Harvard study: US may be world's largest oil producer by 2017

A recent study from Harvard's John F. Kennedy School of Government is bullish on U.S. oil production. It forecasts surging shale-oil production could more than triple the current American output of shale oil to 5 million barrels of oil per day by 2017 from 1.5 million barrels daily in 2012.

Combined with conventional oil production, that would make the US the largest oil producer in the world, at about 10.4 million barrels per day. The International Energy Agency (IEA) has predicted the U.S. will be the top producer by 2020.

In the Harvard study, Leonardo Maugeri, a former senior executive of Eni, the Italian multinational oil company, said the resource size of U.S. shale and tight-oil formations and the industry's knack for technology innovation bode well for production growth.

The U.S. shale-oil boom continues to “dwarf earlier forecasts about its scope and potential,” said Maugeri, who analyzed more than 4,000 shale wells and the work of about 100 E&Ps involved in shale production.

Not all experts are as optimistic. Kevin Norrish, managing director of commodities research for Barclays Capital, questioned the study's predictions. On the one hand, short-term shale production has clearly been underestimated, he noted.

Crude oil production growth has zoomed 1.2 million barrels per day higher than in 2012. The increase eclipsed the Department of Energy and IEA's 2013 growth forecasts by nearly 50% and all but doubled OPEC's call.

“This rate of growth is almost solely down to shale and has been achieved despite the poor performance of producers in the Gulf of Mexico,” Norrish said.

Still, he is cautious about the long-term outlook, partly because of the steep decline rates for shale-oil wells. Two years after a Bakken well drilled in 2012 produces oil, its output is likely 30% of its initial rate.

Maugeri acknowledges such problems. While he thinks technology will continue to push shale development forward, he notes that the nature of the shale and tight-oil sector makes it vulnerable to periods of sluggish growth and even significant falls in production.

For instance, drilling intensity has been the key factor in shale-oil production growth. Steep declines in initial production cause companies to shift quickly to the next well to replace declining production. “Only the U.S. is capable of such drilling intensity,” he said.

In 2012, the U.S. completed 45,468 oil and gas wells and brought online 28,354 of them, compared with 3,921 wells completed in the rest of the world, according to the study.

The US holds 60% of the world's drilling rigs; 95% of them can drill horizontally, which along with hydraulic fracturing is necessary to exploit shale oil.

“It poses a fundamental question for the future of shale production in the U.S.: How far can drilling go?” Maugeri said.

One source of concern is that the shale-oil boom is primarily a boom because of such drilling.

Nevertheless, oil estimates continue to rise. For instance, industry experts have recently recognized the enormous original oil in place (OOIP) in the Bakken, Eagle Ford and Permian regions.

However, “its precise size (the amount for each resource) is still a matter of speculation and continuous update,” Maugeri said.

For example, Continental Resources Inc. estimates the Bakken may hold 900 billion barrels of OOIP, a twofold increase from the 2012 assessment.

“That would make the Bakken's endowment alone larger than Saudi Arabia,” Maugeri said.

The downsides are the dramatic decline in oil recovery after the early months of production and relatively high costs. Both factors cause many to believe recoverable shale-oil reserves represent only a small fraction of the oil in place.

Commodity prices are a big factor. But even if oil prices steadily decrease over the next few years—from $85 per barrel in 2013 to $65 per barrel in 2017—the US could attain shale-oil production of about 5 million barrels per day by 2017, according to the study.

“If oil prices remain close to today's levels, total U.S. production of all forms of oil could grow from 11.3 million barrels per day to 16 million by 2017,” he said. This includes shale, conventional, liquefied natural gas and biofuel production.

Maugeri said his analysis relies on the “Big Three” U.S. plays—the Bakken, Eagle Ford and Permian Basin—to have a combined potential production of 4.7 million barrels of oil by 2017. He said the number of shale-oil wells in North Dakota and Texas could soar from the current 10,000 to more than 100,000 working wells by 2030.

Still, there is always the potential for what he calls “industry victims.”

The U.S.shale boom's greatest beneficiaries today, including many oil and financial companies, may find themselves in distress because of the “various peculiarities of shale economics and development,” Maugeri said. “In fact,

in their quest for shale, many companies have simply overspent on new development without either improving performance or acquiring high-quality assets.”

Most of the assets acquired are overly concentrated in natural gas and liquids, he said.

“Consequently, those companies are now stripped of cash, overburdened by debt, or simply lack the quality resource assets necessary to generate significant growth and returns.”

—Darren Barbee

Obama introduces new energy policy agenda

President Barack Obama delivered an ambitious proposal in early summer for a domestic energy policy that was short on specifics.

The agenda was largely unchanged from the president's energy platform from this past election with the exception that he instructed the Environmental Protection Agency (EPA) to place limits on carbon emissions from existing coal-fired power plants. He also called on the federal government to use up to 20% renewable power by 2020.

Previously the White House had only sought to place limits on new coal-fired power plants. Industry observers tabbed this as a win for natural gas, as it will make it very difficult for power plants to utilize coal without putting in carbon capture technology. It is likely many of these plants will opt to convert to natural-gas-fired facilities.

Obama said that currently there are no limits on carbon emissions from power plants. “That's not right, it's not safe and it needs to stop.”

He said that the EPA's efforts to impose restrictions on power plant carbon emissions will be open and transparent, while allowing for different limits on individual municipalities and states without access to cleaner alternative energy sources.

Obama said that while no single weather event can be cited as being caused by climate change, all of the weather events taking place are tied together and impacted by climate change in some way. These effects are causing an uncertain future for humanity, he said.

He compared the imperative to act on climate change to the need to go to the moon in the 1960s—an action taken for the greater good. “Climate is changing in ways that will have a profound effect on all of humankind…This isn't a question of whether we need to act, but how we act.”

“It will be well past the president's second-term before any of these new rules are finalized and put in place,” John Kneiss, director, Hart Energy Consulting North America, says.

He noted that there will be a long period necessary to provide for public comment and review of the millions of comments submitted on proposals and the writing of final rules, not to mention the resolution of the inevitable litigation that will follow.

Kneiss noted that litigation of similarly complex federal rules has taken upwards of two to three years to make it through the court system. It is likely any litigation related to these proposals will take at least as long to resolve.

While the president said several times during his speech that he was willing to work with any member of Congress on crafting energy legislation to reduce carbon emissions and reverse the effects of climate change, Kneiss said these statements were likely rationalizations to move forward on energy regulations rather than waiting for Congress to act.

He also said that Obama's focus on new energy regulations increases the possibility of carbon tax enactment.

While the president noted that there are market-based solutions to reduce carbon emissions in place in various states already, it is highly unlikely that the federal government would seek such a mechanism due to their complexity and stiff opposition.

“The long-term resolution of budget and debt issues allows for the option of the federal government introducing a carbon tax,” Kneiss said.

While the oil and gas industry does not support such taxes, it is an idea that is viewed with more support than other more complicated measures such as cap-and-trade. This is especially true given that increased costs from such a tax could be passed on to consumers more easily.

The president plans to make up to $8 billion in self-pay loan guarantees available for a “wide array of advanced fossil energy and efficiency projects to support investments in innovative technologies. “

These loans will be made available under the Department of Energy's Section 1703 loan guarantee program .

—Frank Nieto

GHS: Divergent growth trends for reserves show focus on liquids

The top 100 domestic E&P companies added nearly 6 billion barrels (Bbbl.) of proved oil reserves to their books in 2012 while natural gas reserves lowered by 7 trillion cubic feet (Tcf), according to Global Hunter Securities' recent finding and development (F&D) study. The annual study examines year-end reserve data from the 100 largest US public oil and gas companies across one-, three- and five-year periods.

According to the study, the 5.9-Bbbl. record in 2012 outdid the 4.6 Bbbl. in reserves added in 2011 as well as the five-year average of 3.6 Bbbl. of incremental reserve additions. Meanwhile, companies added 33 Tcf in gas reserves, down from 40 Tcf in 2011. Global Hunter says the divergent growth is a result of E&P capex programs becoming more liquids-focused.

“We think this also explains why drillbit F&D costs increased notably year-over-year, as the unit cost to turn the bit to the right and book a barrel of oil reserves is almost always more expensive than drilling for an Mcf of gas,” say the authors.

“In total, drillbit F&D costs increased 28% year-over-year to $22.70 per BOE.”

The 2012 decrease in natural gas reserves also hurt the all-sources F&D cost (total cost incurred divided by total reserve adds during the year), which at $37.30 per BOE was up 94% over 2011. The five-year average was $20.82 per BOE.

E&Ps are also starting to move into “manufacturing mode” according to the study, as development capex was up 28% last year. In fact, spending including acquisitions increased to the highest level on record at $316.6 billion, $56 billion more than in 2011.

“The unmistakable driver came from the industry's uptick in development capex, which totalled $208 billion in 2012 vs. 162 billion in 2011,” according to the study. “Also catching our attention was the downtick in acquisition spending on unproven properties, which was off 40% vs. the average spent the prior two years.”

In aggregate, the data collected from the top 100 U.S. producers includes:

  • more than 300 Tcf of natural gas reserves
  • more than 46 Bbbl. of liquids reserves
  • average daily production of 68 Bcf of gas (around 20% of global production)
  • 11.1 million bbl. of liquids (around 12.6% of global production)
  • cash flow of $2.01 trillion (representing 3% growth year-over-year and larger than Italy's GDP).

—Caroline Evans

Rig count less important metric as days to drill fall

Improved drilling efficiencies are real and should continue for several more years, according to David Pursell, managing director and head of securities at Tudor, Pickering, Holt & Co. Pursell spoke at Hart Energy's Energy Capital Conference in Houston recently.

Actual counting of rigs is becoming less important as an industry metric, and focus is shifting to how many wells are drilled. As efficiency increases, what becomes significant is the number of wells drilled per rig year.

“What we're seeing in all of the key shale plays—where the majority of the horizontal wells are drilled—are significant and continued improvements in days to drill,” said Pursell. Days are being shaved off drilling times even in such mature plays as the Barnett and Fayetteville. The efficiency increases are due to improved drilling techniques, combinations of bit and mud systems, and better rigs.

However, unless rig-count trends move higher, the US land rig fleet will soon outstrip demand. New rigs continue to come on the market: Helmerich & Payne Inc., Patterson-UTI Drilling Co. and Nabors Industries are each building new rigs, and Tudor Pickering forecasts that some 55 new AC (alternating current) rigs will be added to the onshore U.S. fleet this year.

In contrast to older-style mechanical rigs, AC rigs have automated drilling controls, optimized torque and other features that generally drill a better wellbore, more quickly.

“Even high-quality rigs are soon going to be over capacity. Not only are the lower-capability rigs underutilized, there's not 100% utilization in AC rigs or the higher-capability rigs,” he said. Currently, some 265 mechanical-style rigs that are marketable are not working, and about 50 AC rigs that are marketable are not working. These latter are likely lower horsepower, older AC rigs.

One type of rig is defying the trend of steady-to-lower utilization. Rigs with walking capacity—both in the low-capability and high-capability categories—are seeing growing use even as overall horizontal rig counts have essentially flat-lined during the past year and a half at some 1,100 units. That's thanks to a trend toward more pad drilling.

“What's happening is that operators need rigs that help them drill the well faster, but more and more they need rigs that help them move and change locations more quickly. Both of these things matter,” said Pursell.

Of growing interest now to industry analysts is the trend toward pad drilling, and speculation abounds about the scale of additional efficiencies that can be wrung out of the drilling process. Pad drilling offers clear efficiencies on rig moves, and its impact on spud-to-spud days will be significant. The size of the pads and the number of wells per pad will be crucial factors in the next stages of onshore development.

“We're watching what happens with pad drilling,” he said.

—Peggy Williams

For more coverage of Energy Capital Conference, see OilandGasInvestor.com.

North American E&P spending declining as 2013 progresses

U.S. and Canadian E&P 2013 spending is falling faster than company executives previously expected, and the prospects of an upswing in the second half of the year have cratered.

Global E&P spending is forecasted to grow by 5.5% to $637 billion, according to a survey of 462 companies for the Original E&P Spending Survey by James Crandell, managing director of Cowen and Co.

Though US companies will still make up about 23% of global E&P spending, investors should focus on oil-service stocks with investment in international and deepwater operations, he says.

However, the purse strings of North American companies are tightening more than first anticipated. An earlier survey at year-end 2012 forecast US spending would dip 0.8%. Instead, E&P's outlays will drop by an estimated $4 billion, or 2.6% compared with 2012. Partly, that's because some companies want to live within their means while others no longer face the obligation of drilling to hold leases.

Likewise, Canadian spending was initially expected to rise 2.8% from 2012. Executives now believe it is likely to fall 2.3%, Crandell says.

The decline in E&P budgets comes despite slightly higher price expectations for oil and natural gas.

“The outlook for both Canada and the US has eroded somewhat,” Crandell says. “While overall spending is down, we believe well completions and footage drilled will increase due to improvements in drilling efficiency.”

The global spending picture remains relatively unchanged because increased international spending has offset the dip in North America. The Asia/Pacific region is expected to increase spending by nearly one-fifth, Europe will be up 15% and the Middle East by 18%.

Timing is one reason for the spending decline in North America. Crandell says that after years of aggressively acquiring new acreage in shale plays, some companies are free from obligations to hold acreage by drilling, enabling them to reduce spending and more efficiently develop fields.

“Other companies have highlighted a renewed desire to live within cash flows, and this has led to a tightening of budgets this year,” he says. “Notable downward revisions to our prior 2013 capex forecast include Occidental Petroleum, SandRidge Energy and Range Resources.”

Chesapeake Energy appears to be on track to cut $2.75 billion. On the opposite end of the spectrum, Antero Resources, ConocoPhillips, Continental Resources and Noble Energy appear ready to spend more.

US exploration and production expenditures are forecast to decrease by 2.6% in 2013 to $152 billion for the 245 companies surveyed. The drop is likely due to “continued weakness in dry-gas drilling, based on persistently low natural gas prices.”

However, plays such as the Eagle Ford, Permian and Bakken, along with increasing deepwater activity in the Gulf of Mexico, have helped to offset some declines.

“Dry-gas drilling should continue to be impacted by low natural gas prices, while wet-gas drilling should be negatively impacted by lower natural gas liquids (NGL) prices,” Crandell says.

In Canada, the natural gas outlook appears brighter.

“Recent elections have brought in a pro-LNG provincial government to British Columbia that we believe is committed to the export of LNG,” Crandell says.

Drilling should pick up modestly in the second half of the year, driven by activity in the Horn River, Montney and Duvernay plays.

Outside of North America, many of the 166 companies surveyed expected to increase to $443 billion their spending, a hike of 9% from 2012. The spending is driven by stronger estimated growth in the Middle East, Europe, Asia/Pacific and Russia.

The Middle East will increase its spending by 18% from 2012.

International oil companies such as BP and Chevron are, as a group, increasing spending by 7%, led by Eni Petroleum with a 23% increase. Among its peers, only ExxonMobil is decreasing spending, by about 1%.

The survey's 2012 and 2013 budgetary figures are estimates by Cowen and Co. The survey only includes companies that spend more than $100,000 on exploration and production.

—Darren Barbee

Evaluating cost centers, the best comparison is a barrel of oil

It's a job for every individual in the company, from landman to accountant: maximizing revenue and profit. At Hart Energy's recent Energy Capital Conference in Houston, two chief executive officers explained how they do it.

Rick Louden, co-chief executive officer and president of Argent Energy Trust, a Canadian trust with a structure similar to a master limited partnership, described a path built on cost per barrel of oil equivalent, or dollar per BOE. This is a way to make an apples-to-apples comparison when measuring the various cost centers (capital, finding and development, operating costs, and more). “The best apple to use is the barrel of oil,” he said.

Louden gave some examples of how the company converts costs into dollars per BOE. Like an MLP, a trust has a low cost of capital, while the cost of bank debt is low, as it is for everyone. In total, Louden figures Argent's cost of capital is around 8% to 9%.

“When I convert it I look at where it's going—for acquisitions and drilling—so basically it's going into F&D costs,” he said. “Let's say F&D is $30 per barrel for the average company, so 9% of that is $2.70 per barrel. This is a methodology to look at everything in terms of cost per barrel of oil.”

Louden's computations show that for a 70%-oil company, earning about $70 per BOE, the first bottom line will tally $11.40 per BOE.

But it is in the realm of corporate tax that a trust like Argent has the greatest advantage, as they have been given a separate tax treatment in Canada. While in 2006, the Canadian government changed the tax rules for the vast majority of trusts, it left unchanged its tax treatment of trusts that are based in Canada but have assets entirely out of Canada.

“As we look at the company, we're not only interested in maximizing profits to the corporation but also in maximizing the actual dollars to investors that will go into their bank account,” Louden said.

“The corporate tax can be eliminated or lowered quite a bit depending on a company's corporate structure and business plan. We IPO'd in August 2012 and over the next eight years we will pay just 1% or 2% in corporate taxes. And as long as we continue to drill and acquire, we can extend that.”

The reason? Like MLPs, Canadian trusts can save 60% of investors' tax consequences. Investors in non-MLPs or trusts might typically end up with $7.50 per BOE to put in their bank accounts, but trusts or MLPs take that same stream and end up with $10.16 per BOE.

“There's a 35% increase in dollars to investors by just changing the way we structure the business and plan in terms of taxes,” Louden said.

Another advantage: Unlike MLPs, trusts don't have to focus on having assets with 80% value in proved developed producing (PDP) assets. They can go after properties with 50% to 60% of PDP value and can buy proved undeveloped and probables as well. “We're targeting a different acquisition market,” he said.

Argent has begun the process of being listed on the NYSE, and expects listing in August or September of 2013.

The second speaker on the panel, EnerJex Resources Inc. chief executive Robert Watson Jr., described leading the company through a turnaround that began in 2010. Today it is growing through an oil-directed drilling program, with 126 wells drilled last year. The public E&P (OTC: ENRJ) devised some creative financing in the restructuring. And it has been driving down costs, which today are about $25 to $30 per barrel, versus about $50 per barrel when Watson took over the company.

EnerJex has three core assets, 100% oil: two enhanced oil recovery projects in Kansas and a technology exploitation play in Texas. But currently, the focus is Kansas, where the projects have a 50% internal rate of return. “The takeaway is we have a very repeatable, statistic type of risk. And we're smaller, we don't have to lay out big capital up front. The reservoirs are shallow and it doesn't take long to drill.”

The restructuring involved operational and balance-sheet moves. The company raised $5 million through a PIPE (private investment in public equity) offering of common stock and converted $2.7 million of subordinated debt to equity at 80 cents per share.

It sold noncore assets and did an additional PIPE for $3.5 million valued at 60 cents per share; it had a call to buy the shares back at 40 cents. It has not had to raise capital since, “so we're getting a lot of mileage out of our equity dollars,” Watson said.

The company also rebuilt and strengthened its relationship with its banker, Texas Capital Bank. The turnaround was complete by the end of 2011, and the company turned its focus to growth, deploying capital and recording record revenue, EBITDA and cash flow.

Watson's advice is to focus on value creation. “We were able to repurchase shares at a value that was compelling for shareholders and demonstrated our commitment to protecting and growing shareholder value,” he said.

The company was creative in its approach to refinancing projects. The partnership formed in 2011 allowed it to raise project-level capital and effectively

monetize wells. It had “stepped into an operating loss on its books,” said Watson, but since it planned to start development drilling, the present value of the net operating loss wasn't applicable for EnerJex. Through the partnership it raised $5 million of development capital, and pushed the intangible drilling costs (IDCs) to investors.

“We priced that financing at a 10% cost of capital to us, but investors received an after-tax return rate that was much higher. And we came out with ownership in a field that was making 25 barrels per day and now is making 275 barrels a day, with the opportunity to grow. We funded growth quickly without diluting shareholders. “

—Susan Klann

M&A consolidation on horizon as unconventional activity builds

The flurry of activity in unconventional resources during recent years will likely lead to a growing wave of consolidation in the coming years, according to a panel of M&A experts at Hart Energy's recent Energy Capital Conference held in Houston.

Sylvia Barnes, managing director at KeyBanc Capital Markets, said a series of market factors has encouraged M&A activity.

Commodity prices are a key driver of M&A activity. They affect liquidity and cash flows, enhance borrowing bases and have major implications for capital expenditures.

Record low debt costs have led to ambitious growth plans, both through acquisitions and organic growth.

“We've seen a lot of money come in an extensive way and there is more to come … but a lot depends on commodity prices,” she said. A shortage of new resource plays and a realization of the potential of the existing ones have led to renewed interest in M&A activity.

Finally, the cost of developing unconventional resources has created the need for capital resources among smaller players who are keen to form joint ventures to get financing, she said.

KeyBanc says many small-cap energy companies, those with less than $250 million in market capital, are struggling for financing. These companies draw little institutional interest, have little analyst coverage and low value for acquisitions, and are often thinly traded. KeyBanc has identified a market niche and seeks to serve the companies who fall into that category, Barnes said.

M&A activity peaked in the fourth quarter of 2012 but has slowed since then as the industry has faced growing uncertainty about the legality of hydraulic fracturing.

Although activity has slowed in the first half of 2013, Barnes said she sensed “pent-up demand” among many players.

Other panelists agreed that consolidation is likely, although not all agreed on how long the wave would last or what legal form it would take.

“Consolidation is going to happen. It's going to be a major part of our business for the next five to 10 years,” said R. Danny Campbell, president of Henry Resources LLC.

All major basins should see some consolidation; yet, the panel members were keenly focused on the Permian Basin, where well-capitalized majors left for the most part in the 1980s. Those that stayed behind were usually smaller independents as well as some larger independents that came in after the shale boom in the US rejuvenated interest in the Permian.

Today, many of the majors have cash on hand, or access to credit, and are willing to pay to get back in.

“They are all fascinated by these resource plays,” said H. Craig Clark, president and chief executive of Wishbone Energy Partners LLC.

The panelists generally agreed that the likely targets for acquisition are cash-constrained and asset-rich. Buyers, meanwhile, will be well-financed companies in search of resource plays—in many cases, the majors.

“They are all back knocking on the door,” said Campbell. “They are looking for assets and acreage.”

—Keefe Borden

Market confident in oil E&Ps; less so in natural gas companies

Investor sentiments improved for oil E&Ps, integrated services and drillers in second-quarter 2013, while confidence in $4 to $5 natural gas prices swelled, according to Bernstein Energy's Investor Sentiment Survey.

Overall, E&Ps gained support among respondents. However, oil gained as natural gas-focused E&Ps saw reduced interest.

Gas received a significant bounce in expectation, with 55% believing the next 12 months will bring gas prices averaging $4 to $5 per thousand cubic feet (Mcf). That's compared to the first quarter of 2013, in which 33% expected prices of $4 to $5.

In the first quarter, nearly two-thirds of respondents believed gas would average $3 to $4.

“Investors are evenly split between expecting gas prices in two years to be above and below $4.50 an Mcf,” says Bob Brackett, senior analyst for Bernstein Research. “Two-thirds expect prices somewhere between $4 and $5 Mcf, and 17% see two-year prices eclipsing $5 Mcf, up from 13%” in first-quarter 2013.

Investors, though, are especially keen on oil. They believe the energy sub-segment has the most upside over the next year. Integrated oils, drillers, construction and utilities also saw increased interest, though refiners declined significantly.

“After E&Ps, investor sentiment remains most supportive of the oil services,” Brackett said.

Sentiment for oil vs. gas E&Ps tend to fluctuate with commodity prices. Second-quarter results were divergent from this trend for oil E&Ps, however, “as sentiment improved even as the strip fell,” and in particular support for oil E&Ps coalesced toward the end of the survey period.

Nevertheless, since the fourth quarter of 2012, the overall view by respondents of oil services' upside has fallen. Second-quarter sentiment was below 30% compared to roughly 40% at the end of 2012.

In the more immediate term, remarks by Federal Reserve Chairman Ben Bernanke on June 19 appear to have dampened the overall market, Brackett says. Bernanke said the Federal Open Market Committee could slow the pace of bond purchases toward the end of the year if the economy continues to improve.

Survey responses before and after Bernanke's speech showed lower near-term expectations for both oil and gas prices. However, the magnitude of the decline was small compared to the standard deviation of responses, about $2 per barrel, Brackett says.

Long term, expectations among respondents are that prices will rise for natural gas, with the average two-year price up 13 cents to $4.51 per Mcf.

“The most popular response, representing 67% of polled respondents, continued to be in the $4-to-$5-per-Mcf bucket, with other responses distributed more towards higher expectations,” Brackett said. The survey was conducted from June 17 to June 21, during which the 12-month WTI forward oil strip traded at $91 per barrel and the gas strip averaged $3.94 per Mcf.

—Darren Barbee

Underground space enough to dump 500x U.S. CO2 emissions

The solution to handling carbon dioxide emissions may lie underground. The US Geological Survey (USGS) said in late June it had identified enough room underground to store more than 500 times the annual U.S. CO2 emissions.

Basins throughout the country have a potential 3,000 metric gigatons (Gt) of capacity, most of it located in the Gulf Coast. If liquefied, CO2 emissions captured at industrial and energy plants could be injected into the reservoirs, USGS officials said. The oil and gas industry is to thank for the storage locations.

Among other sources of data, the agency mined two proprietary petroleum databases from Neh - ring Associates and from IHS Inc. for a substantial amount of its data.

The USGS said the overall reduction of CO2 emissions will likely involve a combination of technologies. Capture of emissions is “an available technology because existing knowledge derived from the oil and gas production industries has helped to solve some of the major engineering challenges.”

“This USGS research is groundbreaking, because it is the first realistic view of technically accessible carbon storage capacity in these basins,” said Secretary of the Interior Sally Jewell. “If enough of

this capacity also proves to be environmentally and economically viable, then geologic carbon sequestration could help us reduce carbon dioxide emissions that contribute to climate change.”

Carbon sequestration is the process of capturing and storing atmospheric carbon dioxide. Annual US energy-related CO2 emissions were 5.5 Gt in 2011, according to the Energy Information Administration (EIA).

Existing oil in hydrocarbon reservoirs may be produced in the near future by using enhanced-oil-recovery technology that uses manmade CO, and then the reservoirs could be used for COstorage, the USGS said.

The agency said fossil fuel combustion will supply the dominant portion of total global energy demand in both industrialized and developing countries for the next few decades.

The study did not identify specific sites for COstorage, instead assessing capacity on a regional basis.

The Coastal Plains have the largest technically accessible storage resources, with a mean estimate of 2,000 Gt—including 1,800 Gt, or 91% in the Gulf Coast. Storage resources in the US Gulf Coast are near major population centers and industrial COsources and will likely be used for COstorage in subsurface formations in the near future.

The Gulf Coast is particularly attractive because of the sedimentation and the lack of fresh water, which prevented areas in the Rocky Mountains from being considered, USGS officials said.

The Alaska region for storage, with a mean estimate of 270 Gt, is chiefly centered in the North Slope. Alaska centers are in remote areas and may not be ready for some time. However, the North Slope petroleum industry may use these subsurface reservoirs for storage of COthat is co-produced with hydrocarbons, or stored during the enhanced-oil-recovery process using CO.

Additional work will be required to capture emissions, said Brenda Pierce, program coordinator for the USGS Energy Resources Program. COwould need to be captured from stationary sources, such as cement or power plants, and shipped to reservoirs via pipeline. COalso has to be compressed into a liquid prior to injection.

“It does take infrastructure to capture the COand then to pressurize it, because we're talking about liquid COwe're injecting into the ground,” Pierce said during a conference call. “It's not a one-to-one, but you can see we have significant potential compared to what we emit each year. We do need to do the studies (to determine) economic and … land or resource issues.”

—Darren Barbee

Antero Resources sets sights on IPO to bring reserves to surface

Paul Rady and Glen Warren plan to take public their Marcellus- and Utica-focused Antero Resources Corp. in a fund-raiser that is estimated to bring in some $1 billion. Proceeds would go toward paying $436 million of bank debt and further surfacing the company's roughly 26.1 trillion cubic feet equivalent (Tcfe) of gas, gas-liquids and oil reserves.

Rady, who is chairman and chief executive, and Warren, president and chief financial officer, founded the Denver-based shale player in 2002 after selling their three-year-old Pennaco Energy Inc.'s Rockies-focused gas portfolio to Marathon Oil Co. for $500 million in cash in 2001. In 2005, they sold their Barnett-shale holdings for more than $1 billion in cash and stock to XTO Energy Inc., now a business unit of ExxonMobil Corp.

Rady, who began his energy career as a geologist, and Warren, who began as a landman, worked for Amoco Corp.

After selling to XTO, they went to work on other shale plays with some of the proceeds and private-equity funding from Warburg Pincus LLC, Yorktown Partners LLC and Lehman Brothers Merchant Banking Group. The latter is now Trilantic Capital Partners.

Ultimately, their hunt led to a focus on the Marcellus in Appalachia. Last year, to further focus on its existing Marcellus and newer Utica-shale potential, Antero sold its portfolios in the Arkoma Basin to Vanguard Natural Resources LLC for $445 million and in the Piceance Basin to an undisclosed private buyer for $316 million.

Currently, Antero holds some 317,000 net acres in the Marcellus play and some 94,000 net acres prospective for production from the Utica, according to its S-1 filing. “In addition, we estimate that approximately 194,000 net acres of our Marcellus shale leasehold are prospective for the slightly shallower Upper Devonian shale,” the company said.

Year-end 2012 proved reserves were 4.9 trillion cubic feet equivalent (Tcfe), 21% proved developed and 75% natural gas. Antero estimates its leasehold offers more than 4,900 potential horizontal well locations. To date, the company has made 170 successful horizontal Marcellus wells out of 170 attempts and it currently has 15 rigs at work in Appalachia.

“We have begun to apply the expertise and approach we employ in the Marcellus shale to the Utica shale, and we believe we will be able to achieve similar success. We have drilled and completed eight horizontal wells in the Utica shale with a 100% success rate without encountering any faulting.”

First-quarter production averaged 383 million cubic feet equivalent per day, mostly gas, with the balance being gas liquids and oil. The company also owns and operates gathering pipelines and four

gas-compression stations.

Lead underwriters of the IPO are Barclays Capital Inc., Citigroup Global Markets Inc. and JP Morgan Securities LLC. Additional underwriters are Credit Suisse Securities (USA) LLC, Jefferies LLC and Wells Fargo Securities LLC.

—Nissa Darbonne

Billions in offshore projects could capsize rig builders

Global deepwater drilling is poised to take the plunge, with companies spending $114 billion by 2022 and presenting rig contractors with more work than they may be able to handle, according to an analysis by Wood Mackenzie.

Spending for wells in 2012 was $43 billion, returning global drilling activity to pre-Macondo highs. Wood Mackenzie forecasts robust deepwater activity at an overall compound annual growth rate of 9% for the next decade.

However, meeting the demand will require billions of dollars in investment, careful planning and adding many tens of thousands of workers.

Malcolm Forbes-Cable, senior management consultant at Wood Mackenzie and author of the study, noted that deep water has discovered 41% of volumes and created $351 billion in value over the last decade, eclipsing the performance of onshore and shelf activity.

The 20 leading deepwater players grew deepwater and Arctic net acreage licenses by 39% in 2012.

“Deep water has accounted for increasing levels of discovered volumes over the last decade. However, this has not been without increasing technical and commercial challenges,” Forbes-Cable said.

Exploration, appraisal and development wells will increase by 150%, to 1,250 wells per year from 500 today by 2022. But to meet the forecasted well demand, an additional 95 deepwater rigs will have to be constructed between 2016 and 2022 at a cost of $65 billion, Forbes-Cable said. Currently, 90 rigs are on order.

Between 2009 and 2014, yards will deliver an average of 24 rigs per year. Existing capacity is therefore substantial, and with new capacity coming on in China and Brazil, it would seem the market is well equipped to deliver rigs to meet demand, the report said.

“This will require the longest period of deepwater rig construction to date, representing a change for the deepwater sector from cyclical to sustained growth,” Forbes-Cable said.

An estimated 37,000 additional workers will be needed over the next decade to meet existing rig orders and new-builds required to meet demand, Wood Mackenzie said.

With current personnel and historical rates of recruitment, meeting that goal poses a significant challenge for the sector, Forbes-Cable said.

Offshore drilling has been active as more equipment orders and generally stable-to-higher dayrates continue.

Tudor, Pickering, Holt & Co. said in late June that orders for offshore jackup newbuilds were brisk, with 37 ordered in 2013. The peak year for jackup orders was 2011.

The “industry is undergoing a replacement cycle, but after watching deepwater rates plateau, investor skittishness on drillers likely spills over into the jackup market still seeing dayrate increases with this level of new-build activity,” the firm said.

Ultradeep drillers are also reaping solid dayrates, according to James Crandell, an analyst and managing director for Cowen and Co.

Rowan Companies said in late June it had entered a three-year contract with Anadarko Petroleum Corp. for the Rowan Resolute, one of four new ultradeepwater drillships being constructed by Hyundai Heavy Industries Co. Ltd. Dayrates will range between $606,000 and $609,000, including mobilization revenues. Some analysts had expected the rates to be slightly higher.

National Oilwell Varco has experienced an increase in floating production storage and offloading (FPSO) vessel equipment orders in the second half of the year, Crandell said.

In total, the company expects to receive about $1 billion in orders for new FPSOs this year and realize $500 million in revenues for 2013. NOV expects about 150 to 200 FPSO orders in the next five years.

“National Oilwell Varco is pushing up prices at (subsidiary) Rig Tech across the board,” Crandell said. “After a period of price stability, there is a strategic push to get prices up as part of an effort to get Rig Tech margins to 25%.”

Crandell also noted the Gulf of Mexico jackup market is still tightening. He cited Hercules Offshore, which had one dayrate of $107,000 per day, up from $102,000 per day. That compares to Crandell's modeled $104,000 per day.

—Darren Barbee

Rail delivery of US crude, petroleum products is on the rise

Crude oil and refined petroleum products delivered by rail totaled close to 356,000 carloads during the first half of 2013, a 48% increase from the same period in 2012, according to a report by the Association of American Railroads (AAR).

Yet, despite the increase, a lack of railcars – some estimate a 60,000-car backlog – could be thwarting potential growth, the AAR stated.

The amount of crude and petroleum products shipped by rail was 1.37 million barrels per day during the first six months of 2013, up from 927,000 barrels per day in the first half of 2012. US weekly carloads of crude and petroleum products averaged nearly 13,700 rail tankers during the January-June 2013 period.

Crude oil accounts for about half of those 2013 daily volumes, according to the AAR. While the report does not differentiate between crude oil and petroleum products, the AAR generally thinks that the majority of the volume moved in the 2006-10 period was petroleum products, and that most of the increase since then has been crude oil.

Although the amount of crude moved by rail has increased, not even 10% of the crude oil produced daily in the US is transported via rail. About 700,000 barrels per day of crude oil—including both imported and domestic—is delivered by rail. Daily crude production in the US is 7.2 million barrels, according to the latest statistics from the US Energy Information Administration.

The surge in crude oil production from North Dakota, where adequate pipeline to move supplies is lacking, accounts for a large share of the increased deliveries of oil by rail. North Dakota is the second-largest oil-producing state after Texas, as advanced drilling technology has opened up millions of barrels of tight oil in the Bakken shale formation.

More Bakken crude oil moving to market by rail has helped narrow the difference between Bakken crude and Brent crude spot prices to less than $5 per barrel, the smallest gap in 18 months, the AAR stated. “The narrower spread reduces the incentive to ship oil to coastal refineries,” the report says.

—Annie Gallay

Signal Hill squeezes more out of legendary Long Beach Field

The signal-to-noise ratio is improving for Signal Hill Petroleum Inc. as the California company looks to extract more oil from the legendary Long Beach Field, which has generated more than 1 billion barrels of oil out of roughly two square miles of real estate during the last 90 years.

“There is a lot more oil in this area that hasn't been found,” Craig Barto, chief executive for Signal Hill, told attendees at the midsummer meeting of the Independent Petroleum Association of America in Dana Point, California.

After more than 1 billion barrels, one might ask what could possibly be left in the field, which at one time had a reputation for producing more oil per acre than any other real estate parcel in the world. The answer has been found through a novel 3-D seismic program, conducted in the heart of a densely settled urban area in 2012, to map the numerous folds, faults and conventional traps along the Newport-Inglewood

fault zone in the giant sandbox that is the Los Angeles Basin.

Additional opportunities may lie deeper in the Monterey shale, where Signal Hill plans to drill a third test later this year. “We know there is a heck of a lot of oil down there. The question is: How do you get it out the best way?” Barto said.

Signal Hill Petroleum is a privately held firm that opened its doors in 1984. The company grew by buying out the interests of majors such as Texaco, Arco and Shell in the Long Beach Field as the majors looked for better opportunities elsewhere.

The company currently produces 3,000 barrels of oil per day from 300 active wells in Long Beach Field. As old wells play out, the company adds new wells through infill drilling, or re-drilling efforts, operating in a densely settled urban environment on one-year permit extensions.

Like most mature fields, the Signal Hill field experiences a substantial water cut and the company recycles produced water through the reservoir as an enhanced recovery technique. In all, the company generates 90,000 barrels of water per day, which is re-used to sustain oil production and alleviate subsidence issues resulting from mineral and water extraction.

The company has adapted its operations to fit within the confines of a major metropolitan area. It built two custom drilling rigs that operate on 12-hour schedules versus the typical 24-hour protocol. Both rigs feature Tier 4-compliant clean diesel engine packages and electric mud pumps to minimize noise and emissions.

Unlike other areas of Los Angeles where drilling operations are housed in Potemkin-like buildings, Signal Hill conducts its drilling operations on outdoor pads. Special formulas for drilling mud enable the company to rework drilling fluids to proper consistency as each new drilling shift begins.

Barto's encouraging comments on the Monterey shale were echoed by fellow panelist William Albrecht, president of Oxy Oil and Gas Americas.

“We've made a lot of pro - gress,” Albrecht said of the Monterey shale. “We don't have it figured out yet. But we're very positive on the lower Monterey as evidenced by the acreage position we built out here to take advantage of that. One of the big challenges in the lower Monterey is the differences in the lower Monterey offshore California, where it is more thermally mature, more brittle, easier to frac. As you move onshore that changes. It becomes more elastic, a little bit like Play-Doh. But we've got some of our best and brightest minds on this and we are making a whole lot of progress.”

The IPAA meeting took place during the anniversary of the Alamitos #1, June 23, 1921, which was the discovery well in Long Beach Field. That 600-barrel-perday well generated an ultimate recovery of 700,000 barrels, a size that is still enough to move the stock price of companies in horizontal tight-formation oil plays.

The Long Beach Field still produces 1.5 million barrels of oil per year.

—Richard Mason

For more coverage from the IPAA meeting, see OilandGasInvestor.com.