Natural Gas Drops Below $3 for First Time Since 2012 By Naureen S. Malik – Dec 26, 2014, 2:56:43 PM

Natural Gas Drops Below $3 for First Time Since 2012
By Naureen S. Malik – Dec 26, 2014, 2:56:43 PM Bloomberg

Natural gas slumped below $3 per million British thermal units in New York for the first time since 2012 on speculation that record production will overwhelm demand for the heating fuel.

Futures settled at the lowest in 27 months and have plunged 26 percent in December, heading for the biggest one-month drop since July 2008, as mild weather and record production erased a surplus to year-ago levels for the first time in two years. Temperatures will be mostly above average in the eastern half of the U.S. through Dec. 30, according to Commodity Weather Group LLC.

“We don’t see anything scary in the forecast,” said Stephen Schork, president of Schork Group Inc., a consulting group in Villanova, Pennsylvania. “You had this psyche where people were worried about a polar vortex; we had a cold October and a cold early November, and boom, if you were long you are wrong.”

Natural gas for January delivery fell 2.3 cents, or 0.8 percent, to settle at $3.007 per million Btu on the New York Mercantile Exchange. Futures touched $2.973, the lowest intraday price since Sept. 26, 2012. Volume was 54 percent below the 100-day average for the time of day at 2:32 p.m. Gas dropped 13 percent this week.

Prices broke below several technical support levels, including $3.046 and then $3, and may be headed toward $2.80 or lower, said Schork.

Playing Short

“I am playing this market short,” he said. “Anyone who is selling now is trying to trigger a panic selloff.”

February $2.50 puts were the most active options in electronic trading. The price slipped 0.1 cent to 2.6 cents on volume of 557 as of 2:36 p.m.

Above-normal temperatures in the East this week will give way to mostly seasonal readings from Maine to Florida through Jan. 9, according to Commodity Weather in Bethesda, Maryland. The central states will see below-normal readings on Dec. 31 through the first week of January.

The high in New York tomorrow may be 50 degrees Fahrenheit (10 Celsius), 10 more than usual, data from AccuWeather Inc. in State College, Pennsylvania, show. Chicago temperatures may reach 46 degrees, 13 above normal.

Fracking

An estimated 49 percent of U.S. households use gas for heating, led by the Midwest and Northeast, according to the Energy Information Administration.

“We haven’t seen a lot of cold weather this winter,” said Carl Larry, a Houston-based director of oil and gas at Frost & Sullivan. “The warmer it stays, the more pressure on natural gas. Gas production is not dropping and demand is not that high.”

Rising Output

In the absence of extreme weather, rising production will leave inventories at an all-time high above 4 trillion cubic feet by the end of October 2015, BNP Paribas SA said in a report Dec. 23.

BNP Paribas lowered its estimate for average 2015 gas prices to $3.60 per million Btu from $3.75.

“Unseasonably warm weather this month now necessitates extreme conditions ahead in order to avert a surplus,” Teri Viswanath, director of commodities strategy for the bank in New York, said in the report.

Gas stockpiles fell by 49 billion cubic feet to 3.246 trillion cubic feet in the seven days ended Dec. 19, below the five-year average withdrawal for the fourth straight week, EIA data show.

Supplies were 150 billion, or 4.9 percent, higher than year-earlier levels. The surplus will “balloon to just shy of 200 billion cubic feet” by the start of next year, according to JPMorgan Chase & Co.

Record-High Production

Production of the heating and power plant fuel expanded in 2014 to an all-time high for the fourth consecutive year, rising 5.5 percent to 74.26 billion cubic feet a day, EIA data show. Daily output will rise another 3.1 percent next year to 76.58 billion, marking a decade of gains as technologies such as hydraulic fracturing, or fracking, made it more economic to extract fuel from shale rock.

The Marcellus formation in the East has emerged as the biggest driver of gas production growth in the U.S. Production from the shale formation may average 16.3 billion cubic feet a day in January, up 19 percent from a year earlier, the EIA said in its monthly Drilling Productivity Report on Dec. 8.

“This market continues to look oversupplied,” Aaron Calder, senior market analyst at Gelber & Associates in Houston, said by phone on Dec. 24.

Bears’ Takeover

Low gas prices are “eventually going to provide some sort of floor” by prompting power generators to switch from burning coal, said Calder. “This withdrawal shows that it’s going to be a while coming. In the meantime, we are going to see bears take over this market.”

The relative strength index, a technical momentum indicator, declined to 28.8 at 2:36 p.m., falling below 30, a reading considered by some traders to be a buy signal, for the first time since July. The RSI had risen to more than 74 in October before the recent selloff.

“A lot of people came in trading natural gas not really understanding what a powder keg it is in the energy sector,” Schork said. “This is the most volatile market but had been lying dormant for four or five years. The fact that its breaking the $3 barrier, at this point buy at your own risk.”

To contact the reporter on this story: Naureen S. Malik in New York at nmalik28@bloomberg.net

To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Charlotte Porter,

Why Saudis Decided Not to Prop Up Oil – WSJ

WORLD NEWS
Why Saudis Decided Not to Prop Up Oil
In American Shale Oil, A Perceived Threat to OPEC Market Share

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By JAY SOLOMON in Washington and SUMMER SAID in Dubai
Dec. 21, 2014 10:33 p.m. ET

In early October, Saudi Arabia’s representative to OPEC surprised attendees at a New York seminar by revealing his government was content to let global energy prices slide.
Nasser al-Dossary ’s message broke from decades of Saudi orthodoxy that sought to keep prices high by limiting global oil production, said people familiar with the session. That set the stage for Saudi Arabia’s oil mandarins to send crude prices tumbling late last month after persuading other members of the Organization of the Petroleum Exporting Countries to keep production steady.

Hard-hit countries like Iran, Russia and Venezuela suspected the move was a coordinated effort between the oil kingdom and its longtime ally, the U.S., to weaken their foes’ economies and geopolitical standing.

But the story of Saudi Arabia’s new oil strategy, pieced together through interviews with senior Middle Eastern, American and European officials, isn’t one of an old alliance. It is a story of a budding rivalry, driven by what Saudi Arabia views as a threat posed by American energy firms, these officials said.

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Shale-oil production in places like Texas and North Dakota has boosted U.S. output, displacing exports to the U.S. from OPEC members and adding to global oversupply.

RELATED COVERAGE

Mr. Dossary’s October message signaled a direct challenge to North American energy firms that the Arab monarchy believes have fueled a supply glut by using new shale-oil technologies, said the people familiar with the session.
Saudi officials became convinced they couldn’t bolster prices alone amid the new-crude flood. They also concluded many other OPEC members would balk at meaningful cuts, as would big non-OPEC producers like Russia and Mexico. If Riyadh cut production alone, Saudi officials feared, other producers would swoop in and steal market share.
Saudi oil minister Ali al-Naimi tested that conclusion just 48 hours before the Nov. 27 OPEC decision, meeting in Vienna with oil heads of several big producer nations to suggest a coordinated output cut. As he suspected going in, he couldn’t get an agreement, said people familiar with the meeting.

The option left: Let prices slide to test how long, and at what levels, American shale producers can keep pumping.

OPEC’s Nov. 27 move helped drive crude prices to below $60 a barrel from over $100 this summer. It fueled discord among OPEC’s members—and among other energy powers—who have grown accustomed to triple-digit oil prices padding their governments’ balance sheets.

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Mr. Naimi on Thursday said Saudi Arabia and OPEC had no choice but to keep production at current levels amid the price weakness.
“In a situation like this, it is difficult, if not impossible for the kingdom or OPEC, to take any action that may result in lower market share and higher quotas from others, at a time when it is difficult to control prices,” the official Saudi press agency quoted him as saying. Mr. Naimi didn’t respond to inquiries. Saudi oil-ministry representatives wouldn’t comment for this article.
The Saudi approach is part of a significant evolution in Riyadh’s relationship with Washington over the past decade. Close allies since World War II, the countries prospered on the kingdom’s providing a steady oil flow in exchange for America’s securing its borders.
But the U.S.’s emergence as an energy rival is testing this foundation in ways not yet widely appreciated, said U.S. and Saudi officials, as have major differences over American Middle East policies.
Saudi Arabia is taking a risk by letting oil prices plunge, said Arab, American and European officials. Saudi officials have said their economy can survive at least two years with low prices, thanks partly to the kingdom’s $750 billion foreign-exchange reserves. Arab officials believe many less-efficient producers will be driven out of the market.
Still, some oil-industry executives said, Riyadh and Mr. Naimi may underestimate how technology and the shale-oil boom have fundamentally altered energy markets. Many U.S. companies, they said, can make money or break even with oil below $40.
The move has also exposed cracks inside the Saudi ruling circle. In October, as the oil-price slide accelerated, billionaire Prince al-Waleed bin Talal, a nephew to King Abdullah, castigated Mr. Naimi in an open letter for appearing to shrug off price declines. Belittling the impact, he wrote, “is a catastrophe that cannot go unmentioned.”

OPEC’s Dilemma

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At about that time, Mr. Naimi’s deputy, Prince Abdulaziz bin Salman, another nephew of the king, worried to colleagues that the kingdom’s budget couldn’t bear lower prices long, said people familiar with the matter. The offices of Prince Abdulaziz and Prince al-Waleed didn’t respond to inquiries.
Saudi Arabia and its massive energy reserves have played a major role in shaping world affairs for 50 years. During the 1980s, the Reagan administration credited the Saudis with maintaining high oil production to drive down prices and weaken the Soviet Union’s finances. The price drop also fueled an economic recovery in the U.S.
A spokesman for the National Security Council on Sunday said Washington’s alliance with Saudi Arabia remains strong and focused on cooperation on numerous economic and security issues. “Our bilateral relationship is built on over 70 years of close cooperation whether it is counterterrorism, military to military training, educational exchanges, energy security, or bolstering trade and investment,” said NSC spokesman Alistair Baskey.
President Barack Obama ’s administration has worked closely with Saudi Arabia to try using energy markets to pressure Iran into constraining its nuclear program, according to U.S. and Saudi officials.
Beginning in 2009, U.S. officials coordinated with Saudi Arabia, the United Arab Emirates and Kuwait to assure major buyers of Iranian oil would have alternatives if they weaned themselves off Tehran.
The strategy helped the West cut by half Iran’s energy exports over the past three years, said Robert Einhorn, who coordinated U.S. sanctions on Iran in the Obama administration. “What made this possible was that the Saudis and others were able to produce more.”
But Washington’s relations with Riyadh have soured in recent years due to differences over the Obama administration’s handling of Middle East political instability. King Abdullah was incensed last year when Mr. Obama reneged on his pledge to launch military strikes against Syrian President Bashar al-Assad ’s regime following its alleged poison-gas use against civilians. Saudi officials also felt deceived after the Obama administration launched secret nuclear negotiations in 2012 with Iran, Riyadh’s regional rival.
OPEC: The Cartel is Standing Pat on Production, for Now

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“Saudi Arabia’s reliance on U.S. protection is a thing of the past,” said Nawaf Obaid, a visiting scholar at Harvard University’s Belfer Center who has advised the Saudi government on foreign policy. “The Saudis will remain America’s most important strategic partner in the Middle East, but not its closest.”
Washington is entering a new era in its Saudi Arabia relationship, although the alliance remains crucial to the global economy, said Amos Hochstein, the U.S. State Department’s special envoy and coordinator for international energy affairs.
“Our relationship with Saudi Arabia was never dependent on energy. Our relationship is evolving,” he said. “We will never be energy independent because it’s a global commodity. But we can be more efficient and self-sufficient.”
The American energy boom has further complicated relations, said U.S. and Saudi officials. Senior Saudi officials have appeared perplexed in recent months in gauging the impact of the American boom.
In late September, Ibrahim al-Muhanna, a top adviser to Mr. Naimi, said publicly in Bahrain he didn’t foresee oil prices falling much below $90 a barrel due to what he said was the high cost of extracting North American shale oil. He didn’t respond to inquiries.
The Saudis largely kept silent as prices kept falling. Then Mr. Naimi went on vacation in late September, removing himself from a public debate over whether OPEC should rein in production at its November meeting.
Mr. Naimi tended sheep before starting as an errand boy at Saudi Aramco, the national oil company. He worked his way to chief executive before becoming minister in 1995. He won a reputation for data-driven decision making. In the late 1990s, he focused on U.S. Midwest commercial crude-oil inventories—if levels got too high, OPEC needed to cut.
Which Oil Producers Are Breaking Even?

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Mr. Naimi’s comments can rattle or soothe oil markets. So his vacation’s timing puzzled many of his colleagues, said people familiar with the matter, and during his absence there was bickering inside the government about how to arrest the price decline. The question: whether to focus on stopping the short-term revenue impact of the price decline or to exploit the medium-term potential of its reducing competition from North American shale producers.
Meanwhile, OPEC members were slashing prices, often undercutting one another. In early November, Saudi Aramco cut prices to U.S. customers, a move aimed at locking in customers as shale output swelled, industry officials said.
Returning from his holiday, Mr. Naimi met with Venezuela’s foreign minister and its chief OPEC representative, Rafael Ramirez, on a Venezuelan resort island. Privately, the Saudi told his hosts he would support a production cut only if the Venezuelans could persuade producers inside and outside OPEC to participate, people briefed on the meeting said. A Venezuelan foreign ministry spokeswoman declined to comment.
Mr. Ramirez traveled to Russia, Algeria, Iran and Qatar to woo production-cut support. Two days before OPEC’s Nov. 27 meeting, he gathered senior energy officials from Russia, Mexico and Saudi Arabia—including Mr. Naimi—at Vienna’s Hyatt Hotel.
On the table was a proposal to take two million barrels a day off the market, officials familiar with the talks said. OPEC would shoulder the bulk of the cut, but Russia and Mexico were expected to trim a combined 500,000 daily barrels.
Mr. Naimi had expected Russia to balk, these people said. Indeed, the Russian delegates said they couldn’t cut production for technical reasons and because they might lose pumping capacity by shutting wells. An official at OAO Rosneft, the Russian state oil company, confirmed the meeting took place but denied there were discussions about an output cut.
The discussions never made it as far as what Mexico might be willing to do. “From the start, Russia made it clear that it wasn’t going to cut production, and the meeting ended there,” said a person familiar with the discussion. A Mexican energy-ministry spokesman didn’t respond to inquiries.
Mr. Naimi argued it was in everyone’s interest to take collective action and that the market would eventually force the Russians to cut. Russia, he said, couldn’t keep producing roughly 10 million barrels a day unless oil prices were over at least $100.
Mr. Naimi headed to the Nov. 27 OPEC meeting with King Abdullah’s support to align OPEC’s Arab states behind a policy of no production cuts and of defending market share, said people familiar with his mandate. The U.A.E., Kuwait and Qatar gave their support ahead of the meeting.
At the meeting, Mr. Naimi addressed other OPEC ministers, who were asked to leave aides outside the room. He conceded falling prices would be painful but said losing customers to U.S. shale would be worse, people briefed on his comments said.
Mr. Naimi wasn’t advocating forcing down prices to hurt U.S. shale producers, these people said, but was warning that if OPEC cut output, non-cartel crude would likely replace it. OPEC ministers agreed to keep their production ceiling unchanged.
Sell orders flooded oil markets. Shares in big producers tumbled, along with currencies of petro-states like Russia and Nigeria.
U.S. and Arab officials have privately gushed that the decline could undercut the ability of Tehran, Moscow and Caracas to play destabilizing roles globally, and have voiced optimism that Iran’s financial woes could force it into more nuclear concessions.
“If in the process, you have 30% off Iran’s income, fine,” said a senior Arab official involved in the oil deliberations. “If in the process, you shave 30% off Russia’s income, fine.”
There remains a risk prices don’t quickly recover. Some in the Saudi media have criticized Mr. Naimi for a policy they say could be disastrous for the kingdom’s economy. Riyadh depends on oil for 90% of its budget.
“All OPEC and non-OPEC officials are in a state of shock,” said Muhammad al-Sabban, a former adviser to Mr. Naimi, adding that a “ ‘wait and see’ is their only option.”
—Benoît Faucon, Sarah Kent and Kejal Vyas contributed to this article.
Write to Jay Solomon at jay.solomon@wsj.com and Summer Said at summer.said@wsj.com

Oil Crash Exposes New Risks for U.S. Shale Drillers

Photographer: Andrew Burton/Getty Images

U.S. shale oil production.

Tumbling oil prices have exposed a weakness in the insurance that some U.S. shale drillers bought to protect themselves against a crash.

At least six companies, including Pioneer Natural Resources Co. (PXD) and Noble Energy Inc. (NBL), used a strategy known as a three-way collar that doesn’t guarantee a minimum price if crude falls below a certain level, according to company filings. While three-ways can be cheaper than other hedges, they can leave drillers exposed to steep declines.

“Producers are inherently bullish,” said Mike Corley, the founder of Mercatus Energy Advisors, a Houston-based firm that advises companies on hedging strategies. “It’s just the nature of the business. You’re not going to go drill holes in the ground if you think prices are going down.”

Oil Prices

The three-way hedges risk exacerbating a cash squeeze for companies trying to cope with the biggest plunge in oil prices this decade. West Texas Intermediate crude, the U.S. benchmark, dropped about 50 percent since June amid a worldwide glut. The Organization of Petroleum Exporting Countries decided Nov. 27 to hold production steady as the 12-member group competes for market share against U.S. shale drillers that have pushed domestic output to the highest since at least 1983.

WTI for January delivery rose $2.41, or 4.5 percent, to settle at $56.52 a barrel today on the New York Mercantile Exchange.

Debt Price

Shares of oil companies are also dropping, with a 49 percent decline in the 76-member Bloomberg Intelligence North America E&P Valuation Peers index from this year’s peak in June. The drilling had been driven by high oil prices and low-cost financing. Companies spent $1.30 for every dollar earned selling oil and gas in the third quarter, according to data compiled by Bloomberg on 56 of the U.S.-listed companies in the E&P index.

Financing costs are now rising as prices sink. The average borrowing cost for energy companies in the U.S. high-yield debt market has almost doubled to 10.43 percent from an all-time low of 5.68 percent in June, Bank of America Merrill Lynch data show.

Locking in a minimum price for crude reassures investors that companies will have the cash to keep expanding and lenders that debt can be repaid. While several companies such as Anadarko Petroleum Corp. (APC), Bonanza Creek (BCEI) Energy Inc., Callon Petroleum Co., Carrizo Oil & Gas Inc. and Parsley Energy Inc., use three-way collars, Pioneer uses more than its competitors, company records show.

‘Best Hedges’

Scott Sheffield, Pioneer’s chairman and chief executive officer, said during a Nov. 5 earnings call that his company has “probably the best hedges in place among the industry.” Having pumped 89,000 barrels a day in the third quarter, Pioneer is one of the biggest oil producers in U.S. shale.

Pioneer used three-ways to cover 85 percent of its projected 2015 output, the company’sDecember investor presentation shows. The strategy capped the upside price at $99.36 a barrel and guaranteed a minimum, or floor, of $87.98. By themselves, those positions would ensure almost $34 a barrel more than yesterday’s price.

However, Pioneer added a third element by selling a put option, sometimes called a subfloor, at $73.54. That gives the buyer the right to sell oil at that price by a specific date.

Below that threshold, Pioneer is no longer entitled to the floor of $87.98, only the difference between the floor and the subfloor, or $14.44 on top of the market price. So at yesterday’s price of $54.11, Pioneer would realize $68.55 a barrel.

‘Better Upside’

David Leaverton, a spokesman for Irving, Texas-based Pioneer, declined to comment on the company’s hedging strategy. The company said in its December investor presentation that “three-way collars protect downside while providing better upside exposure than traditional collars or swaps.”

The company hedged 95,767 barrels a day next year using the three-ways. If yesterday’s prices persist through the first quarter, Pioneer would realize $1.86 million less every day than it would have using the collar with the floor of $87.98. That would add up to more than $167 million in the first quarter, equal to about 14 percent of Pioneer’s third-quarter revenue.

Exposure Cost

The strategy ensures that the bulk of Pioneer’s production will earn more than yesterday’s market price. The three-ways will also prove valuable if oil rises above the subfloor.

“What they have is much better than nothing,” said Tim Revzan, an analyst with Sterne Agee Group Inc. in New York. “But they left some money on the table that they could have locked in at a better price.”

Noble Energy used three-ways to hedge 33,000 barrels a day, according to third-quarter SEC filings. Assuming yesterday’s prices persist, Houston-based Noble will bring in $50 million less in the first quarter than it would have by locking in the floor prices.

Bonanza Creek, based in Denver, Colorado, set up three-ways with a floor of $84.32 and a subfloor of $68.08, SEC records show. If prices stay where they are, the company will realize $8.1 million less in the first quarter than it would have by just using the floor.

Ryan Zorn, Bonanza Creek’s senior vice president of finance, said that the comparison doesn’t take into account the advantages of the strategy. The proceeds from selling the $68.08 puts helped pay for the protection at $84.32, without which Bonanza Creek would likely have purchased cheaper options with a lower floor.

’Much Better’

“The other comparison is if we’d done nothing,” Zorn said. “I view it as being much better than being unhedged.”

Representatives for Anadarko, Noble, Carrizo and Parsley didn’t return e-mails and phone calls seeking comment.

“Because we’ve had high energy prices for so long, it could have given them a false sense of confidence,” said Ray Carbone, president of Paramount Options Inc. in New York. “They picked a price they thought it wouldn’t go below. It has turned out to be very expensive.”

Callon (CPE)’s first-quarter three-ways cover 158,000 barrels with a floor of $90 and a subfloor of $75, company filings show. Callon, based in Natchez, Mississippi, will get $3.3 million less that it would have realized by using the $90 floor, assuming prices stay where they are.

“Certainly, if we’d had the foresight to know prices were going to crater, you’d want to be in the swap instead of the three-way,” said Eric Williams, a spokesman for Callon. “Swaps make more sense if you knew prices were going to go down the way they did, but a few months ago everyone was bullish.”

To contact the reporter on this story: Asjylyn Loder in New York at aloder@bloomberg.net

To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Richard Stubbe

Fed Bubble Bursts in $550 Billion of Energy Debt: Credit Markets By Christine Idzelis and Craig Torres – Dec 11, 2014, 10:59:52 AM

The danger of stimulus-induced bubbles is starting to play out in the market for energy-company debt.

Since early 2010, energy producers have raised $550 billion of new bonds and loans as the Federal Reserve held borrowing costs near zero, according to Deutsche Bank AG. With oil prices plunging, investors are questioning the ability of some issuers to meet their debt obligations. Research firm CreditSights Inc. predicts the default rate for energy junk bonds will double to eight percent next year.

“Anything that becomes a mania — it ends badly,” said Tim Gramatovich, who helps manage more than $800 million as chief investment officer of Santa Barbara, California-based Peritus Asset Management. “And this is a mania.”

The Fed’s decision to keep benchmark interest rates at record lows for six years has encouraged investors to funnel cash into speculative-grade securities to generate returns, raising concern that risks were being overlooked. A report from Moody’s Investors Service this week found that investor protections in corporate debt are at an all-time low, while average yields on junk bonds were recently lower than what investment-grade companies were paying before the credit crisis.

Borrowing costs for energy companies have skyrocketed in the past six months as West Texas Intermediate crude, the U.S. benchmark, has dropped 44 percent to $60.46 a barrel since reaching this year’s peak of $107.26 in June.

Yields Surge

Yields on junk-rated energy bonds climbed to a more-than-five-year high of 9.5 percent this week from 5.7 percent in June, according to Bank of America Merrill Lynch index data. At least three energy-related borrowers, including C&J Energy Services Inc. (CJES ▼ -3.13% 12.07), postponed financings this month as sentiment soured.

“It’s been super cheap” for energy companies to obtain financing over the past five years, said Brian Gibbons, a senior analyst for oil and gas at CreditSights in New York. Now, companies with ratings of B or below are “virtually shut out of the market” and will have to “rely on a combination of asset sales” and their credit lines, he said.

Companies rated Ba1 and lower by Moody’s and BB+ and below by Standard & Poor’s are considered speculative grade.

Stimulus Effect

The Fed’s three rounds of bond buying were a gift to small companies in the capital-intensive energy industry that needed cheap borrowing costs to thrive, according to Chris Lafakis, a senior economist at Moody’s Analytics in West Chester, Pennsylvania.

Quantitative easing “has been one of the keys to the fast, breakneck pace of the growth in U.S. oil production which requires abundant capital,” Lafakis said.

One of those to take advantage was Energy XXI Ltd. (EXXI ▼ -1.39% 2.84), an oil and gas explorer, which has raised more than $2 billion in the bond market in the past four years.

The Houston-based company’s $750 million of 9.25 percent notes, issued in December 2010, have tumbled to 64 cents on the dollar from 106.3 cents in September, according to Trace, the bond-price reporting system of the Financial Industry Regulatory Authority. They yield 27.7 percent.

Energy XXI got its lenders in August to waive a potential violation of its credit agreement because its debt had risen relative to its earnings, according to a regulatory filing. In September, lenders agreed to increase the amount of leverage allowed.

Bubble Risk

“We think the sell-off has been a little over done,” said Greg Smith, a vice president in Energy XXI’s investor relations department. “People are trading us as though we’re distressed.”

The company has “plenty of liquidity,” Smith said. “Come January we’ll be free cash flow positive,” which is “a rarity in this business,” he said.

The debt rout is one of the latest examples of a boom and bust in U.S. markets as unprecedented Fed stimulus fuels a hunt for yield. The fallout has been limited so far, yet the longer the Fed holds its benchmark lending rate near zero, the greater the risk of more consequential bubbles, according to former Fed governor Jeremy Stein.

“To the extent that highly accommodative monetary policy courts risks to the economy further down the road, there is more of a live trade-off than there was at 8 percent unemployment” said Stein, now a Harvard University professor.

Joblessness of 5.8 percent in November was about half a percentage point away from the Fed’s estimate of full employment, or the lowest level of labor market slack the economy can sustain before companies bid up wages.

Job Creation

Employment in support services for oil and gas operations has surged 70 percent since the U.S. expansion began in June 2009, while oil and gas extraction payrolls have climbed 34 percent.

“There are distortions in multiple markets,” said Lawrence Goodman, president of the Center for Financial Stability, a monetary research group in New York. “It is like a Whac-A-Mole game: You don’t know where it is going to pop up next.”

Fed Chair Janet Yellen said in a July 2 speech in Washington that she saw “pockets of increased risk-taking,” including in the corporate debt markets.

Midstates Petroleum Co. (MPO ▼ -11.56% 1.30) is spending about $1.15 drilling for every dollar earned selling oil and gas. Outspending cash flow is the norm for many companies in the U.S. shale boom.

Changing Environment

The Houston-based company’s $700 million of 9.25 percent notes due in June 2021 have plummeted to 53.5 cents from 108 cents at the beginning of September, according to Trace. The debt is rated Caa1 by Moody’s and B- by S&P.

Representatives of Midstates didn’t respond to phone calls and e-mails seeking comment.

Some borrowers are under pressure just a few months after selling new debt. Sanchez Energy Corp.’s $1.15 billion of 6.125 percent notes maturing in January 2023, issued this year, have tumbled to 77 cents from 101 cents in September, according to Trace. Proceeds from the bonds were partly used to fund a purchase of Eagle Ford shale assets from Royal Dutch Shell Plc. (RDSA ▲ 0.78% 25.97)

“The company has planned for and is poised to rapidly adapt to a changing commodity price environment,” Tony Sanchez, III, chief executive officer of Sanchez Energy, said in a statement yesterday.

The Houston-based company expects to fully fund its 2015 capital program from operating cash flow and cash on hand without drawing on its revolving credit line, the statement said.

Magnum Hunter

Sanchez Energy has never had positive free cash flow. Michael Long, chief financial officer, didn’t return a call seeking comment.

“Oil companies that have high funding costs in the Eagle Ford and the Bakken shale plays are the ones that are most exposed right now due to lower crude prices,” Gary C. Evans, chief executive officer of Magnum Hunter Resources (MHR ▼ -4.16% 3.46) Corp., said in a phone interview.

Magnum Hunter’s $600 million of 9.75 percent debt due in 2020 has tumbled to 84.5 cents from 109 cents in September, Trace data show. The notes are rated CCC by S&P and yield 13.9 percent.

Evans said Houston-based Magnum Hunter sold almost all of its oil properties over the last year and a half and is now predominantly a gas company.

Default Risk

“We’ve insulated ourselves,” Evans said. For other energy borrowers at risk, “the liquidity squeeze” will probably occur in March or April when banks re-calculate have much they may borrow under their credit lines based on the value of their oil reserves.

Deutsche Bank analysts predicted in a Dec. 8 report that about a third of companies rated B or CCC may be unable to meet their obligations should oil prices drop to $55 a barrel.

“If you keep oil prices low enough for long enough, there is a pretty good case that some of the weakest issuers in the high-yield space will run into cash-flow issues,” Oleg Melentyev, a New York-based credit strategist at Deutsche Bank, said in a telephone interview.

For Related News and Information: Junk Fervor Cools as Oil Rout Upends Energy Debt: Credit Markets Junk Backing Shale Boom Faces $11.6 Billion Loss: Credit Markets Shale Boom’s Allure to Wall Street Tested by Drop in Oil Prices Oil Slump Heaps Bond Losses in $50 Billion Glut: Credit Markets Drillers Piling Up More Debt Than Oil Hunting Fortunes in Shale

To contact the reporters on this story: Christine Idzelis in New York at cidzelis@bloomberg.net; Craig Torres in Washington at ctorres3@bloomberg.net

To contact the editors responsible for this story: Shannon D. Harrington at sharrington6@bloomberg.net Caroline Salas Gage, Faris Khan

BUSINESS Oil’s Fall Puts a Chill on U.S. Drilling Energy Firms Slash Spending, Staff as Crude’s Decline Accelerates

By LYNN COOK and ERIN AILWORTH WSJ
Dec. 10, 2014 7:15 p.m. ET

U.S. energy companies are starting to cut drilling, lay off workers and slash spending in the face of an accelerating decline in oil prices, which fell to a fresh five-year low Wednesday.

The number of rigs drilling for oil in North Dakota and parts of Texas has started to edge down, new drilling permits have dropped sharply since October, and many companies say they are going to focus on their most profitable wells.

EOG Resources Inc. this week said it would shed many of its Canadian oil and gas fields, close its Calgary office and lay off employees there as it refocuses in the U.S. Matador Resources Co. of Dallas is contemplating temporarily leaving the prolific Eagle Ford Shale area in South Texas in favor of drilling elsewhere in Texas and New Mexico where it can make more money.

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Investors sold off shares of energy companies including EOG as the U.S. benchmark oil price fell to $60.94 on Wednesday. EOG lost nearly 3% to $86.79 while shale specialists Continental Resources Inc. and Chesapeake Energy Corp. both declined about 7%. Many of these U.S. independent drillers have lost half their value since June.

Shares of global energy giants have fared better than the independent U.S. companies because their refining operations are benefiting from cheaper oil. But some of the biggest are disclosing cutbacks.

BP PLC, which has been cutting back since the Deepwater Horizon oil spill in 2010, outlined a further $1 billion restructuring on Wednesday. ConocoPhillips , one of the biggest shale producers in the U.S., recently said it would spend 20% less next year on drilling wells, honing in on its sweetest spots instead of drilling its more expensive areas like Colorado’s Niobrara.

“At this point a contraction is unavoidable,” said Karr Ingham, economist for the Texas Alliance of Energy Producers.

One reason for the stock declines is investors are skeptical: Whatever their plans, U.S. companies produced 9.1 million barrels a day last week, the highest level since 1983, according to federal data. There is so much oil sloshing around the U.S. that refiners can’t use it all, so 1.5 million barrels of crude went into U.S. oil stockpiles last week.

ENLARGE
Some companies will be able to keep pumping even at lower prices, depending on the location and quality of their wells. Enterprise Products Partners LP, which operates pipelines and oil storage terminals across the U.S., said its analysis shows that the average well in many shale formations aren’t profitable at $60 oil. But wells considered high grade can withstand much lower prices. For instance, some wells in South Texas are profitable at prices of $30 a barrel, while the best in North Dakota’s Bakken area can only withstand a drop to under $50 a barrel.

Energy companies’ hedging strategies run the gamut from Continental Resources, which cancelled nearly all its price hedges and projected oil prices would soon rise, to Pioneer Natural Resources Co. of Irving, Texas, which has hedged 85% of its oil and gas output for 2015. Companies that hedged their production aren’t as exposed to falling prices and may not have to pump less or curb spending as quickly.

Surging American oil output has helped create a global glut of oil that has sent prices spiraling downward. The benchmark U.S. oil price, which briefly rose above $107 a barrel in late June, closed below $61 a barrel Wednesday, down 43% since its summer high.

Drilling permits issued in the U.S. dropped 36% between October and November, according to data from Drillinginfo, but remain 13% above their year earlier level.

Another sign of the energy industry’s pullback: the number of rigs drilling for oil in the Eagle Ford Shale in Texas has started to drop. Drilling in the nation’s second most active oil region hit a peak of 210 rigs in July but recently fell to 190 rigs.

These declines don’t necessarily mean that U.S. oil output will fall, said Greg Haas, a director at research firm Stratas Advisors in Houston, because companies are getting more efficient at drilling. “It used to be if the rig count dropped then oil production dropped, but not anymore,” he said.

In a sense, energy companies are a victim of their own success. EOG, Chesapeake and others learned to drill and frack wells faster and wring more from each well. Chesapeake says its initial production at new wells in the Eagle Ford improved by 65% over the last five years.

Houston-based EOG took 22 days to drill a well in South Texas in 2011; today it takes less than nine days. The company recently said it can earn a 10% profit after taxes even if oil prices were to fall to $40 a barrel.

However, companies with a lot of debt, low rates of return and little chance of drilling their way to better profitability will be hurt if crude remains below $75 a barrel, according to analysts at Global Hunter Securities.

Among the companies they cited was Triangle Petroleum Corp. Jon Samuels, president of the Denver-based independent explorer, said his company is profitable at the current price of oil.

Triangle’s shares are down 47% in the last two months. It is pushing vendors for cheaper prices for drilling equipment and contract labor in the new year, which should help bring down costs, he said.

“You’re going to see activity levels and spending go down substantially compared to this year,” Mr. Samuels said, adding that the stock market reaction to crude’s price drop has been overblown.

Write to Lynn Cook at lynn.cook@wsj.com and Erin Ailworth at Erin.Ailworth@wsj.com

Will Wildcatter’s ‘Naked’ Gamble on Oil Prices Pay Off? Continental Resources CEO Hamm Sells Hedges, Betting on Quick Rebound in Crude

By ERIN AILWORTH, GREGORY ZUCKERMAN and DANIEL GILBERT WSJ
Dec. 9, 2014 12:35 p.m. ET

Harold Hamm ’s willingness to make risky bets helped him build Continental Resources Inc. into the one of the biggest oil producers in North Dakota’s Bakken Shale and a symbol of the U.S. energy boom. But his latest gamble—a quick rebound in crude prices—is rubbing some investors and analysts the wrong way.

Mr. Hamm, who founded Continental and owns 68% of its shares, announced in early November that the company had cashed in almost all of its financial hedges that guaranteed it could sell millions of barrels of oil for about $100 apiece. The company said it had realized $433 million in cash from selling the hedges, some of which ran through 2016.

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“We feel like we’re at the bottom rung here on prices and we’ll see them recover pretty drastically, pretty quick,” Mr. Hamm said on a Nov. 5 call with analysts. He said the Organization of the Petroleum Exporting Countries was pushing down oil prices to slow America’s expanding energy output.

Now, removing the hedges, known in the industry as “going naked,” looks misguided even to some of the company’s fans, after the recent tumble for oil prices. The benchmark price for U.S. oil has continued to slide, falling from $81 in late October to $63.82 on Tuesday.

If Continental had kept the contracts that insured it against lower crude prices, it could have reaped $52 million more for its oil in November, according to a Wall Street Journal review of company disclosures. And it might have received $75 million more this month, assuming current conditions continue.

The Journal’s calculation of about $127 million in forgone revenue is similar to projections by several Wall Street analysts, and those projections would continue to rise in the coming months if oil prices remain below $96 a barrel.

ENLARGE
The company said it disagreed with the Journal’s figures but wouldn’t provide its own, except to say that after figuring in revenue it received for selling its hedges, it expects the “net negative effect” to be $25 million to $30 million in November and December. It sold nearly $1.2 billion of oil and gas in the third quarter and reported net income of $533 million.

“It was a bad move with terrible timing,” said Gregg Jacobson, a portfolio manager at Caymus Capital Partners LP, a $200 million Houston hedge fund manager that had about 4.5% of its portfolio in Continental shares as of the end of the third quarter. Though he thinks the hedging sale will prompt some investors to view the company as unusually risky, Mr. Jacobson said he remains a supporter because of its executives’ skill in finding and drilling for oil.

“In the long run, the stock will respond to how they perform in the field,” he said.

While shares of many U.S. energy producers have had double-digit percentage declines since oil prices began falling in late June, Continental’s stock has been hammered. Its shares, which closed up 7.2% at $36.18 on Tuesday, have fallen by more than half since the end of August, and more than 25% since Mr. Hamm disclosed on Nov. 5 that the company had sold the hedges.

Mr. Hamm said in an interview that he still believes his bet could pay off but that it might take as many as two years to tell. “You can’t condemn that as a bad decision,” he said. “You haven’t seen it play out.”

Companies like Continental can react quickly to market changes, he said, which gives them an advantage over OPEC’s members. The cartel is discounting “the resiliency of U.S. producers,” he said, adding that investors “need to look at Continental long-term.”

A wildcatter—he has called himself an “explorationist”—Mr. Hamm started the company that would become Continental in 1967 and first struck oil in 1971 in Oklahoma. More than two decades ago, he began focusing on exploring the then-little-known Williston Basin, which stretches from South Dakota to the Canadian province of Saskatchewan. Over time, his company became a leader in the Bakken formation in North Dakota, which has become one of the biggest oil fields in the U.S.

Continental produced nearly 35 million barrels of oil last year, almost four times what it was producing five years earlier. That growth has helped push U.S. oil output to more than 9 million barrels of crude a day, up from 5 million in 2008.

Though Continental has become a leader of the U.S. energy boom, it is unusual. Institutional and activist investors have curbed some of the risk-taking of wildcatters at other energy outfits, and few companies of Continental’s size remain controlled by their founders.

Continental said it had 5.2 million barrels insured in November and December at an average price of about $100.

When oil prices are falling, hedges—contracts that many energy companies buy to protect against declining prices by guaranteeing a minimum price for the oil and gas they produce—become much more valuable. Continental notes that several of its competitors aren’t hedged, including Apache Corp. , which has no hedges on the books in 2015. Apache said it does have some production insured through the end of this year.

Mr. Hamm isn’t the first energy executive to abandon hedges. Under the leadership of former CEO Aubrey McClendon , Chesapeake Energy Corp. dropped its natural-gas hedges in 2011, leaving it exposed to a dismal gas market and dealing with a cash crunch the following year.

‘It was a bad move with terrible timing… In the long run, the stock will respond to how they perform in the field’
—Gregg Jacobson, a portfolio manager at Caymus Capital Partners
Continental isn’t likely to face a liquidity crisis—its debt is smaller than many of its competitors at about 1.7 times its cash flow, according to S&P Capital IQ. And the company has $1.75 billion in unused credit, recent financial filings show.

“They’ve built such a good balance sheet, they have the luxury of making this gamble,” said Jason Wangler, an analyst for Wunderlich Securities, who called the move a speculative bet. “They left money on the table in the short term.”

Mr. Hamm, he said, is “the guy you’re investing in, as much as the company.”

Since selling Continental’s hedges, Mr. Hamm has lost about $4.4 billion of his personal fortune as Continental’s shares have fallen—a loss that could be compounded by Mr. Hamm’s divorce. A judge recently awarded the former Mrs. Hamm, Sue Ann Arnall, a nearly $1 billion settlement; she appealed that decision on Friday. Mr. Hamm now owns about $9.2 billion of company stock.

Some investors say Continental’s primary acreage in the Bakken and elsewhere renders the hedging decision less important in the long-term.

“Cash flow next year will be lower and more volatile, assuming prices stay under pressure,” said Joe Chin, an analyst at Obermeyer Wood Investment Counsel LLLP, an Aspen, Colo., firm that owned 340,000 Continental shares at the end of the third quarter. “But we remain confident about management’s ability to deploy capital.”

Write to Erin Ailworth at Erin.Ailworth@wsj.com, Gregory Zuckerman at gregory.zuckerman@wsj.com and Daniel Gilbert at daniel.gilbert@wsj.com

Why Elon Musk’s Batteries Scare the Hell Out of the Electric Company

Why Elon Musk’s Batteries Scare the Hell Out of the Electric Company
By Mark Chediak Bloomberg

December 05, 2014 6:06 PM EST

Climate: Now or Never

Here’s why something as basic as a battery both thrills and terrifies the U.S. utility industry.

At a sagebrush-strewn industrial park outside of Reno, Nevada, bulldozers are clearing dirt for Tesla Motors Inc.’s battery factory, projected to be the world’s largest.

Tesla’s founder, Elon Musk, sees the $5 billion facility as a key step toward making electric cars more affordable, while ending reliance on oil and reducing greenhouse gas emissions. At first blush, the push toward more electric cars looks to be positive for utilities struggling with stagnant sales from energy conservation and slow economic growth.

Yet Musk’s so-called gigafactory may soon become an existential threat to the 100-year-old utility business model. The facility will also churn out stationary battery packs that can be paired with rooftop solar panels to store power. Already, a second company led by Musk, SolarCity Corp., is packaging solar panels and batteries to power California homes and companies including Wal-Mart Stores Inc.

“The mortal threat that ever cheaper on-site renewables pose” comes from systems that include storage, said Amory Lovins, co-founder of the Rocky Mountain Institute, a Snowmass, Colorado-based energy consultant. “That is an unregulated product you can buy at Home Depot that leaves the old business model with no place to hide.”

J.B. Straubel, chief technology officer for Palo Alto, California-based Tesla, said the company views utilities as partners not adversaries in its effort to build out battery storage. Musk was not available for comment.

The Tesla systems are arriving just as utilities begin to feel increasing pressure worldwide from the disruption posed by renewable energy.

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In Germany, the rapid rise of tax-subsidized clean energy has undermined wholesale prices and decimated the profitability of coal and natural gas plants. Germany’s largest utility EON SE said this week it will spin off its fossil-fuel plant business to focus on renewables in part because of new clean energy competitors coming onto its turf.

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Threats to the traditional utility model come as energy and environment take the world stage at the latest round of United Nations climate talks that began Dec. 1 in Lima. Delegates, backed by global environmental groups, want to leave the conference with a draft agreement to tackle climate change by lowering carbon-dioxide emissions — something that has eluded them for years.

The Rocky Mountain Institute’s Lovins has installed solar on his house in Snowmass and uses it to power his electric car. His monthly electric bill: $25. He has a lot of company.

100,000 Plug-ins
In California, where 40 percent of the nation’s plug-in cars have been sold, about half of electric vehicle owners have solar or want to install it, according to a February survey by the Center for Sustainable Energy, a green-energy advocate. More than 100,000 plug-ins have been sold in California, according to data from HybridCars.com and Baum & Associates, though EVs make up less than 1 percent of all U.S. car sales.

Few homes and businesses use solar and back-up-battery storage, proof for some utilities that the systems remain a hard sell outside of states like California or markets like Hawaii where high power costs make solar competitive.

Still, the Edison Electric Institute, a trade group representing America’s investor-owned utilities, recently announced that its members will help to encourage electric vehicle use by spending $50 million annually to buy plug-in service trucks and invest in car-charging technology.

“Advancing plug-in electric vehicles and technologies is an industry priority,” said EEI President Thomas Kuhn.

Charging Stations
Analysts think the industry has been slow to react. Tesla, SolarCity and green-energy companies are already moving aggressively into unoccupied space. “Some of the more nimble companies that think and move more quickly, they are beating the utilities to the punch,” said Ben Kallo, a San Francisco-based analyst for Robert W. Baird & Co.

Tesla has installed 135 fast-charging stations, some powered by solar, across North America where its Model S drivers can refuel for free. NRG Energy Inc. is building a network of public charging stations in major cities that drivers can access on a per-charge basis or for a flat monthly fee of about $15.

And then there’s the home front. In a July report, Morgan Stanley said Tesla’s home and business energy-storage product could be “disruptive” in the U.S. and in Europe as customers seek to avoid utility fees by going “off-grid.”

‘Sufficient Appreciation’
“We believe there is not sufficient appreciation of the magnitude of energy storage cost reduction that Tesla has already achieved, nor of the further cost reduction magnitude that Tesla might be able to achieve once the company has constructed its ‘gigafactory,’” Morgan Stanley analysts wrote.

Tesla sees itself taking on a grand mission — not just to lower emissions from cars and trucks, but to have a societal impact. “If we only do it on the transportation side, we ignore the utility side, and we are probably ignoring half of our responsibility,” said Mateo Jaramillo, director of powertrain business development at Tesla Motors, at the recent Platts California Power and Gas Conference in San Francisco.

Tesla and Oncor Electric Delivery, owner of the largest power-line network in Texas, have discussed a $2 billion investment in stationary battery storage to solve the problem of fluctuating output from wind and solar. Tesla and SolarCity are separate entities and only share management at the board level.

Tesla fell 2 percent today to $223.71 in New York.

Smart Home
A glimpse of that future can be seen in Davis, California, where Honda Motor Co. has developed a “smart home” that produces more energy than it uses while charging a plug-in car. The home was designed in collaboration with SolarCity, PG&E Corp. and the University of California at Davis to showcase energy-efficient and renewable technologies. It will serve as a home for a member of the UC Davis community and a lab for the study of new businesses and technologies.

SolarCity rival SunPower Corp. is offering its solar and storage systems to buyers of electric cars from Audi AG and rebates for solar-panels to Ford Motor Co. plug-in customers. SunPower also has struck a partnership with homebuilder KB Home to begin installing solar and storage systems in California.

The time when residents can charge their electric cars with excess solar stored in their home batteries is “not decades away, that is years away,” said SunPower CEO Tom Werner.

Holy Grail
Both SolarCity and SunPower say their goal isn’t to move customers completely off-grid, just to reduce their dependence on it. “Grid storage has been the Holy Grail for renewables because the energy is intermittent,” Kallo said. “Finding a way to store that is very powerful.”

For the power companies, the stakes are high.

In June, EEI issued a call to action, saying converting people from gasoline cars to electric vehicles is nearly essential for survival. The report concluded: “The bottom line is that the electric utility industry needs the electrification of the transportation sector to remain viable and sustainable in the long run.”

To that point, executives at some of the nation’s largest utilities from New York to California say they are preparing their grids for more plug-in cars, reaching out to automakers and working with regulators to make sure customers as well as the utilities benefit from the trend.

Natural Partnership
“I read a lot of articles about Elon Musk versus the utility companies,” said John Shipman, who heads electric vehicle programs at New York-based Consolidated Edison Co. “I don’t see it that way at all. There is a natural partnership that can exist there.”

In California, where electric vehicle adoption is the highest in the nation, and Governor Jerry Brown has set a goal of having 1.5 million zero-emission vehicles on the road by 2025, utilities are already in the game.

“The electric grid will be just as important in the years to come because the grid is becoming the platform that makes it possible for people to plug in solar panels, batteries and charging stations,” said Ellen Hayes, a PG&E spokeswoman. “Having a solar panel that isn’t connected to the grid is like having a computer that’s not connected to the Internet.”

Edison International’s Southern California Edison and Sempra Energy’s San Diego Gas & Electric have proposed investing about $500 million in car charging stations. Along with PG&E, they are backing a proposal that would loosen restrictions on utilities owning charging facilities.

Grid Upgrades
There is yet another side to the argument — can utilities manage the load?

“Electric vehicles can be the best thing to ever happen to our industry or the worst thing to ever happen to our industry,” said James Avery, a senior vice president at San Diego Gas & Electric.

Avery doesn’t foresee most customers leaving the grid, but does see the risk of an influx of electric cars that overtaxes the network. SDG&E, whose territory has the highest penetration of plug-ins in the U.S., plans to spend as much as $3.2 billion to upgrade its grid. It already offers cheaper rates for EV owners to charge overnight when power demand is lowest.

Southern California Edison is planning to spend about $9.2 billion through 2017 to allow the two-way flow of electricity on its system, said Edison International CEO Ted Craver.

“We are certainly big supporters of electric transportation,” Craver said.

He added: “That electric car isn’t just going to stay at home. It’s going to go other places. It’s going to need to get charged in other places. And I think our ability to provide that glue for all those things that are going to plug into that network is really how we see our core business.”

Shifting Landscape
Some utilities are more amendable to the shifting landscape than others. Last year, Pinnacle West Capital Corp.’s Arizona Public Service raised the ire of its customers and the solar industry by tacking on a monthly fee of about $5 for residents with solar systems. Adding fixed connection charges or additional fees to such customers may cause more of them to defect, said Lovins of the Rocky Mountain Institute.

“Utilities should look at Elon as a brilliant entrepreneur and innovator who is helping create the new electricity industry and betting against him hasn’t worked so well,” Lovins said. “I would look at ways to benefit from what he is bringing to the market.”

(An earlier version of this story corrected the description of Tesla’s charging stations.)

To contact the reporter on this story: Mark Chediak in San Francisco at mchediak@bloomberg.net

To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net Will Wade, Steven Frank
More News: Environment, Leaders, Energy Markets, Municipal Bonds, Transportation, Sustainability

Grid-Scale Storage: Smooth Operators

Business Insider/Economist
12/5/14

Matching output to demand is hard with wind and solar power. The answer is to store surplus juice on the grid until it is needed

ON OCTOBER 28th a battery factory opened in Concord, North Carolina. That was good for an area which has seen dark economic times, but the event made few headlines. Perhaps it should have made more, though, for this factory’s owner, Alevo, a Swiss company, is not in the business of manufacturing cells for torches, mobile phones or even laptop computers. Rather, it is making batteries that can store serious amounts of electricity–megawatt-hours of it. And it plans to sell them to power-grid operators.

To start with, the new batteries will be used to smooth the consequences of irregular demand through the day by absorbing electricity during troughs and regurgitating it during peaks. If that pans out, it will eliminate the need for gas-powered “peaker” stations which fire up quickly when needed, but are expensive to run. It would also allow non-peaker stations to operate more efficiently. Alevo reckons that if a grid as big as America’s Western interconnection (which supplies the west of the United States and Canada) were to use 18GW-worth of its batteries the grid could save $12 billion a year. Though the company has no North American contract yet, it does have an agreement to deploy its batteries in Guangdong, China.

Smoothing the operation of existing grids, however, may be only the beginning. In the longer run, optimists believe, batteries like these, or some equivalent technology, are the key to dealing with the problem not just of irregular demand, but of irregular supply. As the unit cost of solar and wind energy drops ever closer to that of power from fossil fuels, the fact that the wind does not always blow and the sun does not always shine becomes more and more irksome. It is not just the great power-gap that is night which matters. As the chart below shows, even during the day–and even in deserts–the amount of sunlight can vary from minute to minute. And the wind, of course, is equally fickle.

Cheap grid-scale storage would overcome these irregularities. Renewables could then compete on cost alone. And there are many ideas for how to make this happen. Some, such as Alevo’s, are ready to be sold. Others work in laboratories but have yet to be scaled up for use in the real world. Others still are little more than twinkles of varying plausibility in their inventors’ eyes. But if even one of them is up to the task, then renewable energy may, at last, be able to stand on its own, rather than having to be subsidised and regulated into existence.

At the moment, grid-scale storage is dominated by pumped hydro. According to the Electric Power Research Institute, an American think-tank, 140GW-worth of this is installed around the world, with a capacity of 1.4TWhr. Pumped storage requires friendly geography. You need two reservoirs separated by a good gap of altitude. But it is then just a matter of linking them with pipes and using turbines that, if turned by falling water, generate electricity, but, when fed electricity, turn the other way to pump that water whence it came. Send it uphill when power is cheap, and let it flow down when there are spikes in demand, and you have a nice little business.

Not everywhere, though, has compliant hills and valleys. And pumped storage takes a long time, and a lot of money, to build. Technologies that start small, but can be scaled up as needed, are often a better answer.

Batteries now included

The immediate future of grid-scale storage, then, probably lies with real batteries rather than topographical ones. At least, Alevo thinks so. At full capacity, the firm’s factory in Concord should be able to turn out 16.2GWhr-worth of them a year. And Alevo is not alone. Tesla is building an even bigger factory near Reno, Nevada (see “Brain scan: Tesla’s electric man”) to make batteries for its electric cars and for local and grid storage.

Several stations that use batteries to regulate the output of wind farms have already been built, or are under construction. In Sendai, Japan, Toshiba is creating one based on lithium-ion batteries. This should open in 2015. It will have a maximum power of 40MW, and will be able to run at that rate for half an hour. The Notrees Battery Storage Project, which opened in Texas in 2013, uses lead-acid batteries–sophisticated versions of the type found in petrol and diesel cars. It has a maximum power of 36MW and could run for 40 minutes at full tilt. Another Japanese project, of 34MW, in Rokkasho, uses sodium-sulphur batteries. And one in Alaska, of 27MW, uses nickel-cadmium ones.

As that list suggests, many types of grid-scale battery technology are available. Alevo uses electrodes made of lithium iron phosphate and graphite. These are connected by an inorganic sulphur-based electrolyte, a combination, the firm claims, that is particularly propitious because cycling between charged and discharged states produces only a 1°C change in the battery’s temperature. This should eliminate the risk of overheating, to which some sorts of lithium-based cells are prone.

There are types of battery that actually require high temperatures to work. In sodium-sulphur cells of the sort deployed at Rokkasho both of those elements need to be liquid, meaning the battery has to be maintained at a temperature of 300-350°C. And an approach being developed by Donald Sadoway of the Massachusetts Institute of Technology would use two sorts of liquid metal, separated by a liquid electrolyte. The clever thing about this design is that, by picking a dense metal such as a mixture of antimony and lead, a light one such as lithium, and an electrolyte whose density falls between the two, the three substances will float as separate layers in a container, rather as oil separates from vinegar in a salad dressing.

Despite their superficial differences, one thing all these batteries have in common is that the energy they contain is stored chemically within their electrodes. This has a consequence, at least for those with solid electrodes. The constant change in the electrodes’ composition as they are charged and discharged gradually wears them out. This limited lifespan is one reason using batteries for grid-scale storage is still pricey. Indeed, Alevo’s claim that its batteries can undergo more than 40,000 cycles of charging and discharging without noticeable loss of function is an important part of its sales pitch.

An alternative approach, known as a flow battery, does not suffer from this difficulty. A flow battery’s energy is stored in its electrolytes (of which there are two, separated by a membrane), rather than its electrodes (see illustration 1). Not only does that stop the electrodes wearing out, it also means that there is no upper limit, based on the sizes of those electrodes, on how much energy such a battery can store. Its capacity depends instead on the size of the tanks used to hold the electrolytes.

Flow batteries are a much less developed technology than standard batteries, but they are beginning to become commercially available. Many of those on sale at the moment (by firms such as Gildemeister of Germany and UET of Washington state) use vanadium-based electrolytes. Vanadium is a good material because its multiple ionic states mean it can be used to store energy without having to involve other reagents, and thus complicate the design.

Unfortunately, vanadium is expensive. But systems that use cheaper materials are being developed. Several firms are trying zinc and bromine in electrolytes and others iron and chromium. Ideas still in the lab include flow batteries based on cheap organic compounds called anthraquinones. If these prove robust enough to commercialise, they will be strong competitors in the grid-scale storage market. But they will not be alone. For batteries are not the only route to the destination.

Pumped up

If the engineers at Gravity Power in Goleta, California, get their way, even pumped storage is in line for a makeover. Their approach, it should be said from the outset, is one of the most twinkly of the twinkling eyes in the field. Even if it ultimately fails it shows the originality of thought that is being brought to bear on the problem.

Instead of two large reservoirs at different altitudes on a hillside, Gravity Power proposes two water-filled cylindrical shafts–one wider than the other–dug into the ground (see illustration 2). The shafts will be linked top and bottom to form a circuit, with a combined pump-turbine, similar to the ones used in conventional pumped storage, in the upper link. The wider shaft will contain a huge cylinder, made either of the rock the shaft is cut through or of concrete, to act as a piston.

When the pump-turbine is opened, the piston sinks, driving water around the circuit and through the turbine, generating power. Spin the device the other way using electricity, and the reversed water flow pushes the piston up again.

How much energy this arrangement can store depends on how deep the shafts go. And that is where it gets tricky, for some serious civil engineering will be needed if the idea is to work. Gravity Power proposes the shafts descend hundreds of metres. This will require large thicknesses of suitable rock–in practice this will probably be limestone, which is soft enough to cut into–so deployment will be limited not so much by geography as geology. And making a good seal between piston and shaft will hardly be trivial. So it will be expensive. A unit 700 metres deep, with a main shaft 26 metres across and a return shaft (or penstock) of about a tenth of that, would cost $170m. It would, though, be able to store about 200MWhr of energy, with an output of 50MW. Building one that size is years away, but the firm hopes to start work in 2015 on a demonstration plant near Penzberg, in Germany, with a depth of 140 metres, a capacity of 500 kWhr and an output of 1MW.

Nor is Gravity Power’s approach the only one to rely on underground spaces and friendly geology. Another is to fill a subterranean cavern with compressed air. For that, the cavern needs to be hermetically sealed and this means using an underground salt dome that has been hollowed out by solution mining (ie, the salt has been extracted with hot water).

Given such a cavern, compressed-air storage is a bit like classical pumped storage, except with a gas, rather than a liquid. Air is pumped into the cavern, increasing its pressure, and then let out to drive a turbine. But there is a catch: gases heat up when compressed and cool when they expand. For compressed-air storage to work, therefore, the air released from the cavern has to be heated (usually by burning natural gas), otherwise it would freeze the turbine. That makes compressed-air storage inefficient–one reason there are only two grid-scale examples of it in the world (one in Germany, the other in Alabama).

This would change if the heat of compression could be captured, stored and recycled. And that is the goal of LightSail Energy, a firm based in Berkeley, California. LightSail has developed a small, but still grid-scale, compressed-air system that sprays water into the compression chamber, to cool the air as its volume shrinks. The air is then stored in a set of tanks with a total volume of 42,000 litres, and the water, with its heat load, is put into two tanks that have, in total, about a quarter of the volume of the air tanks.

At the moment, this device can store 700kWhr of energy, but that should rise to 1.1MWhr when (as is the plan) it is pressurised to 300 atmospheres instead of the current 200. That is a fraction more than one of Alevo’s battery packs, which store 1MWhr. For comparison, the Alabama salt dome can store 2.9GWhr.

If heat is to be stored at scale some inventors would prefer to simplify the process, get rid of the compressed air, and concentrate on sequestering the heat itself. Isentropic, a company in Fareham, Britain, plans to employ the compression and expansion of a gas (in this case, argon) to create heat and cold respectively in two large containers of gravel–one of the cheapest solid heat-storage media imaginable. Once again, a pump-turbine is involved. It does the compression and expansion when electricity is abundant, and when it is scarce the gas flow, and thus the heat flow and therefore the whole process, is reversed.

Nor are these ideas the end of the list. Several firms, from giants such as ABB of Zurich, to minnows such as Berkeley Energy Sciences, a neighbour of LightSail, are pushing giant flywheels as at least part of the answer. Another suggestion–for filling in the shortest irregularities in supply, those lasting a few seconds or minutes such as are caused by the passage of a cloud in front of the sun–is to use supercapacitors, which store electricity as an actual electric charge, rather than converting it into chemical or physical potential energy of a non-electric form. At the other end of the scale as far as the size of the gap in supply is concerned, namely the nocturnal hours when solar energy cannot operate, several research groups are trying to use molten salts (usually sodium and potassium nitrates) to store heat gathered during the day and then, at night, raise steam for generators with it.

And there is one further idea around that, though it relies on new storage technology being developed, does not rely on that technology being developed specifically for grid-scale storage. This is to use the fleet of electric cars that its proposers hope will take over from ones driven by internal-combustion engines over the course of the next couple of decades.

In the imaginations of such people, the batteries of these cars (which would, when idle, be attached to the grid in order to charge them), could be employed as a giant storage network, to be plundered with the car owners’ permission at times of peak demand. It is an intriguing thought–but the overlap between those times and the times cars are most likely to be on the road might scupper it in practice. As might the answer to the question about how ubiquitous electric cars will actually become. For that will depend on the future success and affordability of batteries.

The path from startup to success is littered with corpses, and an awful lot of business models depend for their putative profit on what is, according to your point of view, either a subsidy or a factoring in of the economic externalities (in the form of climate change) imposed by fossil fuels. In particular, Germany’s Energiewende and California’s Renewable Energy Programme have, by requiring a large fraction of those jurisdictions’ electricity to be renewable, helped fuel the boom.

Your bill, sir

The world would no doubt be a better place if the externalities imposed by fossil fuels were properly accounted for in the price of electricity. But that is a hard sell, not least because of disagreements about those externalities’ true size. In the meantime, it is better if grid-scale storage can be rolled out without taxpayer support.

That is the main reason for watching the example of Alevo. It says it can make money even in unsubsidised grids, because it has been ruthless about reducing manufacturing costs and simplifying the technology as far as possible.

This is a businesslike approach. If it works, and others prove able to mimic it, then the cost of running a grid, and thus the price of electricity, will fall. That alone will be a good thing. But success will change the very nature of such a grid, enabling it to absorb more wind and solar power even if this is a consequence unintended by the grid owners. How much more is yet unknown, for fossil fuels (particularly natural gas) are getting cheaper too. But renewables will no longer be fighting the battle with one hand tied behind their back.

The world would no doubt be a better place if the externalities imposed by fossil fuels were properly accounted for in the price of electricity.

Original Article: http://feedproxy.google.com/~r/businessinsider/~3/V1UYSNWoS7I/grid-scale-storage-smooth-operators-2014-12

Solar and Wind Energy Start to Win on Price vs. Conventional Fuels NOVEMBER 23, 2014 AT 7:57 PM NYT > Business Day / By DIANE CARDWELL

For the solar and wind industries in the United States, it has been a long-held dream: to produce energy at a cost equal to conventional sources like coal and natural gas.

That day appears to be dawning.

The cost of providing electricity from wind and solar power plants has plummeted over the last five years, so much so that in some markets renewable generation is now cheaper than coal or natural gas.

Utility executives say the trend has accelerated this year, with several companies signing contracts, known as power purchase agreements, for solar or wind at prices below that of natural gas, especially in the Great Plains and Southwest, where wind and sunlight are abundant.

Those prices were made possible by generous subsidies that could soon diminish or expire, but recent analyses show that even without those subsidies, alternative energies can often compete with traditional sources.

In Texas, Austin Energy signed a deal this spring for 20 years of output from a solar farm at less than 5 cents a kilowatt-hour. In September, the Grand River Dam Authority in Oklahoma announced its approval of a new agreement to buy power from a new wind farm expected to be completed next year. Grand River estimated the deal would save its customers roughly $50 million from the project.

And, also in Oklahoma, American Electric Power ended up tripling the amount of wind power it had originally sought after seeing how low the bids came in last year.

“Wind was on sale — it was a Blue Light Special,” said Jay Godfrey, managing director of renewable energy for the company. He noted that Oklahoma, unlike many states, did not require utilities to buy power from renewable sources.

“We were doing it because it made sense for our ratepayers,” he said.

According to a study by the investment banking firm Lazard, the cost of utility-scale solar energy is as low as 5.6 cents a kilowatt-hour, and wind is as low as 1.4 cents. In comparison, natural gas comes at 6.1 cents a kilowatt-hour on the low end and coal at 6.6 cents. Without subsidies, the firm’s analysis shows, solar costs about 7.2 cents a kilowatt-hour at the low end, with wind at 3.7 cents.

“It is really quite notable, when compared to where we were just five years ago, to see the decline in the cost of these technologies,” said Jonathan Mir, a managing director at Lazard, which has been comparing the economics of power generation technologies since 2008.

Mr. Mir noted there were hidden costs that needed to be taken into account for both renewable energy and fossil fuels. Solar and wind farms, for example, produce power intermittently — when the sun is shining or the wind is blowing — and that requires utilities to have power available on call from other sources that can respond to fluctuations in demand. Alternately, conventional power sources produce pollution, like carbon emissions, which face increasing restrictions and costs.

But in a straight comparison of the costs of generating power, Mr. Mir said that the amount solar and wind developers needed to earn from each kilowatt-hour they sell from new projects was often “essentially competitive with what would otherwise be had from newly constructed conventional generation.”

Experts and executives caution that the low prices do not mean wind and solar farms can replace conventional power plants anytime soon.

“You can’t dispatch it when you want to,” said Khalil Shalabi, vice president for energy market operations and resource planning at Austin Energy, which is why the utility, like others, still sees value in combined-cycle gas plants, even though they may cost more. Nonetheless, he said, executives were surprised to see how far solar prices had fallen. “Renewables had two issues: One, they were too expensive, and they weren’t dispatchable. They’re not too expensive anymore.”

According to the Solar Energy Industries Association, the main trade group, the price of electricity sold to utilities under long-term contracts from large-scale solar projects has fallen by more than 70 percent since 2008, especially in the Southwest.

The average upfront price to install standard utility-scale projects dropped by more than a third since 2009, with higher levels of production.

The price drop extends to homeowners and small businesses as well; last year, the prices for residential and commercial projects fell by roughly 12 to 15 percent from the year before.

The wind industry largely tells the same story, with prices dropping by more than half in recent years. Emily Williams, manager of industry data and analytics at the American Wind Energy Association, a trade group, said that in 2013 utilities signed “a record number of power purchase agreements and what ended up being historically low prices.”

Especially in the interior region of the country, from North Dakota down to Texas, where wind energy is particularly robust, utilities were able to lock in long contracts at 2.1 cents a kilowatt-hour, on average, she said. That is down from prices closer to 5 cents five years ago.

“We’re finding that in certain regions with certain wind projects that these are competing or coming in below the cost of even existing generation sources,” she said.

Both industries have managed to bring down costs through a combination of new technologies and approaches to financing and operations. Still, the industries are not ready to give up on their government supports just yet.

Already, solar executives are looking to extend a 30 percent federal tax credit that is set to fall to 10 percent at the end of 2016. Wind professionals are seeking renewal of a production tax credit that Congress has allowed to lapse and then reinstated several times over the last few decades.

Senator Ron Wyden, the Oregon Democrat, who for now leads the Finance Committee, held a hearing in September over the issue, hoping to push a process to make the tax treatment of all energy forms more consistent.

“Congress has developed a familiar pattern of passing temporary extensions of those incentives, shaking hands and heading home,” he said at the hearing. “But short-term extensions cannot put renewables on the same footing as the other energy sources in America’s competitive marketplace.”

Where that effort will go now is anybody’s guess, though, with Republicans in control of both houses starting in January.

Two Big Trends Will Fuel The Renewable Energy Boom For Years

This is the big picture.

Carlos Barria/Reuters
The renewable energy revolution is happening faster than many expected.
According to recent report from Citi Research, renewables will continue their market share grabs from coal and gas forSome of this can be explained by the need for cleaner energy.

“Environmental pressures on coal consumption are rising not only in Europe and North America, but also in China and other emerging markets,” according to the Citi analyst’s note. “The most significant change has been in China, where increasing regulations and the establishment of carbon markets should limit the attractiveness of coal power. Moreover, the country is aggressively pursuing an ‘everything but coal’ development plan for the power sector, with rapid growth in capacity for alternative energy sources.”

Coal power plants are increasingly being pushed into “retirement.”

Most people have been expecting natural gas to be coal’s major substitute. However, Citi’s forecast suggests that growth in natgas demand is going to be way less than previously anticipated.

Renewables should take ever-increasing amounts of market share in an environment like this, according to the report.

In the figure above, you can see that coal’s utilized capacity (measured in GW) is projected drop from 198 GW in 2011 down to 181 GW by 2020. Natural gas slightly increases from 115 GW in 2011 to 132 GW by 2020, although that number is less than previously expected (and you can see there’s a dip from 2012 to 2014). Nuclear sees no major change in either direction, starting at 90 GW and ending at 92 GW.

On the flip side, renewables in 2011 were at 50 GW and are expected to rise to 68 GW by 2020.

two reasons.

First, renewables are rapidly becoming cost-effective, and second, environmental restrictions are becoming an increasingly high hurdle.

Renewables Are Getting Cheaper

Thanks to tech advances, the cost of renewables is finally dropping to affordable levels, which is allowing them to proliferate, according to Citi.

“Costs for solar and wind energy are falling rapidly, with learning rates of around 30% for solar and 7.4% for wind,” the report states.

Wind power has already achieved cost parity with the most expensive coal power plants in Europe (slightly above $80/MWh), and by the end of the decade it’s expected to reach cost parity with the majority of plants (around $70/MWh).

Solar is still the most expensive major electricity source at the moment (around $160/MWh), but Citi is projecting that by 2020 solar will drop to wind’s current prices (slightly above $80/MWh).

“Natural gas has already eroded coal’s cost competitiveness in the US, with decreasing costs for wind, solar and ex-US natural gas to follow,” according to Citi.

Below is the global electricity cost curve.

Citi Research
Environmental Restrictions Favor Renewables

Historically there has been a correlation between economic growth and electricity demand growth. But right now we’re seeing the opposite: during a period of economic growth, electricity demand growth has been relatively flat or declined for some regions.

Some of this can be explained by the need for cleaner energy.

“Environmental pressures on coal consumption are rising not only in Europe and North America, but also in China and other emerging markets,” according to the Citi analyst’s note. “The most significant change has been in China, where increasing regulations and the establishment of carbon markets should limit the attractiveness of coal power. Moreover, the country is aggressively pursuing an ‘everything but coal’ development plan for the power sector, with rapid growth in capacity for alternative energy sources.”

Coal power plants are increasingly being pushed into “retirement.”

Most people have been expecting natural gas to be coal’s major substitute. However, Citi’s forecast suggests that growth in natgas demand is going to be way less than previously anticipated.

Renewables should take ever-increasing amounts of market share in an environment like this, according to the report.

In the figure above, you can see that coal’s utilized capacity (measured in GW) is projected drop from 198 GW in 2011 down to 181 GW by 2020. Natural gas slightly increases from 115 GW in 2011 to 132 GW by 2020, although that number is less than previously expected (and you can see there’s a dip from 2012 to 2014). Nuclear sees no major change in either direction, starting at 90 GW and ending at 92 GW.

On the flip side, renewables in 2011 were at 50 GW and are expected to rise to 68 GW by 2020.