Could any conjecture on an agreement between Russia and The Kingdom Come True?

Tuesday, February 2nd, 2016 and is filed under Oil and Gas Financial Analysis

Great Article by Dalan McEndree for OilPrice!!!!!!!!! Read this…great international reporting and research by him on these two O&G Players and their crucial relationship.

In recent days, signs of a possible breakthrough in the year-long stand-off between Russia and Saudi Arabia on crude production strategy have emerged. Saudi Arabia, OPEC’s dominant member, has long insisted OPEC (read Saudi Arabia) would not reduce output to balance supply and demand absent corresponding cuts from non-OPEC members (read Russia), while Russia has consistently insisted harsh climactic conditions prevent Russian producers from reducing output and in any case Russia insists it could withstand low prices as well as any other country.

January 27, however, Russia announced, in a roundabout way, its willingness to cut. According to Bloomberg, the Russian Energy Ministry issued a statement that “Energy Minister Alexander Novak and the heads of Russia’s biggest oil companies discussed the possibility of working with OPEC.” The article also reported that Deputy Prime Minister Yury Trutnev told President Vladimir Putin that:

“There was a series of meetings with other governments last week on the issue of oil prices during the World Economic Forum in Davos, Switzerland. Oil exporters are talking about coordination because the current price is “unacceptable” to justify spending on exploration and field development”.

These Russian comments were not the only signs of potential movement in the past week. At a conference in Kuwait City, Iraq’s Oil Minister Adel Abdul Mahdi stated that “Saudi Arabia and Russia, the world’s biggest oil producers, are now more flexible about cooperating to cut output as crude prices have fallen to levels that hydrocarbon-rich nations didn’t foresee.

Many observers, however, have been quick to dismiss the significance of these public statements. John Kilduff, founding partner of Again Capital, and frequent CNBC oil contributor, commented January 29 on CNBC that:

“This whole story line about there being a coordinated production cut plan is just rubbish”.

More generally, as this quote from a recent Bloomberg article shows, observers believe simply both sides are committed to their current (over)production strategy:

“There’s little sign the countries themselves are ready to reach an agreement despite the economic damage wrought by the lowest prices since 2003. Long-standing obstacles remain — Saudi Arabia’s desire to defend market share, Russia’s inability to cut production in winter months — and analysts say talk of a deal probably reflects the hope of producers in pain rather than the expectation of concrete action”.

In fact, skeptical observers dismiss these statements’ implications at their own peril. Both the Saudis and the Russians are serious, as both have powerful motivations to agree on measures to balance the market through production cuts, reduce crude inventories, and increase prices.

The real question, instead, is whether their interests are sufficiently congruent to agree to simultaneous moves to balance the market.

With Their Economic Situation Dire, Are the Russians Desperate?

Over the last several months, as crude prices have renewed their plunge and taken the Ruble with them, Russian economic prospects have deteriorated sharply. Even a cursory review of press reports reveals the intensity of the economic pain.

At the World Economic Forum in Davos last week, Alexei Kudrin, Russia’s respected former Finance Minister, stated—or perhaps warned—“We have two years in reserve [to overcome the economic crisis] when social sentiments will be stable. There are still social protests, they are growing, but they aren’t bursting into something out of control”.

In recent days, signs of a possible breakthrough in the year-long stand-off between Russia and Saudi Arabia on crude production strategy have emerged. Saudi Arabia, OPEC’s dominant member, has long insisted OPEC (read Saudi Arabia) would not reduce output to balance supply and demand absent corresponding cuts from non-OPEC members (read Russia), while Russia has consistently insisted harsh climactic conditions prevent Russian producers from reducing output and in any case Russia insists it could withstand low prices as well as any other country.

January 27, however, Russia announced, in a roundabout way, its willingness to cut. According to Bloomberg, the Russian Energy Ministry issued a statement that “Energy Minister Alexander Novak and the heads of Russia’s biggest oil companies discussed the possibility of working with OPEC.” The article also reported that Deputy Prime Minister Yury Trutnev told President Vladimir Putin that:

“There was a series of meetings with other governments last week on the issue of oil prices during the World Economic Forum in Davos, Switzerland. Oil exporters are talking about coordination because the current price is “unacceptable” to justify spending on exploration and field development”.

These Russian comments were not the only signs of potential movement in the past week. At a conference in Kuwait City, Iraq’s Oil Minister Adel Abdul Mahdi stated that “Saudi Arabia and Russia, the world’s biggest oil producers, are now more flexible about cooperating to cut output as crude prices have fallen to levels that hydrocarbon-rich nations didn’t foresee.

Many observers, however, have been quick to dismiss the significance of these public statements. John Kilduff, founding partner of Again Capital, and frequent CNBC oil contributor, commented January 29 on CNBC that:

“This whole story line about there being a coordinated production cut plan is just rubbish”).

More generally, as this quote from a recent Bloomberg article shows, observers believe simply both sides are committed to their current (over)production strategy:

“There’s little sign the countries themselves are ready to reach an agreement despite the economic damage wrought by the lowest prices since 2003. Long-standing obstacles remain — Saudi Arabia’s desire to defend market share, Russia’s inability to cut production in winter months — and analysts say talk of a deal probably reflects the hope of producers in pain rather than the expectation of concrete action”.

In fact, skeptical observers dismiss these statements’ implications at their own peril. Both the Saudis and the Russians are serious, as both have powerful motivations to agree on measures to balance the market through production cuts, reduce crude inventories, and increase prices.

The real question, instead, is whether their interests are sufficiently congruent to agree to simultaneous moves to balance the market.

With Their Economic Situation Dire, Are the Russians Desperate?

Over the last several months, as crude prices have renewed their plunge and taken the Ruble with them, Russian economic prospects have deteriorated sharply. Even a cursory review of press reports reveals the intensity of the economic pain.

At the World Economic Forum in Davos last week, Alexei Kudrin, Russia’s respected former Finance Minister, stated—or perhaps warned—“We have two years in reserve [to overcome the economic crisis] when social sentiments will be stable. There are still social protests, they are growing, but they aren’t bursting into something out of control”.

Until recent weeks, the Russian government had some basis to harbor hope that GDP, after contracting ~3.5 percent in 2015, would return to growth within this two year window. As late as Q3 2015, the IMF estimated that in 2016, GDP would grow, if only anemically at below 1 percent.

Recent crude price action, however, has dashed such hopes and instead has raised the prospect of a deeper and longer recession. In a “stress” test it conducted in November, the Russian Central Bank estimated that with Ural crude prices below $40 per barrel between 2016-2018, the Russian economy would contract five percent in 2016, inflation would run at 7-to-9 percent, and that these conditions “would also raise risks to inflation and financial stability.

Central Bank efforts to stabilize the Ruble and contain inflation are one reason the “stress” test results may prove prescient. The plunge in crude prices is preventing the Central Bank from easing monetary policy to stimulate the economy. Friday, January 29, it announced that it would keep its benchmark interest rate at 11 percent, to support the Ruble (which fell as low as ~R82.5/US$ last week before recovering to ~RUB75.5/US$ on January 29) and contain inflation. In its announcement, it noted that its next move could be to raise rather than lower the benchmark rate, were inflationary pressures to increase.

Facing crude prices below $30 per barrel, Russian Finance Minister Anton Siluanov in a January 16 television interview said Russia now faced a RUB 1.5 trillion budget deficit ($38.6 billion at the time of the interview) and that this would force the government to rework the budget it approved in December, which was based on $50 Ural crude prices. Reworking, according to Siluanov, will entail cutting RUB 500 million in spending (from which the military, national security, and agriculture would be exempted) and finding RUB 1 trillion in additional revenue.

Finding this RUB 1 trillion confronts the Russian government with unpalatable choices. Russia’s sovereign wealth/reserve funds have been proposed as sources—but in September, Siluanov warned that they would be depleted in sixteen months.

Related: Russian-OPEC Production Cut Remains A Long Shot

The Russian government is also contemplating asset sales (including part of its stake in Rosneft and in VTB, a major bank), but such sales would provide one-time boosts to revenue and in any case would take time to organize. Borrowing is a possibility, since Russia’s sovereign debt is low, but the Russian government can’t access U.S. and European capital markets, closed to it due to U.S. and EU sanctions related to the conflict over Ukraine).

The Russian energy industry is also a target—and potentially a lucrative one, given the structure of Russian taxes on the industry. In 2015’s first three quarters, for example, low crude prices decreased the revenues the Russian government collected in export customs duties from Rosneft, Russia’s largest producer, by RUB 520 billion (RUB 1058 billion to RUB 738 billion), while taxes other than income taxes increased only RUB 80 billion, from RUB 919 billion to RUB 1009 billion).

It is therefore not surprising that in September, the Russian Finance Ministry attempted to increase the mineral extraction tax. Industry opposition and opposition from other Russian ministries—citing the negative impact on investment and output—forced it to back down (Venezuela is an example, admittedly extreme, of what happens when government raids on industry revenues to fund current operations squeezes investment). It proposed instead to slow down the planned decrease in crude export duty rate (from 42 percent to 36 percent. Also under consideration is a windfall profits tax on Russian energy exporters benefitting from the Ruble’s depreciation.

Deteriorating Energy Industry Conditions

The situation of Russian energy producers is also difficult. The Telegraph (UK) in early January quoted Russia’s deputy finance minister, Maxim Oreshkin, as telling TASS earlier this month that low crude prices could lead to “hard and fast closures in coming months.” The article also said noted that in the key Soviet-era fields in western Siberia, the annual rate of depletion is averaging 8 percent to 11 percent, while new projects are being curtailed.

According to the Telegraph, Transneft, the Russian crude and product pipeline monopoly, estimated that Russian crude exports could decrease in 2016 by some 460,000 barrels per day, based on producer applications for pipeline capacity.

In an interview with TASS, the Russian news agency last week, Lukoil Vice President Leonid Fedun commented that Lukoil was unlikely to produce the one hundred million tons it produced in 2015. He also said that it mad

For Rosneft, inflation has contributed to increased costs in all but one expense category compared to 2014’s corresponding quarter (percentage change in red font in column 2 in the table below) and, because revenues declined in 2015, increased the ratio of that cost to revenue compared to the corresponding 2014 period (last two columns).

These two effects caused operating income through Q3 2015 to fall to RUB 455 billion from RUB 539 billion in 2014 (and, of course, in US$ terms, the value of the operating income decreased even more, since the respective average exchange rates were RUB 59.28/US$ and RUB 35.59/US$ in 2015 and 2014). In addition, if not for the 41.3 percent decrease in export customs duty—RUB 520 billion in absolute terms—operating income would have been negative RUB 65 billion through 3Q 2015 (RUB 455 billion minus RUB 520 billion).

For Rosneft, inflation has contributed to increased costs in all but one expense category compared to 2014’s corresponding quarter (percentage change in red font in column 2 in the table below) and, because revenues declined in 2015, increased the ratio of that cost to revenue compared to the corresponding 2014 period (last two columns).

These two effects caused operating income through Q3 2015 to fall to RUB 455 billion from RUB 539 billion in 2014 (and, of course, in US$ terms, the value of the operating income decreased even more, since the respective average exchange rates were RUB 59.28/US$ and RUB 35.59/US$ in 2015 and 2014). In addition, if not for the 41.3 percent decrease in export customs duty—RUB 520 billion in absolute terms—operating income would have been negative RUB 65 billion through 3Q 2015 (RUB 455 billion minus RUB 520 billion).

Reduced revenues and increased costs in 2015’s first three quarters also reduced the amount of cash Rosneft generated to cover investment, dividends, and net finance expense (which includes interest paid, interest received, and operations with derivative financial instruments). The following table shows that the cash remaining after Rosneft’s spending on net finance expense, investment, and dividends, after adding non-cash depreciation, depletion, and amortization expense back into operating income, declined significantly through three, six, and nine months of 2015 compared to 2014 in Ruble terms and, of course, even more in US$ terms given Ruble depreciation (RUB 59.28/US$ in 2015 versus RUB 35.59/US$ in 2014):

Reduced revenues and increased costs in 2015’s first three quarters also reduced the amount of cash Rosneft generated to cover investment, dividends, and net finance expense (which includes interest paid, interest received, and operations with derivative financial instruments). The following table shows that the cash remaining after Rosneft’s spending on net finance expense, investment, and dividends, after adding non-cash depreciation, depletion, and amortization expense back into operating income, declined significantly through three, six, and nine months of 2015 compared to 2014 in Ruble terms and, of course, even more in US$ terms given Ruble depreciation (RUB 59.28/US$ in 2015 versus RUB 35.59/US$ in 2014):

Given that average crude prices in Q4 2015 were substantially lower than in Q3 and that they likely will even lower in Q1 2016, Rosneft’s financial operating results should also deteriorate substantially in these quarters. The following table projects Rosneft’s revenues in Rubles in Q4 2015 and Q1 2016 using the Ruble’s Q4 average US$ exchange rate and a guesstimate of the Ruble’s Q1 US$ average exchange rate; an estimate of sales in volume terms, assuming output in 4Q 2015 continued to outpace 2014 levels by 2 percent and stayed constant in Q1 2016; and guesstimates of crude prices, taking into account Ural crude’s discount to Brent, Rosneft’s price competition in Europe with Saudi Arabia, and the impact on Rosneft prices in Europe and Asia from a prepayment agreement with Transneft that lowered its realized price per barrel (in Q1, Q2, and Q3, a reduction of RUB 200, RUB 40, and RUB 180 in Europe and RUB 170, RUB 350, and RUB 190 Rubles in Asia).

This rough guesstimate of Rosneft’s 4Q 2015 and 1Q 2016 performance suggests that the company will not generate sufficient cash to fund investment, dividends, and interest, and pay down debt.

From the Saudi Point of View

The Saudis and their Gulf Arab allies also have compelling reasons to consider production cuts to balance the global crude market and raise prices. They depend on revenues from crude and crude product exports as much as if not more so than the Russian government to fund government spending. Like the Russian government, they face serious domestic and international challenges—including wars and domestic tensions—that they counted on the export of crude and crude products to fund.

As a result of lost revenues and deteriorating budget numbers, the government are drawing on foreign currency and sovereign wealth resources, seeking to cut spending, including in such politically sensitive areas as subsidies for individuals and businesses, and to defer or cancel important investment projects (the UAE in recent days suspended the tender process for stage two of a project to build a 1,350 mile railroad from Kuwait the Indian Ocean along the Persian Gulf).

To raise revenue, they are introducing new taxes (such as on unoccupied land in Saudi cities) and contemplating asset sales (or which the Saudi plan to sell shares in Saudi Aramco and/or its downstream subsidiaries is a prime example).

OPEC dynamics are another important consideration. Other OPEC members—Venezuela, Algeria, Nigeria, Angola and Libya—repeatedly have called for output to be cut. In response, the Saudis have argued that OPEC cuts would be ineffective in the absence of simultaneous cuts from non-OPEC countries members. Were the Saudis and their Gulf Arab allies to reject a sincere Russian commitment to cut production, their credibility and authority within OPEC would suffer perhaps irreparable damage.

Related: More Oil and Gas Bankruptcies Are Assured

Also, for the Saudis, the plans to sell shares in Saudi Aramco and/or its downstream operations could play an important role. The price investors will be willing to pay for shares in these entities will depend on the value they place on the entities, and this value will depend on their assessment of the entities’ management, strategy, and prospects. If, for example, potential investors believe that management, at the behest of the Saudi government, will sacrifice growth, profits, and dividends to achieve Saudi foreign policy goals through low prices, investors’ interest might be tepid at best.

A Narrow Window of Opportunity for Russia for Coordinated Cuts

The Russians potentially enter any discussions with a weaker hand. The Saudis and their Gulf Arab allies probably can withstand lower prices longer than the Russians. Russia lacks the financial resources the Saudis and their Gulf Arab allies have at their disposal.

Their sovereign wealth funds and foreign currency reserves in absolute and per capita terms exceed Russia’s, the value of their government owned energy assets are greater than the value of the Russian government’s energy assets (which are already partially privatized), and Saudi Arabia and its Gulf Arab allies have access to international capital markets, whereas the Russian government, because of U.S. and EU sanctions, does not.

They also have the means to pressure Russia. The Saudis have spare capacity (according to the IEA have some `1.5~2.0 million barrels per day which they can bring on line within three months), while the Russians lack spare capacity. Finally, Russia’s major energy companies report quarterly results, whereas with a few exceptions, Saudi and Gulf Arab energy companies do not. Thus, the Saudis have access to critical Russian microeconomic financial data, whereas the Russians do not have such access to Saudi and Gulf Arab data.

Possibly, if the Russian government believes its hand is weaker, it might consider it advisable to reach agreement expeditiously. After all, the Russian government should take into account that if Russian data during the first quarter shows declines in output and exports, as comments from Russian government and company officials cited above suggest might happen, and Q1 2015 financial reports show intensifying financial pressures on Russian energy companies, Saudis and their Gulf Arab allies might be tempted to decide to maintain pressure on prices and force Russia to absorb the cuts necessary to balance the global crude markets.

Having spent time in Moscow and still with good friends there… McEndree is correct about the situation in Russia. He neglected to reflect on the added impact of sanctions there, as well.

 

O. Victor Lattanzi (ovlattanzi@marakon.com) is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group and Senior Strategist, Marakon Consulting at Charles River Associates.

Make Sure You Have a Plan for Long Lasting $30 Oil…

Monday, February 1st, 2016 and is filed under bankruptcy

This will not go away on its own according to ‘Fuel Fix’…

HOUSTON – Bankruptcy paperwork could pile up high in Texas this year if the oil downturn keeps the pressure up on everything from oil drillers and trucking companies to hotels and caterers near the oil patch.

More than two dozen Texas bankruptcy attorneys expect a 30 percent increase in corporate restructurings and bankruptcy filings in the state this year, according to a sampling of bankruptcy attorneys by a Houston law firm.

That means 800 more of the state’s businesses than last year could be forced into drastic action in 2016, with the financial stress concentrated in the Eagle Ford Shale and the Permian Basin, spreading to wastewater treatment plant operators and laundromats in remote oil towns and ultimately affecting things like legal services and commercial real estate in Houston.

“It’s a domino effect,” said a bankruptcy attorney, in a recent interview. “But the further out you get from the epicenter, the less pervasive the impact.”

The firms that could go bankrupt or restructure this year are tied to an estimated $84 billion in assets in Texas. Based on the survey, it believes the number of Texas bankruptcies and restructurings could reach 3,468 this year. That’s about 13 percent higher than the average for the past decade, but it’s a quarter lower than the financial crisis in 2009.

That’s because even though the oil bust is more severe this time around, banks are collectively a lot healthier now than during the national credit crunch seven years ago. The lessons learned then and during the 1980s oil bust are coming into sharper view. To fight the oil-market meltdown in Texas, companies “have to be Attila the Hun when it comes to cost-cutting.”

“I tell them, you’ve got to be attractive (to investors). You’re an ugly duck – but you’ve got to be the best-looking ugly duck on the street now,” he said. “Your existing lenders can put you into bankruptcy.”

But it is often too hard for companies to make tough choices, and “the catharsis of the debtor” many times will get the best of managers headed for bankruptcy.

“They can’t bring themselves to tell the 30-year administrative assistant that they’re gone, or tell everybody on the payroll they’re getting a 10-percent pay cut,” he said. “But to survive, that’s what you have to do. Some of them don’t survive, some of them do.”

An influx of bankruptcies would add another economic headache in Texas after the layoffs of approximately 60,000 upstream oil and gas workers, according to economist Karr Ingham.

But the state is much better-equipped to handle it now than in the 1980s oil bust because the state’s financial system is propped up by big banks tied to trillions in assets and the state’s real estate market is just showing the first hints of distress. Three decades ago, Texas banks were extremely small – each branch was its own entity, per state regulations. Hundreds failed.

Still, big Wall Street banks and smaller Texas lenders are preparing for the flurry of energy loan defaults as oil prices slip into territory that makes it impossible to make money on expensive shale drilling in remote parts of the state.

JPMorgan Chase, Wells Fargo and other big financial institutions have set aside 5 to 7 percent more cash as a cushion against loans losses, but if oil prices remain low for the rest of the year those losses could rise to 10 percent – the same amount that some banks lost during the 1980s, Evercore ISI estimates.

“With oil here in the $30s, the banks have finally found religion,” said an analyst at Evercore ISI, in a recent conference call with investors. “They’re ramping up loan loss reserves and recognizing their criticized assets, but there’s still more pain to be had.”

O. Victor Lattanzi (ovlattanzi@marakon.com) is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group and Senior Strategist, Marakon Consulting at Charles River Associates.

Cornell University to Consider Divesting Fossil Fuel Investments…

Saturday, January 30th, 2016 and is filed under oil and gas investment

This is an absolute absurdity and wholly ignorant. I am embarrassed for you. Your role is to teach our children right from wrong and not succumb to their whims and fancies…

Such a move would place you on par with the Wall Street Journal Editor’s unsuitable adoption of ‘fracking’ as a synonym for horizontal drilling.

We’ve been fracturing wells in this Country for 100 years. How do you think the hydrocarbons are released from the rock’s pores?

Keep the thermostat at 70 degrees and call the Science Department before the vote…What’s their phone number?

(Bloomberg) Cornell University’s trustees are planning to discuss divesting from fossil fuels, an issue that many of the richest U.S. schools have grappled with while only a few have taken action to purge their endowments of oil, gas and coal company stocks.

Cornell’s 64-member board will include the topic at its scheduled meetings today and Saturday, said John Carberry, a spokesman for the Ithaca, New York-based school. It was unclear whether the board will vote on the issue. Cornell’s $6.3 billion endowment has about $24 million in fossil-fuel investments, according to the school.

Divestment has been a popular issue in recent years among students, who have protested at campuses from Swarthmore College to Yale University. Yet even with the movement spreading to more than 1,000 campuses, only a few dozen schools have placed some restrictions on their commitments to the sector.

Energy Efficiency

Even if schools don’t withdraw from fossil-fuel investments, they can invest money in in revolving loans to promote energy efficiency or solar or wind programs in their communities, said Mark Orlowski, founder and executive director of the Boston-based nonprofit Sustainable Endowments Institute.

“Cornell’s board has a really exciting opportunity,” Orlowski said in an interview. “Regardless of a full divestment plan or a partial divestment plan, these are the types of opportunities that can have a significant and tangible long-lasting impact on campus and in the community.”

Stanford University, with a $22.2 billion endowment, is one of the schools committing to no longer invest in coal companies. In September, the University of California system, with $91 billion in holdings, said it sold $200 million in coal and oil sands company investments. The Massachusetts Institute of Technology in October rejected demands from a student-led group to divest, as did Harvard University and Yale University.

Policy Concern

Elizabeth Garrett, who became Cornell’s president last year, told the student newspaper in November that she doesn’t think “divestment is the right way to go,” and that the school’s investments in fossil fuels aren’t big enough to make a difference if it divests.

“The trustees are now putting in place a method through which they would think about these issues of divestment, because we anticipate that this is not going to be the last request for divestment stemming from a policy concern,” Garrett told the paper. “They want to put in place a way for people to understand how to present these issues to the board and a way to consider them.”

David Skorton, Cornell’s former president, also rejected the idea previously, partly because he said it may harm the performance of the endowment.

Cornell posted a 3.4 percent investment return for the year ended June 30, the worst performance in the eight-school Ivy League. Also today, Cornell announced a $50 million donation from Robert F. Smith, chairman and chief executive officer of private equity firm Vista Equity Partners. The gift will support chemical and biomolecular engineering and African-American and female students at the university’s college of engineering.

 

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group.

EIA Short Term Energy Outlook 2016

Wednesday, January 27th, 2016 and is filed under oil and gas forecasts

From EIA Short Term Energy Outlook

Highlights

 

  • This edition of the Short-Term Energy Outlook is the first to include forecasts for 2017.
  • North Sea Brent crude oil prices averaged $38/barrel (b) in December, a $6/b decrease from November, and the lowest monthly average price since June 2004. Brent crude oil prices averaged $52/b in 2015, down $47/b from the average in 2014, as growth in global liquids inventories put downward pressure on Brent prices throughout much of the year.
  • Forecast Brent crude oil prices average $40/b in 2016 and $50/b in 2017. Forecast West Texas Intermediate (WTI) crude oil prices average $2/b lower than Brent in 2016 and $3/b lower in 2017. However, the current values of futures and options contracts continue to suggest high uncertainty in the price outlook. For example, EIA’s forecast for the average WTI price in April 2016 of $37/b should be considered in the context of recent contract values for April 2016 delivery (Market Prices and Uncertainty Report) suggesting that the market expects WTI prices to range from $25/b to $56/b (at the 95% confidence interval).
  • The price of U.S. retail regular gasoline is forecast to average $2.03/gallon (gal) in 2016 and $2.21/gal in 2017, compared with $2.43/gal in 2015. In December, average retail regular gasoline prices were $2.04/gal, a decrease of 12 cents/gal from November and 51 cents/gal lower than in December 2014. EIA expects monthly retail prices of U.S. regular gasoline to reach a seven-year low of $1.90/gal in February 2016, before rising during the spring.
  • U.S. crude oil production averaged an estimated 9.4 million barrels per day (b/d) in 2015, and it is forecast to average 8.7 million b/d in 2016 and 8.5 million b/d in 2017. EIA estimates that crude oil production in December fell 80,000 b/d from the November level.
  • Natural gas working inventories were 3,643 billion cubic feet (Bcf) on January 1, which was 17% higher than during the same week last year and 15% higher than the previous five-year average (2011-15) for that week. EIA forecasts that inventories will end the winter heating season (March 31) at 2,043 Bcf, which would be 38% above the level at the same time last year. Forecast Henry Hub spot prices average $2.65/million British thermal units (MMBtu) in 2016 and $3.22/MMBtu in 2017, compared with an average of $2.63/MMBtu in 2015.
  • A decline in power generation from fossil fuels in the forecast period is offset by an increase from renewable sources. The share of generation from natural gas falls from 33% in 2015 to 31% in 2017, and coal falls from 34% to 33%. For renewables, the forecast share of total generation supplied by hydropower rises from 6% in 2015 to 7% in 2017, and the forecast share for other renewables increases from 7% in 2015 to 9% in 2017.

Distress in the oil patch is spurring a (not that) new type of joint venture…

Tuesday, January 26th, 2016 and is filed under Energy Mergers and Acquisitions

…Looking for ‘deals’ according to Bloomberg News.

Joint ventures between oil and gas explorers in the U.S. and their foreign counterparts helped fuel the shale boom. They’re coming back in a new iteration for the bust.

The difference this time: Shale explorers are partnering with Wall Street financiers to raise money for drilling, instead of overseas rivals.

Typically, private equity firms invest in energy by buying entire companies or providing capital to startups. Last year, U.S. oil and gas companies struck a half-dozen joint venture deals with private equity firms totaling at least $1.4 billion. In December, an affiliate of Fortress Investment Group agreed to provide National Fuel Gas Co. with as much as $380 million to fund wells in Pennsylvania, while Blackstone Group LP’s credit arm closed a similar deal in July with Linn Energy LLC.

Such transactions could accelerate this year as explorers face a cash crunch amid a rout in commodity prices. They are essentially a source of off-balance sheet financing for producers with good land but less than stellar credit. The way they are structured makes such deals akin to a homeowner renting out a room to keep the lights on.

“It’s tough times in the oil patch,” said the co-head of energy acquisitions and divestitures with Citigroup Inc. in Houston. “The traditional ways of raising money are not available.”

Temporary Stake

Joint ventures with private equity firms are fairly complex but have a simple premise. The investor pays for a certain number of new wells in exchange for a temporary majority stake in each well it funds. After booking a specified return, the financier surrenders most of its ownership interest back to the explorer.

They make sense right now because low commodity prices means producers are facing budget shortfalls, and they’re losing access to other types of funding.

U.S. crude fell 5.8 percent Monday to $30.34 a barrel. Last week, oil closed below $30 a barrel in New York for the first time in 12 years.

Bond sales by energy companies with less than prime credit fell 22 percent in 2015 to their lowest level in four years, according to data compiled by Bloomberg. Oil and gas explorers saw bank credit lines cut by an average of 5 percent in September and October, when lenders conduct one of their bi-annual reviews of loans outstanding to drillers. Analysts are forecasting even steeper cuts this spring if prices don’t rebound.

Drilling Costs

Private equity firms are also eager to invest in energy, and by some estimates have amassed as much as $100 billion in recent years for oil and gas deals.

“There is a lot of discussion,” said a partner with Akin Gump Strauss Hauer & Feld LLP in Houston. “I’m aware of one investor in this type of transaction that has looked at somewhere in the neighborhood of 200 of these transactions, but only closed on a handful of them.”

The last time explorers were so active in seeking a partner to cover drilling costs was about seven years ago during the U.S. shale boom, as Chesapeake Energy Corp. and Devon Energy Corp. established joint ventures with explorers from China and Europe. Many foreign companies booked losses on those deals after natural gas prices collapsed.

Protective Measures

The more recent pacts are designed to protect the private equity shops from that fate. So far, they have tended to be much smaller. The joint ventures are set up as temporary partnerships with a pay-as-you-go structure, and investors have oversight over where wells are drilled. The money also isn’t used to develop virgin prospects that may or may not pay off.

“The parties have a very good understanding of what type of production they can expect from the wells, what the wells are going to cost,” said a partner with Kirkland & Ellis in Houston. “These deals are usually focused on assets where the companies have proven that their completion technology works.”

The latest partnerships and earlier joint ventures are both innovations to the classic farmout deal — a company bringing in someone else to do some drilling because it can’t afford to — a staple of the energy sector for decades, Speier said. Buyout firms including KKR & Co. began developing the blueprint for the recent deals about three years ago to fund small, private companies with no access to the traditional debt and equity markets, he said.

The idea began catching on last year with larger explorers as their options for raising capital narrowed, he said.

Disappearing Runway

“A lot of companies are very quickly running out of runway,” he said.
EnerVest Ltd. may consider a drilling partnership when oil and gas prices eventually rebound and it ramps up production across its 33,000 wells in 17 states, according to John Walker, the Houston-based company’s chief executive officer.

Having a partner in some of these areas “would allow us to put a lot more rigs out there,” Walker said. “When prices go up, we’ll see more of them done.”

EnerVest negotiated a drilling partnership last year but tabled the discussions as energy prices slid and it decided to halt drilling everywhere, he said.

Sliding prices aren’t the only thing that can make drilling partnerships difficult to navigate.

Shale wells tend to dwindle over time after initially gushing. If it takes too long for the investor to make their money back, wells could be running dry by the time an explorer takes back ownership of them.

“The operator team is going to do a lot of work with little to show for it,” Citigroup said. “Operators don’t want to be working for somebody else.”

The complexity of these partnerships also means they can take a long time to come together, and may fall apart before an agreement is signed given the volatile nature of commodity prices.

They make sense only in certain areas such as the best parts of the Permian and Eagle Ford Basins of Texas, or Marcellus Basin in the Eastern U.S. This is because investors are generally seeking returns of about 15 percent, so the wells have to be able to pay out far better than that.

“For it to be attractive, we need to be drilling wells at 25 percent to 30 percent,” EnerVest said.

If oil and gas prices keep falling, explorers may not be able to find places to use the money they lined up. For instance, Linn Energy has yet to draw any of the $500 million that Blackstone Group’s credit arm agreed to provide in June. Last year, the company cut its capital expenditures program and halted a bond buyback program because of lower commodity prices, making it unlikely that Blackstone would make a sufficient return.

Also, a drilling partnership won’t necessarily stop a company from collapsing.
Magnum Hunter Resources Corp. struck a $430 million drilling finance about four months before filing for bankruptcy in December.

Despite all the challenges, some drilling partnerships announced last year seem to have worked out. ArcLight Capital Partners LLC paid out more than one-third of the $67 million it committed to Rex Energy Corp. as of September, according to company filings. That enabled Rex to grow production while cutting spending.

Legacy Reserves has drilled at least six wells in the Permian Basin with funding from a $150 million partnership it established in July with TPG, according to company presentations.

“While it’s too early to comment on production rates, we and TPG are pleased with our execution of the program,” Paul T. Horne, Legacy’s CEO, said on an earnings conference call in November.

 

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group.

North Dakota regulators approve Dakota Access Pipeline…to ENERGY TRANSFER PARTNERS

Thursday, January 21st, 2016 and is filed under oil production

ENERGY TRANSFER PARTNERS-WE ARE PROUD TO BE YOUR NEIGHBOR.

BISMARCK, N.D. (AP) — North Dakota regulators on Wednesday approved the biggest-capacity crude pipeline proposed to date that would move nearly 600,000 barrels daily from the oil patch to Illinois. Some things to know about the $3.8 billion, 1,150-mile project that crosses four states:

WHAT HAPPENED?

The North Dakota Public Service Commission had been reviewing Dallas-based Energy Transfer Partners’ permit for 13 months. The three-member, all-Republican panel long signaled support, saying the pipeline would reduce truck and oil train traffic, cut natural gas flaring and create more markets for the state’s oil and gas. The commission voted 2-0 to approve the permit; Commissioner Randy Christmann abstained because his mother-in-law has been negotiating an easement for the project.

WHAT NOW?

Energy Transfer Partners hopes to complete the pipeline by year’s end. The North Dakota’s portion is the longest leg (about 360 miles) and the most expensive ($1.4 billion).

Regulators in South Dakota and Illinois have already approved permits. Iowa still remains, though the company says it expects that approval to come next month. The U.S. Army Corps of Engineers also must approve the pipeline because it would cross beneath the Missouri River twice in North Dakota, near Williston and Mandan.

PIPELINE’S PATH

Energy Transfer Partners says it has easement agreements on 85 percent of the properties along the pipeline’s path, which crosses 50 counties, and will use eminent domain if agreements with landowners can’t be reached voluntarily. Easements can bring significant money for landowners: A couple in south-central North Dakota said they signed a 99-year easement worth almost $50,000 to allow a half-mile of pipeline on their farm.

SAFETY MEASURES

The steel pipeline will vary in diameter from 12 inches to 30 inches and would be buried at least 4 feet below ground — up to 64 feet at Missouri River crossings. The company says it would have safeguards including leak detection equipment, and that workers who remotely monitor the pipeline from Texas could close block valves on the pipeline within three minutes if a breach is detected.

 

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group.

Goldman Sachs Sees Oil Markets Turning Bullish Soon…

Thursday, January 21st, 2016 and is filed under Oil and Gas Financial Analysis

Good Morning!

Fun reading…someone must be long WTI or Brent.

(BLOOMBERG) When Goldman Sachs first postulated that oil prices might fall to as little as $20 per barrel, many market participants were incredulous. Fast forward a few months though, and with oil below $30 a barrel, $20 does not look nearly so improbable.

$20 Oil No Longer Seen As Good For The Economy

For instance, as oil supplies rise, it creates additional demand for storage capacity which in turn raises the price leading new storage supply solutions to come online. This can take the form of either new tanks built, or alternative equipment converted to oil storage – for instance pipelines and supertankers being used for storage rather than transport of crude.

The World Just Lost One Of Its Biggest Oil Plays To Low Prices

Additionally, there simply was never enough clean and clear data to suggest that a storage space crunch was imminent. An awful lot of supply exists across the U.S. heartland and elsewhere, but there is no good way to monitor it. Satellite imagery is starting to change that reality, but for now we have at best rudimentary methods for estimating capacity utilization. Thus worrying about storage capacity at this juncture is something like worrying about the threat of an alien attack – we have no good evidence to suggest a problem is at hand.

Related: When Will Petrobras’ Fire Sale Start?

Goldman’s view that storage capacity is not an issue unless the market sees an unexpected spike in production or fall in demand makes sense – markets do very well with supplying the needs of society when those needs are forecastable. As long as the oil glut continues to grow at a predictable pace, all should be well then.

The second notable point regarding Goldman’s view is the call for the start of a new bull market in late 2016. This should give some distant sense of hope to energy investors. Almost no oil producer on Earth can make money at present prices. Saudi Arabia and Iran in particular will likely keep pumping oil as a way of thumbing their nose at one another, but the Russians and the Venezuelans may find in short order that draconian financial adjustments are needed to keep their economies afloat without the traditional rich stream of oil revenues they have enjoyed. Similarly, while most oil companies survived the fall banking evaluations, 2016 will bring new challenges on that front.

Gary Schilling, an American financial analyst, noted the dilemma here that producers find themselves in last year with what proved to be a very prescient call. At this point companies are not making money oil at current prices. Instead they are continuing to operate in the hope that tomorrow will be better. They can do this until one of two things happen; they run out of cash for operating purpose, or they give up hope. It will probably take a combination of both factors to re-balance the markets.

 

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group.

Some Bankrupt Oil and Gas Drillers Can’t Give Their Assets Away…

Wednesday, January 20th, 2016 and is filed under bankruptcy

Oil is in free fall…

In mid-2014, when the crude price topped $100 a barrel, Clark made an offer to buy properties from Dune Energy Inc., a small driller with money trouble. Dune turned him down. A year later, as oil plunged to $60 a barrel, Dune filed for bankruptcy and Clark’s White Marlin Oil & Gas Co. picked up the assets at auction at a deep discount. “What we offered versus what we got it for, it’s a great price,” Clark said. “We’re going to continue to play these bankruptcies. We’re participating in two more right now.” Winners and losers are emerging from the energy bust. What’s a meal for Clark is indigestion for banks that financed the boom using oil and gas properties as collateral. The four biggest U.S. banks — Bank of America Corp., Citigroup Inc., JPMorgan Chase & Co. and Wells Fargo & Co. — have set aside at least $2.5 billion combined to cover souring energy loans and have said they’ll add to that if prices stay low. There’s plenty to keep Clark bargain-hunting. Last year, 42 U.S. energy companies went bankrupt, owing more than $17 billion, according to a report from law firm Haynes and Boone. Dune went belly up owing $144.2 million. Its assets sold for $20 million. In May, American Eagle Energy Corp. filed for bankruptcy with debts of $215 million. Its properties sold for $45 million in October. BPZ Resources Inc. owed $275.2 million. Its assets fetched about $9 million. Endeavour International Corp. went into bankruptcy owing $1.63 billion. The company sold some assets for $9.65 million and handed over the rest to lenders. ERG Resources LLC opened an auction with a minimum bid of $250 million. Response? No takers. “A lot of people got into this business and didn’t really understand the ups and downs of price cycles,” said a managing director for turnaround and restructuring with the consulting firm. “They’re getting a very bad dose of reality right now.”

Eternal Energy

More pain will come. Crude prices, down 70 percent since June 2014 and hovering in the $30- a-barrel range, could head down further, an AlixPartners report said. With its optimistic ticker AMZG — earlier incarnations were named Golden Hope Energy and Eternal Energy — American Eagle is classic shale. The last few years, the company took advantage of low interest rates and high oil prices, outspending its income and relying on debt to keep drilling. Now the company is part of the bust, selling off acreage for less than it owed its bondholders. Bradley Colby, American Eagle’s chief executive officer, didn’t respond to an e-mail seeking comment. Samson Resources Corp. filed for bankruptcy in September, listing $4.2 billion in debt. Its initial plan was to let lenders with claims on its assets take over, but unsecured creditors opposed the idea since, they contend, nothing would be left over for them. The company is still negotiating with its lenders. Brian Maddox, a spokesman for Tulsa, Oklahoma-based Samson, declined to comment. “The reality is setting in as prices remain lower for longer,” said a partner with Haynes and Boone in Houston, which represented Dune Energy in bankruptcy. An attorney for BPZ Resources declined to comment. Representatives of Endeavour International didn’t respond to requests for comment. Cat Canyon ERG Resources owns nearly 19,000 acres in a century-old field about an hour’s drive northeast of Santa Barbara, California. Called Cat Canyon, it was discovered in 1908 and has produced 300 million barrels of crude since then. ERG planned to squeeze more oil from the aging field. That was before prices declined. ERG declared bankruptcy in April owing about $400 million, most of it to Beal Bank USA, a private lender based in Las Vegas. The company found no qualified buyers willing to pay its minimum bid of $250 million. Any money the business generates will be used to repay Beal before other creditors, said  ERG’s chief restructuring officer.

Bankruptcies are accelerating. Magnum Hunter Resources Corp., Swift Energy Co. and New Gulf Resources filed in December. With more liquidations hitting the market, bargain hunters may not be willing to pay top dollar when there are so many deals to be found. The next test will be the auction of Quicksilver Resources Inc.’s properties, scheduled for Wednesday. The shale driller declared bankruptcy in March with more than $2 billion in debt. “So much of the frenzy in shale in the past few years was a result of the money pouring out of Wall Street,” “It was as much a Wall Street play as it was an oil-and-gas play, said White Marlin. “It was putting money to work. Companies took on all that risk and now we see the result.”

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group

Meet the energy hedge funds that made money while oil plunged…

Tuesday, January 19th, 2016 and is filed under oil and gas investment

The plunge in oil prices has dragged down much of the energy sector with it. Yet, some energy-focused hedge funds managed to avoid the carnage entirely.

Lansdowne Partners — one of Europe’s largest hedge funds with $22 billion — gained 14.8 percent last year in its long-short energy-focused equity fund, according to a person familiar with the matter. Some commodity trading advisers, or CTAs, posted gains of more than 25 percent in 2015.

Breaking even was an achievement last year, when the price of a barrel of oil dropped 30 percent and the Standard & Poor’s 500 Energy Sector Index lost 21 percent. Energy-focused equity funds fell 10.7 percent last year, according to eVestment’s latest hedge fund performance report. Oil has fallen about another 21 percent in 2016, trading below $30 for the first time since 2003.

Landsdowne bucked the trend with a majority of its gains from short positions, the person familiar with the matter said. Other key drivers at the $140 million fund, managed by Per Lekander, were long and short bets on utilities, energy infrastructure and renewables, the person said. Lansdowne spokesman Matthew Goodman declined to comment.

Brenham Capital Management, a Dallas, Texas-based long-short equity hedge fund run by John Labanowski, gained 23.2 percent last year, according to an investor letter obtained by Bloomberg. The $824 million fund focuses on small- and mid-cap energy stocks. Dawn Blankenship, Brenham’s director of investor relations, declined to comment.

The energy sector had a few strong performers despite the overall turmoil. Parsley Energy, an Austin, Texas-based exploration and production firm, rose 15.6 percent in 2015. Bets on the stock helped Zimmer Partners, the $1.9 billion hedge fund firm, post a gain last year, according to a person familiar with the matter. Its fund, which makes long and short bets on U.S.-based energy companies was up 3.5 percent, according to an investor letter obtained by Bloomberg. Melanie Ashmore, Zimmer’s head of investor relations, declined to comment.

Refinery stocks were a relative bright spot over the past year, though they were hit hard recently by the U.S.’s lifting of the crude export ban. Many investors have said the end of the ban will eat away at U.S. refiner’s access to cheaper oil. The McGinnis MLP and Energy Fund, which was long on refinery stocks, ended the year up 1.4 percent after a 10.4 percent plunge in December wiped out most of the year’s gains, according to someone familiar with the returns.

Steve Henderlite, chief operating officer at Mission Advisors, the San Antonio, Texas-based energy-focused hedge fund that runs the McGinnis fund, is still bullish on refineries.

“We don’t think the removal of the ban has significantly changed the story for refiners,” Henderlite said, declining to comment on the returns. Even without a ban, refiners will benefit from cheaper oil from Canada and Mexico, he said.

Shorting Strategies

One of the most profitable strategies has been to bet against the price of oil and other commodities. Hedge fund manager Pierre Andurand, whose commodity-focused hedge fund gained 8 percent last year through Dec. 11, told investors last month that oil may fall to $25 a barrel or lower in the first quarter. Global supplies will continue to grow while global demand growth will slow, which could result in “a test of maximum storage capacity” and “significantly lower crude prices,” he said in a letter. His London-based firm, Andurand Capital Management, manages $615 million.

Shorting strategies helped some commodity trading advisers post double-digit returns last year. Red Rock Capital’s long-short systematic commodity strategy gained 31.3 percent in 2015, according to an investor letter obtained by Bloomberg. Half of last year’s profits were generated by short positions in energy futures such as crude oil, natural gas, gasoline and heating oil, Thomas Rollinger, managing partner and chief investment officer, said in an e-mail.

The $103 million Millburn Commodity Program gained 25.6 percent last year, according to a person with knowledge of the matter. The quantitative fund got about half of its returns from energy bets, according to Barry Goodman, co-chief executive officer of Greenwich, Connecticut-based Millburn Ridgefield Corporation, which manages $1.4 billion.

More Declines

“So far in 2016, our models are forecasting continued near-term declines for crude and the other instruments within the energy sector, although it is important to note that the models can be reasonably quick to adapt when they determine the environment has changed,” Goodman said in an e-mail.

CTAs, which tend to be trend-following, were helped by energy price’s “slow and steady decline over the past two years,” said Melanie Rijkenberg, London-based associate director at the $9 billion fund of hedge funds, Pacific Alternative Asset Management Co. However, “once the trends stop, CTAs tend to struggle, particularly if we enter a directionless regime.”

Betting against energy and energy stocks won’t work forever, Rijkenberg warned. “As the market settles down and oil finds a bottom, there will be more value opportunities to capitalize on,” she said.

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group.

American Energy Partners expands internationally…Aubrey McClendon an irresistible force?

Monday, January 18th, 2016 and is filed under Energy Mergers and Acquisitions

American Energy Partners LP this week signed a $500 million oil and natural gas development deal with Argentina state oil company YPF, marking the Oklahoma City energy firm’s third such international contract.

As in Australia and Mexico, American Energy Partners plans to spent the next three years drilling for oil and natural gas wells in a shale play, using horizontal drilling, hydraulic fracturing and other techniques the domestic energy industry has developed over the past decade.

“We decided over a year ago that we should take the expertise we’ve developed to those countries around the world where the shale code hasn’t been cracked yet,” Aubrey McClendon, CEO of American Energy Partners, told The Oklahoman on Friday. “It’s been tried either by companies too big or too small. We think we have a high level of technical expertise and the ability to watch costs and be the prime mover in combining this world-class technology with world-class cost control.”

Shale and other dense rocks have been found worldwide to be the source rock that has provided the oil and natural gas for traditional development. Shale oil and natural gas reserves have been found in about 110 counties, but companies in recent years have faced challenges developing those resources outside of North America.

“It hasn’t spread to more countries because the rocks aren’t right or the deal terms aren’t right or access is wrong or costs are too high,” McClendon said. “In the three countries we’ve targeted, we believe all of those things are coming together. They have great rock, rule of law, great commercial terms and you’re close enough to civilization to where you can aspire to have costs not identical to the U.S., but close.”

Also, Australia recently built seven new liquefied natural gas export facilities with proximity to Asian markets, and Argentina has government mandated price controls, guaranteeing sales prices of $7.50 per 1,000 cubic feet of natural gas and $67.50 per barrel of oil, well above Friday’s U.S. price of $2.10 and $29.42, respectively.

“Those are two big reasons why we want to be in Argentina,” McClendon said.

The Argentina play is a developed field where several hundred shale wells already have been drilled.

“We think completion technology hasn’t been brought up to U.S. standards,” McClendon said.

The Argentina development includes a pilot area of 55,500 acres. By late 2018, the companies plan to expand into another block that covers 92,600 acres.

“YPF is welcoming a partner that will contribute expertise of the highest level to develop shale oil and gas in our country,” YPF CEO Miguel Galuccio said in a statement. “We believe that this partnership will be very enriching for our company by allowing YPF to accelerate the learning curve.”

American Energy Partners primarily has focused on domestic shale oil and natural gas plays, including the Ohio Utica, Pennsylvania-area Marcellus, the Woodford in western Oklahoma and the Wolfcamp in Texas. The company has about 400 employees in Oklahoma, and about 50 in Texas, McClendon said.

International development is in line with the company’s existing strategy, he said, but the company has no immediate plans to add more international markets.

“Certainly there are things we learn in the U.S. that are applicable overseas, and the things we learn overseas will apply here,” he said. “We think it’s a nice extension of our ability in other plays.”

Low domestic oil and natural gas prices over the past 18 months have led companies to slash domestic drilling budgets and search for new sources of income.

McClendon, however, said he expects prices to soon recover in the United States and throughout the world.

“2016 is going to be a great opportunity,” he said. “We think it will rebound from the bottom of the cycle. Given the number of drilling projects that have been deferred or delayed or cancelled, we think people are too negative on oil and gas prices. I’m optimistic by nature and feel it will turn around faster than others think.”

O. Victor Lattanzi is a Harvard trained market strategist with 12 years experience in the oil and gas industry and current Managing Partner of the Investment Capital Group.

A New Approach to Dealmaking