Macquarie Tristone: Energy lenders see slight move

Banks are adjusting their price forecasts as commodity prices continue to rapidly fluctuate, according to Macquarie Tristone’s “Quarterly Energy Lender Price Survey” of 34 participating regional, U.S. national and international banks that engage in reserve-based lending.

For 2013, the second-quarter survey indicates a mean base-case West Texas Intermediate (WTI) oil price forecast of $76.44 per barrel and a mean base-case Henry Hub gas price forecast of $3.17 per million Btu. The report’s survey of Brent-based oil price forecasts shows a mean base case of $79.25 per barrel.

The five-year trend shows a decreasing forward price deck for oil and increasing forward price deck for gas, with average 2017 oil and gas price forecasts of $75.93 per barrel, $76.99 per barrel and $4.61 per million Btu, for WTI, Brent and Henry Hub, respectively.

Modest escalation of oil and gas prices after 2017 is common, but prices are capped at means of $75.09 per barrel and $4.57 per million Btu, respectively. The average discount rate used by participating banks is 9%, unchanged from last quarter’s average.

Operating costs on average are escalated 0.3% per year for WTI, 1.3% for Brent and 0.4% for Henry Hub.

The firm compared the average base case against Nymex futures pricing as of April 15, 2013, with results for WTI averaging 86% of Nymex futures in 2013, and results for Brent averaging 89% of the exchange’s WTI futures in 2013; the average base case results for WTI and Brent increase to 88% and 90%, respectively, in 2017.

Quarter-to-quarter pricing trends. Compared to last quarter’s survey, front-year pricing decreases by 0.5% for oil and increases by 2% for gas. In the later years, forecasts for both oil and gas prices in the fifth year decrease by 0.8%.

Sensitivity case results. The second-quarter survey also includes a sensitivity case, which represents the lenders’ low or conservative price decks. Of the 34 participating banks, 28 banks provided a sensitivity case for WTI and Henry Hub, which averages a 20% discount to base case lending policies for oil and a 17% discount for gas over the five-year strip. Three banks provided a sensitivity case for Brent, which averages an 18% discount to the base case pricing over the five-year strip.

Macquarie Tristone is a global energy advisory firm providing fully integrated investment banking, acquisitions and divestitures, and global equity-capital-markets services. For more information, contact Andrea Yuen at 713–651–4206.

Barclays: Midyear spending outlook supports bullish 2014

A Barclays midyear update to its annual spending survey reflects an increasingly positive global spending outlook. Its analysts now forecast that global E&P spending will reach a new record of $678 billion in 2013, up 10% from 2012 and an increase of over 300 basis points from its December 2012 survey.

“This represents the fourth consecutive year of double-digit worldwide spending gains since the 2009 downturn,” Barclays says.

Companies have hiked their capex budgets notably in the Eastern Hemisphere and modestly for North America. International E&P spending is now forecast to rise 13.2% (versus Barclays’ initial forecast of more than 9%). North America spending projections have climbed by 2% (versus a December forecast for flat year-over-year spending levels).

“We believe the sizable improvement in E&P spending forecasts is due to significant increases in planned activity levels in the Middle East and Asia. Of note, PetroChina is now anticipated to be the largest spender on E&P in the world in 2013, overtaking Exxon, which has held the top spot since spending data began to be collected in the mid-1980s,” the analysts note.

Companies are basing their 2013 E&P spending budgets on Brent oil prices of $101 per barrel, West Texas Intermediate prices of $86.5 per barrel, and U.S. natural gas prices of $3.62 (Henry Hub), up only modestly from forecasts in December and below current prices (as of early June).

International exploration is drawing more dollars than ever. It is now expected to rise 13.2% year-over-year, reaching a record $490 billion. While Latin America growth has slowed and is expected to rise just 12%, Middle East spending budgets have swelled by 28% (compared to 11% previously). Companies also project solid gains in budgets for India, Asia and Australia (currently expected to rise 19% versus 11% in the December survey).

“The improvement in the Middle East is primarily driven by higher spending forecasts for Saudi Aramco and in Iraq, while in the Asia Pacific, the increases are mostly due to higher budgets from the Chinese majors,” the analysts say.

In the U.S. onshore, activity is recovering, up 2%, but remains uneven. Still, Barclays says its updated outlook reinforces its “positive stance” and that its initial 2014 outlook is additionally robust.

“We continue to believe the industry is in the early stages of a long, sustained and powerful global upcycle with steady spending growth in the international and offshore markets and rebounding activity in North America,” the report says.

“The E&P spending outlook for next year is starting to take hold, and we anticipate further substantial gains internationally, more oil-related activity, and the start of a natural gas cycle in North America.” This positive outlook is underscored by companies’ budgets: only 6% anticipate a decline in 2014 E&P spending.

—Susan Klann

Ernst & Young: Despite lower profits, U.S. E&Ps spent more in 2012

Exploration and production capex rose to $185.6 billion, a new high, in 2012, according to Ernst & Young’s sixth annual oil and gas reserves study. The study analyzes U.S. upstream spending and performance data for the 50 largest companies based on 2012 end-of-year oil and gas reserve estimates.

Total capex in 2012 was 20% higher than in 2011. Meanwhile, all categories of spending rose in 2012, with the largest increases in development spending (21%) and proved property acquisitions (17%), according to the study. “Spending for proved properties rose from nearly $14 billion in 2011 to $21.6 billion, while spending for unproved properties reached $33.8 billion in 2012.”

BHP Billiton led the pack in both proved and unproved property acquisition costs for fiscal year 2012 due to its acquisition of Petrohawk Energy, which provided BHPB with company-operated resources in the Eagle Ford, Haynesville and Permian plays. BHPB also reported the largest increase in combined E&P spending, followed by Royal Dutch Shell, Apache Corp. and Marathon Oil.

Large independents accounted for the biggest rise in combined exploration and development spending (36%). “This group accounted for 48% of total capital expenditures, compared with 29% of the independents and 23% for the integrateds,” according to the study.

Meanwhile, integrateds increased their spending by 20%, and smaller independents increased theirs by just 1%. “As the smaller independents’ reserves are generally more weighted toward natural gas, the low gas prices throughout much of 2012 had a substantial impact on their cash flows and spending ability.”

Although companies spent more on E&P last year, and total oil and gas production increased 7%, profits were down by a whopping 58%.

Increased production “could not compensate for the $26.4 billion in property impairments recorded due to low natural gas prices,” according to the study. “These impairments, paired with a price-driven 3% decrease in revenues and increases in other costs, contributed to a 58% fall in aftertax profits for study companies.”

Low natural gas prices also resulted in downward revisions of 29.3 trillion cubic feet (Tcf) in 2012 and contributed to a 10% decrease in gas reserves, according to Ernst & Young. Furthermore, the all-sources gas production replacement rate was only 42% in 2012, despite strong extensions and discoveries of 24.6 Tcf.

It also became more expensive to find new reserves.

“The cost to find and develop new reserves surged to $45.03 per barrel of oil equivalent in 2012, reflecting not only the increased spending but also the substantial downward revisions of natural gas reserves as a result of low natural gas prices,” according to the study.

—Caroline Evans

Stacked-pay potential turns Powder River Basin into powder keg

First-quarter enthusiasm surrounding the stacked-pay potential of the Powder River Basin, historically a coal- and coalbed methane-producing reservoir, is entirely justified, according to a recent report by Wells Fargo Securities. The report, “E&P: Powder Keg in the Rockies Redux,” revisits a March 2012 Wells Fargo report on the basin.

“With its history of vertical oil production, it was only a matter of time before operators got more aggressive,” the analysts say. With companies such as Chesapeake Energy, Devon Energy and Samson Oil & Gas leading the way over the past few years, “that is exactly what has happened.”

Despite some disappointing well results in the Niobrara, the oil-bearing shale formation in the basin, the Shannon and Sussex formations, which lie above the Niobrara, and the Frontier/Turner, which lies below it, have provided “encouraging well results from numerous operators throughout the stacked-pay column,” according to the report.

The Frontier formation’s initial production (IP) rate, at 1,424 barrels of oil equivalent (BOE) per day, was nearly three times that of the Niobrara’s 500 BOE per day. The Sussex and Shannon each had an IP rate of 725, also greater than the Niobrara’s. Add in the fact that the Shannon and Sussex each have lower well costs than the Niobrara, and the formations look even more attractive.

Furthermore, operators in the basin have shifted their emphasis from gas-focused drilling for coalbed methane to deeper oil plays over the past few years. The shift could account for the production increases EOG and Chesapeake have seen in recent years, the analysts say. The report lists 16 companies that operate in the Powder River Basin; of those operators, only EOG, Chesapeake and Bill Barrett have increased production, with Barrett “likely inflated by divested coalbedmethane production.”

Still, the production numbers are not “predictive of a company’s acreage position or anything else for that matter,” according to the report. “The more important metrics will obviously be well results, core tests, geology, if current wells hold up, etc.”

The report cites permitting as one of the major challenges facing operators in the Powder River Basin, “with scattered portions of federal and state acreage dotting the most prospective acreage. Operators have said the landowners are generally cooperative, but with the slow process of federal permitting, operators have emphasized the heightened need for forethought and planning.”

The federal permitting process is expected to slow even more as a result of sequestration cuts to Bureau of Land Management funding. Cuts could result in 300 fewer drilling permits in Wyoming, Utah, Colorado and New Mexico, and “for the Rockies in general, we have heard permitting time is now 400 days in the Bakken.”

Another challenge is a lack of midstream infrastructure. Crude could be limited by gas-processing capacity, but “there is clearer line of sight into the crude infrastructure due to PRB’s coal heritage and thus its rail infrastructure,” according to the report. “However, crude loading terminals are likely to be the choke point and permitting for these facilities could pose a challenge.”

Despite these setbacks, the report still asserts that the Powder River Basin “was one of the overlooked highlights of [the] firstquarter 2013 earnings season.”

—Caroline Evans

Tax breaks spark development in Alaska; BP spends $1 billion

A new law that saves the energy industry millions in taxes is generating more oil and gas activity on Alaska’s North Slope, including a $1-billion investment from BP. The state is working to reverse declining North Slope oil production, which has plummeted from its peak of about 2 million barrels per day in 1988 to less than 600,000 barrels daily, according to U.S. Energy Information Administration (EIA) data.

BP credited the state’s recent tax reform for spurring its investment plans for Alaska. Within the next five years, the company plans to add two drilling rigs to its North Slope fields in Prudhoe Bay. The first rig should be in place by 2015, followed by the second in 2016, increasing BP’s Alaskan rig fleet to nine.

Also, drilling work is expected to ramp up by fourth-quarter 2013, and existing facilities are set for upgrades to boost well performance at Prudhoe Bay and Milne Point fields, BP said.

The company’s Alaska operations—specifically the west Greater Prudhoe Bay area—could benefit from an additional $3 billion. BP said it has gained support from other working interest partners to evaluate improvements to eliminate bottlenecks at existing Prudhoe Bay facilities, building a new drilling pad, and possibly drilling more than 110 new wells. The multiphase development would span 10 years, with the first two to three years dedicated for appraisal work.

Moreover, BP is teaming with others to commercialize the North Slope’s gas resources as part of a South Central LNG project.

While the incentives, which became effective May 22, increased the base tax rate for production from 25% to 35%, the state eliminated the progressive surcharge portion of the production tax and made available other incentives that could further reduce the rate. These include a credit of $5 per taxable barrel against a producer’s production tax liability for oil produced from certain eligible areas, a credit of 10% of qualified service expenditure, and an exploration credit for areas outside the North Slope and Cook Inlet, according to the bill’s fiscal note analysis.

While the changes have been welcomed by the industry, they have drawn opposition from those seeking to repeal the law. The analysis shows the impact of the change could range from a minimum of some $670 million in fiscal- year 2014 to a maximum of some $815 million in 2019. Others believe the reform is needed to help reverse declining production numbers.

In a weekly oil message on the issue prior to the bill’s passage, Alaska Gov. Sean Parnell said, “When it comes to the current tax structure, the facts speak for themselves. Alaskan oil production is declining at nearly 6% per year. We have fallen behind both Texas and North Dakota and risk falling behind California if we continue to accept status quo decline. We need a good Alaska comeback.”

Another effort that is under way to improve development focuses on Alaska’s unconventional resources. The U.S. Department of Energy (DOE) has said Alaska’s North Slope could have as much as an estimated 25 billion barrels of viscous oil in shallow sands. The area also is believed to have about 85 trillion cubic feet of potentially recoverable gas in the form of methane hydrates, based on U.S. Geological Survey (USGS) estimates.

In April the Alaska Department of Natural Resources and the DOE’s Office of Fossil Energy signed a memorandum of understanding to strengthen R&D collaboration and information sharing between the two agencies.

—Velda Addison

Canadian Bakken does not equal U.S. counterpart

Canada’s Bakken is not the same as the mighty Bakken shale in the U.S. Bakken wells in Canada are shallower and have shorter laterals than U.S. Bakken wells, costing far less. Most of the Bakken wells in Canada are found in localized pools, while the U.S. play is widespread. That means estimated ultimate recoveries (EURs) in Canada are a lot lower, according to Gibson Scott, director, energy research, ITG Investment Research, New York.

“I have found a common thread among many of our clients in their beliefs that all the Bakken is created equal. Operators tend to represent the Bakken as one play type, and as a result, investors are often misinformed about the differences between the U.S. and Canadian plays,” he told participants at the Hart Energy DUG Bakken and Niobrara conference in Denver in late May.

“The difference is because the oil found in Canada was in fact generated on the U.S. side of the border and migrated updip to structural and stratigraphic traps,” he said. “If you think about it, billions of barrels of oil escaped the kitchen or the oil-generating window millions of years before the U.S. banned oil exports in 1975.”

And the differences are striking. At Viewfield Field in Saskatchewan, which is the largest horizontal Bakken development in Canada, the wells cost an estimated $2 million each, the average EUR is 110,000 barrels of oil equivalent (BOE), the average true vertical depth (TVD) is 4,950 feet, and the average lateral length is 1,500 meters. Completions consist of 18 stages.

On the U.S. side, the numbers rise dramatically. Wells cost an average of $10 million and have EURs of 500,000 BOE. The wells are 3,000 9,900 feet TVD with 3,000-meter laterals. There are 28 stages in each completion.

“Obviously, the Canadian play is much less prolific, but it is also a lot cheaper to drill. When you combine the aerial extent of the U.S. play with the outsize productivity per well, its total deliverability dwarfs that of the Canadian Bakken,” he said. “This flood of light oil has pretty significant implications not only for the pricing of U.S. and Canadian Bakken oil, but also the pricing of all Western Canadian Sedimentary Basin and PAD IV crude oil.”

The differences in the plays are shown in production. Total production from the U.S. play has surpassed 800,000 barrels daily, while the Canadian Bakken is some 100,000 barrels per day. “More importantly, annual production growth out of the U.S. play has averaged about 53% during the past three years, while the Canadian Bakken play has only grown by about 7% per year,” Scott said.

The U.S. play is largely found within the hydrocarbon-generating window of the Bakken play. Much of the Canadian Bakken is found outside the thermally mature window.

“As you climb the walls of the basin you begin to leave the kitchen, and that changes the exploration model significantly,” Scott noted.

“Most Canadian development occurs in isolated pools and is not widespread across southern Saskatchewan. Bakken wells on the U.S. side of the border produce oil but the distribution is much more regional in extent. Development is widespread across a footprint that covers 10 million acres.”

Historically, activity in the U.S. Bakken was concentrated in Sanish and Parshall fields, where a better quality Middle Bakken rock allowed industry to do more with less. “Today, most of the activity is taking place west of the Nesson Anticline. The Middle Bakken is thinner and tighter in this area. The industry is really having to push the technical envelope to extract commercial quantities of oil,” Scott said.

He pointed out that the most significant inputs to an economics model are wells costs and productivity, which are very different in Canada than in the U.S.

As the industry marches west into tighter and poorer quality rock, it has had to adapt its completion design accordingly. In 2009, the average well in the U.S. play was drilled with a lateral length of 6,900 feet and stimulated with 1.9 million pounds of sand in 16 stages at a cost of $6 million.

In 2012, the average U.S. Bakken well ran 9,300-foot laterals and was stimulated with 3 million pounds of proppant in 30 stages for an expected well cost of more than $9 million.

On the Canadian side, costs have risen from about $1.6 million per well two years ago to about $2 million now. Crescent Point and PetroBakken, the two dominant operators in Canada’s largest two Bakken developments, have had to change drilling and completion designs as well. The former switched completion methods in 2011 to 25-stage, cemented liners. As a result, costs climbed.

“PetroBakken has gone through several iterations of drilling and completion design. Today, the company employs a dual-lateral well with each leg stimulated in about 15 stages at a total well cost of about $2.9 million,” he said.

Scott said his company uses well cost estimates by region and over time to estimate the West Texas Intermediate (WTI) price required for wells to break even. The lower drilling and completion costs of the Canadian Bakken wells result in a much more favorable ranking among the various areas.

“As it turns out, lower productivity is more than offset by lower well costs. On a production weighted basis, the average breakeven of the Canadian Bakken is about $60 per barrel WTI compared to $65 per barrel for U.S. Bakken crude on average,” he said.

—Scott Weeden

Bernstein: 'Either prices must rise or costs must fall'

An analysis of financial and production metrics of the 50 largest publicly traded oil companies by Bernstein Research reveals that cost inflation has not abated for producers. At the same time, surging non-OPEC oil and liquids production as well as U.S.-driven natural gas oversupply are keeping a lid on commodity prices. The result: Net income margins for the group are at the lowest levels in a decade.

The shale and tight-oil revolution, largely based in North America, isn’t resulting in lower commodity prices because oil prices are set “not only by spare capacity (a function of supply and demand), but also by marginal cost of production,” the report notes. Further, producers’ efforts have boosted their reserve bookings.

“Increased North American production and weakening demand in China have conspired to keep supply and demand in balance and oil prices flat,” say the report’s authors, led by Neil Beveridge. “This is not sustainable. Either prices must rise or costs must fall.”

The analysts looked at production costs; cash costs; unit costs; organic finding and development costs; marginal cost of production; and cash cost of production.

The results show that net income margins for key non-OPEC producers have shrunk to decade lows—22%. Production costs rose by 5% year-over-year to $22.64 per barrel in 2012, while unit costs reached $39.70 per barrel of oil equivalent, “the highest ever as DD&A and exploration expenses continue to rise at double-digit rates,” the analysts say. They expect the trend in cost inflation and DD&A to continue.

Reserve additions for 2012 were “disappointing, with overall reserve replacement at 109%.” On the other hand, reserve replacement costs rose a hefty 45% over the year previous, to $22.30 per barrel of oil equivalent. “Despite the arrival of shale, it continues to get tougher to add barrels,” the authors say.

This outlook underpins the analysts’ stance that oil prices won’t drop in the long term, although there may be blips short term. “The marginal cost of non-OPEC production has increased from $92.30 per barrel to $104.50 per barrel of oil equivalent, up 13% from the year previous,” they say. They expect oil prices over the near and medium term to remain flat.

Another fall-out from this scenario: Capex will falter in tandem with pared cash flows, slowing the production machine.

“As long as oil prices stay flat and costs continue to rise, it will be impossible for the industry to sustain current levels of capex and growth,” Bernstein says.

—Susan Klann

Foreign shale markets motivated but lack skilled labor, regulation

Although assessments from the Energy Information Administration (EIA) and the USGS on international shale-gas reserves should offer strong motivation for countries to quickly develop cheaper, more reliable and more abundant supplies, it hasn’t happened.

A Raymond James Global Research report indicates that “the delays are a function of regulatory/ political hurdles, constraints in availability of rigs and skilled labor, along with general inertia.”

According to a USGS world petroleum assessment, “The energy struggle (outside of the U.S.) is economic, political, and technological, and is waged on the field of uneven geologic distribution of energy resources.

“The ongoing struggle for energy has been manifested in a military conflict in the Middle East, political struggles in the Former Soviet Union, and financial struggles throughout the world.”

The Raymond James report quoted a 2011 EIA assessment that indicated that there is 5,760 trillion cubic feet (Tcf) of recoverable shale gas, excluding the U.S., Russia and most of the Middle East. Almost every country in Europe is a net gas importer “with historically high dependence on Russian supply and, increasingly, liquefied natural gas from overseas,” yet there is an estimated 639 Tcf in Europe.

Most major oil companies and numerous E&Ps have acreage in Europe and China, and more recently Argentina and South Africa.

“We think the next two years will be more eventful than the past two, but don’t count any of these chickens until they’re hatched,” the report said.

Bans on unconventional techniques make headlines, but they are not the sole source of underdevelopment. There are only 70 onshore rigs in Europe (vs. more than 1,700 in the U.S.); 18 European countries have permitted some unconventional activity, but acreage of interest is almost always near a population center; and pre-development (i.e., seismic) is far behind when compared with the U.S.

The report provided some country-by-country status.

Europe

France, Spain. France has potentially the largest shale-gas resource (180 Tcf estimated) but a ban was enacted in 2011.

In Spain, estimates indicate 72 Tcf is available and about 200 wells have been drilled in the north. The government is concerned that it cannot stop a nationwide ban.

Poland. Silurian shale has received the most attention and drilling results haven’t been overwhelming, with only 10 of the 30 wells fractured. A recent study has reduced the estimated shalegas volume by a factor of 10, and infrastructure and proposed taxes would increase prices.

Ukraine, Romania. Shell has a deal for Ukrainian development but results aren’t expected until 2015. A Chevron deal has met resistance from “local opposition parties,” and no timelines have been announced.

Chevron has interests in Romania’s Bariad block, but the first exploration well won’t happen until late 2013.

U.K. The government supports development. A geological survey from 2011 indicates 5.3 Tcf of reserves. One active company, Cuadrilla Resources, recently announced that commercialization is not realistic until at least 2015.

China

China has more estimated reserves than the U.S. Its dependence on coal, an “old-fashioned nationalism” for coal, a lack of shale technology and infrastructure, and bureaucracy will make shale-gas development slow.

Argentina, South Africa

Argentina has an estimated 774 Tcf of gas. Repsol YPF’s investments were nationalized by the state in 2012, making any potential partners wary. However, the country’s central bank recently created a $2-billion fund for Vaca Muerta development.

South Africa, with great potential, does not have significant gas market demand and currently imports mostly from Mozambique. Shell, a major acreage holder, has said that commercialization is not realistic until 2020.

—Larry Prado

Barclays on shale's economic effect: 'The best is yet to come'

For all the hype about job growth and energy independence surrounding increased oil and gas activity in the shale plays, the overall effect to date to the U.S. economy is modest at best, say analysts with Barclays Capital Inc. But the best is yet to come.

“Dramatic changes in U.S. energy markets as a result of the revolution in oil and natural gas drilling technologies have led to a direct—albeit modest—boost to U.S. GDP (gross domestic product) and industrial production,” says Dean Maki, economics research analyst for Barclays, in a mid-May report on U.S. shale energy and equity market effects.

Job growth and GDP will continue to rise due to increased oil and gas activity, he says, “with the effects likely to grow over time.”

The oil and gas boom has had a positive impact on several macroeconomic indicators, including trade, industrial production, employment and inflation.

The U.S. trade deficit for petroleum products declined 1%, from 1.9% of GDP in fourth-quarter 2005 to 0.9% in first-quarter 2013, “the largest factor in narrowing the overall real trade deficit,” according to the report. Likewise, increased oil and gas drilling has gained ground as a percent of industrial production from “low single digits” in fourth-quarter 2009 to 10.3%.

Employment generated by oil and gas extraction, support activities and pipeline construction has grown by more than 260,000 jobs since the end of 2005, compared with overall U.S. employment growth of 618,000 in the same period. “Still, these direct effects are modest relative to the current pace of labor market improvement,” which is currently adding some 173,000 overall jobs per month, compared with 3,000 in the oil and gas sector.

Indirect effects of increased drilling are anticipated from expected lower energy prices, including more discretionary funds to spend for households and businesses, and cost advantages that motivate firms to locate in the U.S.

“The U.S. manufacturing sector is the primary beneficiary of these cost savings.”

So far, the analysts say, “the positive effects on GDP and employment growth of shale drilling appear to be modest.” However, “there is good reason to expect them to grow larger in the coming years.” They cite jobs from nearterm construction of liquefied natural gas (LNG) facilities, investment spending by manufacturers expanding in the U.S., and incremental effects of lower electricity prices resulting from lower natural gas costs.

—Steve Toon

Integrated vs. indie: Debate continues over which strategy is best

Should integrated majors split their operations to focus on their respective strengths, or does integration itself give the company efficiencies and market intelligence that it would not otherwise have? As major oil and gas corporations split and others consider the same path, the debate continues. Panelists discussed the pros and cons of each business model at a recent conference organized by KPMG’s Global Energy Institute.

Garry Peiffer, executive vice president of business development at Marathon Oil Co., said the company split its upstream and downstream operations in July 2011, but the debate within the company to take that step dates back to the mid-1990s.

Back then, many downstream companies were struggling and joint ventures were a common legal structure for diversifying the risk of refining. Marathon formed a joint venture with Ashland Corp., Marathon-Ashland Corp., to cope with the challenges from 1998 to 2005. In 2005, Marathon bought out Ashland’s 38% stake in the joint venture for $4 billion, Peiffer said.

By the mid-2000s times were good for refiners, but the mixed business model made it hard for investors to discern Marathon’s exact strategy. Was the company primarily an upstream or a downstream operator? The answer, for many investors, wasn’t clear, and management thought the confusion was reflected in the company’s share price, he said.

In an attempt to add value for shareholders, in July 2008 Marathon’s management announced it would separate the downstream from the upstream operations. “We wanted to see if the sum of each part was greater than the whole at that time,” Peiffer said.

For the board of an integrated Marathon Oil, the company’s downstream segment was almost an afterthought. About 10% of the integrated board’s time was spent talking about the downstream segment, although that segment accounted for about half of the company’s earnings for a portion of those years.

“We thought if we split the business apart, we would have better focus by both boards,” he said. By this time, Marathon’s downstream operations, as a portion of its total operations, were twice the size relative to its peers.

The financial crisis and recession took hold and those plans were put on hold in February 2009. The company resumed its plans to split the two businesses in January 2011.

The separation has had other benefits. Management now finds it easier to retain employees because they know the company’s focus and the incentive plans are clear.

Another company, Valero Energy Corp., took the decentralization process one step further, spinning off its retail segment entirely in May 2013, according to Clay Killinger, senior vice president and chief financial officer at CST Brands, the renamed retail business.

Valero spun off the retail division for the same reasons that Marathon spun off its downstream operations, Killinger said. Each management team now has the freedom to focus on its respective business, so there is no competition for capital between each segment. The retail segment produced about 10% of the company’s total EBITDA (earnings before interest, taxes, depreciation and amortization) before the two split, he said.

Valero’s management believed that splitting the two would give investors additional value. As a general rule, retailers trade at around 8.5 times EBITDA. Refiners generally trade around four times EBITDA. “The sum of the individual parts is greater than the whole in our case,” he said.

But not all energy executives agree with the strategy. Jay Pryor, vice president of business development, Chevron Corp., said the integrated company has no plans to split up in the near future. “For our type of company and for what we do, we find the integration accretive,” he said.

In 2012, Chevron Corp. as a whole reported $26 billion in earnings, but only about $4 billion came from the company’s downstream operations. Although it is a small percentage of the company’s overall earnings, that $4 billion in refining profits is enough to place it in the top 50 companies of the Fortune 500, he said.

The company’s integrated operations bring dozens of hidden benefits. In Nigeria, to cite one example, Pryor said the company needed a flaring solution in one of its upstream operations. Rather than hire outside consultants, the company borrowed the expertise of its downstream engineers to build the project.

“In the project worlds these days, the technologies are not that different. You need the flexibility to move people around,” he said.

Chevron transfers hundreds of people between the two segments every year. The skills from one sector are transferable to another, he said. In addition, an integrated company has more immediate market feedback and a better flow of market intelligence than a disintegrated one.

Chevron’s integrated operations also give it valuable market intelligence that it would not otherwise have as a divided company, Pryor said.

—Keefe Borden

North Dakota Pipeline Authority: Rail is here to stay

North Dakota has been one of the biggest stories in energy the past two years as crude production out of the Williston Basin has led to tremendous job and economic growth in the state, and has helped put the U.S. on the cusp of energy self-sufficiency. It has also helped make rail transportation a major force in the midstream.

“Rail is the new kid on the block. It’s been quite the story the past few years and has taken many of us by surprise with how quickly it has come online,” Justin Kringstad, director of the North Dakota Pipeline Authority, told attendees at Hart Energy’s DUG Bakken and Niobrara conference in Denver in May.

Indeed, crude-by-rail transportation has grown from nearly nil in 2008 to more than 620,000 barrels per day as of March 2013. This translates into a staggering 71% market share, according to Kringstad.

Rail has helped to resolve two of the biggest challenges that producers and operators have faced in the play: moving oil out of the basin and moving it around the basin, he said.

Midstream companies have also sought to solve these challenges through consistent pipeline additions in the state, from 11,707 miles in 2009 to 12,717 in 2010 before increasing to 15,070 miles in 2011, according to the most recent data available. Data from 2012 will be released in the third quarter of 2013.

“To say activity is blistering out there is an understatement. Things are moving very rapidly with pipe being put in the ground as safely and quickly as possible,” he said.

The state has three major systems. The largest is the Enbridge system with 210,000 barrels per day of capacity moving east to the Great Lakes and 145,000 barrels per day of capacity moving north to Canada. The state only has one refinery—the Tesoro Mandan facility, which can handle 58,000 barrels per day.

Rail transportation was originally thought to be a short-term solution with pipeline transportation being the long-term fix. However, a funny thing happened in late 2012: There was a major drop-off in pipeline volumes.

This was due to the flexibility that rail transportation provides as it allows producers to access markets with better economics. Traditionally, the price differential between North Dakota crude and West Texas Intermediate crude has been $5 to $10 per barrel; however, by late 2012 the differential was more than $20.

“It’s no coincidence that right as we saw these differentials we saw rail transportation pick up in order to find premium markets,” Kringstad said.

While rail and new pipelines are helping to solve many of the issues producers are facing, there is still a great need for new infrastructure. Although the rig count has decreased in the region this year, improved efficiencies should keep production steady for the next several years before gradually decreasing from 2016 to 2029.

The lack of infrastructure has caused some wells to be completely disconnected from any systems, which has resulted in increased flaring of natural gas. “We need to get these wells connected as fast as possible,” Kringstad said.

—Mike Madere

DUG Bakken-Niobrara: Private equity details what's in a deal

If you are in the business of loaning money to oil and gas producers, a standard question from the financially inquisitive is “what’s your typical deal?”

Panelists at Hart Energy’s recent DUG Bakken and Niobrara conference in Denver outlined what they think is typical and preferable in the world of deal-making.

John Cleveland, managing director of SFC Energy Partners, Denver, offered his diagnosis: “A typical deal for us is a group of people from Apache, Anadarko, Conoco, someplace like that. They’re in their 40s or 50s. They’ve been involved in the oil and gas industry their entire careers. They’re sort of a multi-disciplinary group—an engineer, a geologist, a finance guy. They’ve always talked about going out on their own. And they finally decide, ‘OK, let’s do it.’”

The team members put a business plan together and make their pitch—and that’s where experience counts, Cleveland said. “If there’s an additional common theme to that profile I just outlined, it’s that somebody in that group almost invariably has what I call ‘a lost-in-the-files opportunity.’ It might be something that they saw when they were a junior engineer at Amoco 20 years ago, and everyone else had forgotten about.

“But this one person remembers it, and with the miracle of modern technology—3-D seismic, horizontal drilling, multistage fracs—you can now go back into that zone and really make a profitable opportunity out of it. Many of pitches we get have opportunities like that embedded.”

If a management team can point to an opportunity, Cleveland says they will deliver a much more compelling pitch. “What is much less compelling is ‘We’re five guys, we’re great guys, we have great track records and we want $75 million to go out and do great things,’” he said.

“You can probably already see that if a management team comes in and says ‘we want $75 million and this is how we’re going to invest to the first $30 million and this is why this opportunity is so compelling,’ – that’s a much more persuasive pitch than ‘we want a hunting license.’”

Chuck Yates, partner and managing director, Kayne Anderson Capital Advisors LP, said, “Coming in with an opportunity and showing why you want to do it allows you to have a discussion with your private-equity provider.”

He said it is imperative for a management team to figure out if it has the same risk profile as a private-equity provider.

“Let’s face it: Terms are all kind of the same. If anyone had much better terms they’d get all the deals,” he said. “So when you’re out there thinking who you’re going to go with, it’s really like a marriage. I know that sounds quirky and all, but you need to date a little bit before you get married. Being able to lay out a project, and walking in and laying down logs and showing seismic, showing your mapping, showing why you think it works, and getting a reaction from the private-equity guy on whether they think it will work, how much capital you should devote to it— that’s what should drive your decision on who your private-equity provider is much more than anything else.”

One of the things Kayne Anderson will do with management teams, Yates said, is say, “Show us a project you worked on 10 years ago.”

Yates used the example of a management team that described a project in which they drilled three wells, all of which were dry holes, and explained why they thought that happened. “It was very illuminating for both sides because we figured out that we were on the same page in terms of risk. We thought a lot of the team, and they’re one of our portfolio companies today,” he said.

Harrison Williams, executive vice president, co-head of acquisitions and divestitures, Raymond James, said, “We are increasingly working with our clients at an earlier stage.” Planning an exit strategy early on is beginning to occur more often.

“Our objective is to take something from acreage value to PUD [proved undeveloped] value. If you have enough wells to cover an area geographically, and you have enough bulk PDP [proved developed producing] in a package, then you’re going to get PUD value on a per-acre basis, and that may be 10 times what you paid for that acreage. I think that valueadd from acreage to PUD is what makes the private-equity model work.”

—Mike Madere