C-corps, you’re down to 4% in 2014.”

Andrew Fletcher, KeyBanc senior marketer, energy derivatives, adds that, in hedging, producers have to be nimble and seize the day. “Be flexible on timing. Opportunities don’t always coincide with the next board meeting. Stick to your plan and don’t second-guess yourself. Failure to execute is a real cost.”

In 2008, when the gas-price strip pushed above $12, gas-weighted deals were at $3.01 per thousand cubic feet equivalent (Mcfe) of proved reserves, Barnes notes. There were 47 publicly announced transactions of at least $25 million in value that year. In 2009, when the strip fell below $4, there were 26 and at an average price of $1.75 per proved Mcfe. To date, the 2012 average is $1.37.

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

The multiple is less than half that of onshore U.S. unconventional-resource portfolios.

With one simple multiple, “3-4x,” Bill Marko explains just how depressed asset valuations for deepwater Gulf of Mexico assets are these days. The figure is how much public-stock investors will pay for these properties within E&P companies’ portfolios: three to four times EBITDA.

That’s in contrast with 8x to 10x EBITDA at which investors are valuing onshore U.S. unconventional-resource plays, he says, and is less than an overall multiple of 5x to 7x for large-cap E&P companies in general.

Marko, managing director, energy M&A, for Jefferies & Co., addressed more than 500 attendees at Oil and Gas Investor and A&D Watch’s 11th annual A&D Strategies and Opportunities conference in Dallas recently.

Since the Macondo incident in the Gulf in April 2010, “the increased regulatory environment, risk of deepwater operations, and size and timing of deepwater development are causing reconsideration of deepwater strategies,” he says.

In more than two years since Macondo, there have been only a handful of deals for Gulf assets, including a few that had been signed prior to April 2010 and subsequently closed on schedule.

The highest-profile new deal involved shallow-Gulf assets, with Oklahoma-focused SandRidge Energy Inc. buying Dynamic Offshore Resources LLC this year, sweeping the private-equity-backed producer off the IPO market. And, what a bargain it was, according to Tom Ward, SandRidge chairman and chief executive officer.

Ward told attendees at Oil and Gas Investor’s Energy Capital Conference in June, “The idea of us getting into the Gulf of Mexico was just a dislocation of the market. Post-Macondo, oil in the Gulf of Mexico was selling at a discount to what we could buy it for onshore the U.S.” (See senior editor Steve Toon’s report.)

Interest in Gulf leases is strong since lease-sales have resumed post-moratorium. Marko notes that the June 2012 Central Gulf sale was the third largest in history; the first- and second-largest were in 2008 and 2007, respectively, as oil prices were heading to $150 and natural gas above $10.

Tudor, Pickering, Holt & Co. Securities Inc. analysts reported after the 2012 sale, “The bidding was dominated by supermajors as the Top 5 accounted for 74% of total winning bids versus 48% in the March 2010 auction-with two supermajors in the Top 5 (at the time).”

But bids for shallow Gulf leases were weak this past June. “Shallow-water (acreage) received lots of attention, but operators were not paying up for it. Compared with the March 2010 lease sale, shallow water showed an increase of 28% in blocks receiving bids, but the price per acre declined from $118 to $102…

“The (shallow-water) bidding activity suggests lots of interest-if the price is right.”

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Current analyst new-play favorites include the horizontal Permian, Utica, Mississippi Lime, Woodbine, Pearsall, Uinta, Tuscaloosa Marine Shale.

What’s the next great new Lower 48 horizontal play? There will be fewer going forward, according to analysts at Tudor, Pickering, Holt & Co. Securities Inc.

“Interestingly, U.S. resource plays continue to be either smaller in areal extent or increase in complexity-there aren’t many Bakken, Eagle Ford, Marcellus (plays) popping up,” they note. Those three formations have been vast in acreage they underlie, commercial-success repeatability across that acreage and predictability in hydrocarbons they give up-all hallmarks of a “resource play.”

Investors wanting to anticipate the next great resource play may run out of relatively easy opportunities, so importance in stock-picking should be place more in the future on playmakers’ wherewithal to tackle complicated rocks. “We expect this trend (of fewer new plays) to continue and, over time, the affinity for stocks with differentiated abilities to find, develop and repeat smaller-field-type plays will increase.”

Gabriele Sorbara, E&P analyst for Imperial Capital LLC, says the Utica play, which Chesapeake Energy Corp. proved last year, remains promising. Yet, “the leveraged Ohio Utica shale companies-PDC Energy Inc. and Rex Energy Corp. in our (coverage) universe-may underperform the group in the near term, despite the numerous catalysts to come, given the high expectations set on the play.” As more data develops, “we believe a buying opportunity may emerge in 2013.”

The TPH analysts’ favorite new horizontal play is the horizontal Permian Basin “where we are expecting a slew of updates, including (M&A) transactions, well results and inventory updates over the next three to six months.”

Sorbara also likes the Permian’s more immediate potential: “…In this volatile market, we continue to believe the operators in the (more) proven plays, specifically…in the Permian Basin, Eagle Ford and Williston Basin, present the more attractive risk/reward profiles.”

The TPH analysts also have the Utica on an “areas to watch” list. Others are the

–Tuscaloosa Marine Shale, which Encana Corp., Devon Energy Corp. and Goodrich Petroleum Corp. are working to commercialize;

–the Woodbine play in East Texas that is being drilled by several private companies as well as Crimson Exploration Inc., Halcon Resources Corp., Zaza Energy Corp. and Devon;

–the Pearsall in South Texas that is being worked by Cabot Oil & Gas Corp., EOG Resources Inc., Goodrich and others;

–the Uinta in the Rockies that Newfield Exploration Co., Bill Barrett Corp. and Berry Petroleum Co. are drilling; and

–the Mississippi Lime that was commercialized by SandRidge Energy Inc. last year and is also being proven by Chesapeake, Midstates Petroleum Co. Inc., Range Resources Corp., Devon, Royal Dutch Shell and Apache Corp.

Midstates is expanding in the Mississippi Lime, buying a portfolio from privately held Eagle Energy of Oklahoma LLC for $325 million in cash and some $325 million of preferred shares. The TPH analysts expect the deal, which is to close by the end of this month, will bring a less complex cash-flow-maker to Midstates’ portfolio to balance its geologically complex Louisiana properties.

“The Mississippi Lime is one of the more recent emerging oily/NGLs-rich plays onshore with the distinct characteristics of being shallow reservoirs-driving low well costs and high-water-cut production,” the TPH analysts report.

Meanwhile, for more Utica-stock-pop exposure sooner, Sorbara suggests, from among just five Utica names in the Imperial Capital coverage list current, Magnum Hunter Resources Corp., “with a potential liquidity event on the horizon, given the company has hired an advisor to market its Utica shale properties in search of a joint-venture partner.”

Not covered by Imperial but also marketing Utica packages include Chesapeake and EV Energy Partners LP.

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

TPH: “U.S. ethylene-cracker build-out opportunity (alone) represents a potential of some $20 billion in expenditures….”

If they build it, the price will come….

In the midst of ethane rejection at Conway and somewhat-stranded Canadian oil-sands and North Dakota oil, several build-out and new-build fractionation, ethane-cracker, gas-export and refining projects are on the books across the U.S. to monetize producers’ new NGLs, dry gas and crude oil.

While burgeoning U.S. hydrocarbon supply has heralded expectations for a U.S. manufacturing renaissance, it is certainly resulting in a U.S. engineering and construction (E&C) windfall.

Here are details on some downstream build-out to take on new, indigenous supply as well as insight on further build-out, according to Tudor, Pickering, Holt & Co. Securities Inc.’s equity-research analysts’ notes since commencing coverage of E&C stocks this spring:

–Globally, “identifiable ethane-cracker work represents $20- to $30 billion of opportunity with a potential, overall chemical/petrochemical pipeline of $70- to $90 billion of projects, e.g. ethylene, PDH (propane dehydrogenation), butadiene.”

–Chicago Bridge & Iron Co. NV (CB&I) won a PDH construction job from Enterprise Products Partners LP, which enjoys “unparalleled access to Gulf NGL supplies,” for a fee-based PDH facility, giving Enterprise “a new growth platform and marginally improves propane supply/demand fundamentals with 35,000 barrels per day of demand, i.e. 3% of the market.”

–HollyFrontier Corp. is expanding its Woods Cross refinery in Salt Lake City. Marathon Petroleum Corp. has a $2.2-billion heavy-oil under way at its Detroit refinery. Valero Corp., which expects to quit using imported, light, sweet crude on the Gulf Coast by year-end 2013, has two $1.5-billion hydrocracker projects under way.

–E&C firm Fluor Corp. won $5 billion of additional oil and gas projects this spring globally, bringing its total for the sector to $19.5 billion. “Going forward, oil- and gas-sector prospects remain robust, especially on the low-U.S.-gas-price-driven side, given petrochemical, GTL (gas to liquids) and even LNG (liquefaction) opportunities…Fluor believes the U.S. markets-led by oil and gas and associated chemicals/industrial work-look promising.”

–Besides Fluor, KBR Inc. also expects some U.S. GTL-facility construction projects to come. “While we’re not certain of the economics there, (Fluor) maintains it is involved in some discussions on that front.”

–CB&I’s planned purchase of The Shaw Group Inc. in early 2013 will bring its all-sector backlog from $18 billion to $28 billion. “The acquisition also adds material U.S. leverage to CB&I as Shaw’s revenue is some 85% U.S. versus CB&I, which does some 80% international. Locking up a U.S. labor force for low-gas-/LNG-driven infrastructure build-out is also a potential goal here…(And) large, greenfield petchem projects have yet to hit E&C backlogs.”

–Technip bought Shaw Group’s “ethylene-cracker-capable energy and chemicals group” for $300 million. “Petchem capabilities are so hot right now…The deal demonstrates that E&Cs without petchem leverage are looking to jump in pre- the build-out boom-a theme we’re onboard with.”

–KBR’s North American construction-services backlog grew to some $2.3 billion this summer, such as for gas-processing. “Not coincidentally, the downstream backlog was up a whopping 60% to more than $700 million as shale production drives petrochemical and gas-processing work domestically and abroad.”

–The TPH analysts don’t expect many U.S. LNG export facilities will be permitted, though. “Exporting base hydrocarbons is not historically a U.S. forte….” That may bode well for more U.S. (end-user) E&C awards. “The U.S. prefers processing the hydrocarbons in-house and selling refined products-e.g. shale gas processed and fractionated, ethane extracted and cracked into ethylene then into plastic for export.”

–Williams Cos.‘ Williams Olefins LLC is well on its way to expand its ethylene plant at Geismar, Louisiana, from 1.35- to 1.95 billion pounds a year, awarding CBI with a $300-million E&C contract for this earlier this year.

–Meanwhile, KBR won a contract from Ineos Olefins & Polymers USA to build a 465-million-pound-per-year ethylene furnace along the Houston Ship Channel. “We believe U.S. ethylene-cracker build-out opportunity represents a potential of some $20 billion in expenditures by E&C clients; associated processing/fractionation opportunities offer an additional multibillion dollars of upside.”

–Bechtel Corp. has won Cheniere Energy Inc.’s Sabine Pass, Louisiana, liquefaction E&C project. Meanwhile, CBI has received the FEED project for Freeport LNG Development LP’s LNG project at Freeport, Texas.

–”CB&I views the North American petchem opportunity as $16 billion during the next 24 months, which we believe may surprise some folks to the upside. We estimate the U.S. ethylene-cracker opportunity alone at some $20 billion, but over a longer time horizon. Large greenfield cracker projects-potentially $4 billion each-are not likely a 2012 story but, as we saw with the $300-million Williams Olefins award, CB&I will benefit from ethylene-cracker expansions via its technology and E&C businesses in 2012.”

It will still be a while for downstream infrastructure to catch up to upstream supply, however.

Brad Olsen, TPH’s midstream analyst and author of its monthly NGLs report, notes, “We are seeing returns migrate from upstream companies towards the midstream and even the downstream-i.e. refining and petrochemical…

“Ethane supply is sufficiently robust and pricing versus crude is already sufficiently weak that petrochemical companies are rushing to build new and to convert existing ethylene crackers that are capable of consuming greater quantities of ethane. The rub: Ethylene crackers take two to three years to convert; five to seven years to build.

“That’s a lot longer than drilling wells, laying pipe or building new fractionation towers to deliver the end product to petchem consumers. Expect ethane supply to outpace demand through 2017-18.”

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Sunoco-Carlyle’s Philly refinery deal puts U.S. shale boom to work.

News of private-equity investor The Carlyle Group LP’s deal with Sunoco Inc. brings the Northeast U.S.’ high-priced oil-feedstock market into new, lower-priced, U.S. oil supply. Tudor, Pickering, Holt & Co. Securities Inc. analysts sum it up: “Cheap domestic supply versus expensive, light-oil imports equals action.”

Sunoco’s Philadelphia refinery had been slated for closing next month, while it and its already-closed Marcus Hook each depended on higher-priced, seaborne oil supply as feedstock in making refined products, such as gasoline. The TPH analysts name the Philadelphia plant as the largest refinery in the PADD 1, or U.S. East Coast region, processing 330,000 barrels of oil per day.

Plans are for railing Bakken-shale-play oil from North Dakota to the plant, giving it access to a lower-cost feedstock than Brent-priced oil. Upgrades to the plant will also utilize U.S. hydrocarbon producers’ new gas and gas-liquids supply from the Marcellus shale play that is in western Pennsylvania.

The TPH analysts note that some 50% of East Coast refining capacity had been targeted for closing. “But Trainer (the ConocoPhillips refinery Delta Air Lines bought this year and that processes 187,000 barrels of oil per day) and (Sunoco’s) Philadelphia escaped.” Western Refining’s Yorktown plant, which processed 60,000 barrels per day, is closed, along with Sunoco’s Marcus Hook, which processed 180,000 per day.

Paul Sankey, global energy analyst for Deutsche Bank, says in his report “Diamond Age: Refining and the U.S. Manufacturing Export Renaissance” on Monday before the Carlyle-Sunoco news, “We believe the U.S. unconventional oil and gas boom is a secular long-term play that is unique to the U.S., providing oil, natural gas liquids and natural gas at far below global prices for at least a decade to come.”

Stock investors are wrong if thinking the U.S. hydrocarbon-supply boom doesn’t create profit opportunity for U.S. refiners, he adds. “The equity market maintains an irrational belief in the cyclicality of this business, despite the secular shift. It refuses to pay for the export growth. It disregards the lack of new capacity addition and growth in exports. It ignores the improved, safety, returns, and management execution and strategy.”

Carlyle and Sunoco report in a joint press release that the continued operation of the Philadelphia plant-the oldest on the East Coast in continuous operation-will “save 850 jobs, secure the region’s fuel supply by continuing the daily flow of 10 million gallons of various fuels, and create 100 to 200 new, permanent jobs, as well as thousands of construction jobs.”

Brian MacDonald, Sunoco chairman and chief executive, says, “This partnership is a great example of what can happen when motivated people think creatively to solve pressing problems. The private sector, government and labor all played important roles in getting this done. This is the best possible outcome for everyone involved: Existing jobs will be saved, new jobs will be created and new business opportunities will be given the chance to develop.”

Carlyle managing director Rodney Cohen says, “Together we’ve re-imagined the Philadelphia refinery and its role as a critical energy hub in the Northeast. This joint venture will keep one of the region’s most important economic engines up and running. The refinery will be a reliable and critical supplier of fuels to the regional market through its new business structure and improved crude oil sourcing.

“In addition, the refinery’s exceptional location and infrastructure will enable the joint venture to create new business opportunities related to Marcellus shale natural gas fields….”

Leo Gerard, international president for employees’ rep United Steelworkers, says, “Not only will good paying manufacturing jobs be saved, but new ones will be created as this vital facility is improved and expanded.”

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Maguire Energy Institute’s Weinstein: “North Carolina now has the potential to join America’s shale-gas revolution.”

North Carolina’s legislators have overridden Gov. Bev Perdue’s veto of pro-hydraulic-fracture-stimulation legislation, thus allowing the well-known oil- and gas-extraction-assistance technique in the state in the future.

The state’s Senate voted 29-13 to override, according to Reuters; the House, 72-47.

James Taylor, senior fellow for environmental policy for The Heartland Institute, a Chicago-based supporter of free markets, says in an institute press release, “State agencies and the U.S. Environmental Protection Agency have diligently monitored hydraulic fracturing for decades. As EPA Administrator Lisa Jackson testified under oath in Congressional hearings, EPA has not found a single case of hydraulic fracturing contaminating groundwater. State agencies have yet to identify a single case of groundwater contamination, either.”

The institute also provides a statement from Bernard Weinstein, associate director of the Maguire Energy Institute at Southern Methodist University and a policy advisor to the institute: “…The outcome is a plus for North Carolina taxpayers and businesses. Fracking has been used for more than 50 years to complete tens of thousands of wells across the U.S., and neither the Environmental Protection Agency nor state regulators have ever documented a case of groundwater contamination from the process.

“North Carolina now has the potential to join America’s shale-gas revolution, which is helping put our country on the path to energy independence with attendant economic and fiscal benefits to producing states.”

For more information on shale resource potential in North Carolina, see “North Carolina’s Shale Potential Attracts Attention” at UGcenter.com. For information on hydraulic fracturing, see “Independent Review Finds EPA Pavillion Report Lacking in Scientific Data, Methodology and Analysis” at IPAA.org.

-Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.