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Alaska’s rocks keep drawing explorers searching for oil, gas: Fuel for Thought

These are bleak times across much of the nation’s “oil patch.” Layoffs are spreading and rigs are being laid up. One state – Alaska – is defying the trend, at least for now. Industry employment in Alaska remains near-record numbers, according to state data. Producers are pressuring contractors and suppliers to slash rates, but explorers keep lining up in search of black gold.

What keeps the industry interested, and busy, is that really the rocks are great. State geologists say the North Slope has one of the largest oil-generating systems of the world. “The rocks are fundamental,” said Ken Boyd, a former state oil and gas director. “If you don’t have good rocks you don’t have anything.”

Jim Musselman, CEO of Caelus Energy, agrees with this. “We believe the North Slope is the oiliest place on earth,” Musselman said in an interview. Caelus is one independent busy on the North Slope, and this winter the company will be drilling a prospect Musselman thinks could be an equal to the Kosmos field off West Africa, which Musselman also helped develop.

Bill Armstrong, head of Denver-based Armstrong Oil and Gas, is equally bullish about the slope and his company is taking a larger piece, and will likely operate, what could be a major discovery made with Repsol, who remains a partner.

Armstrong has a long track record on the slope having led the exploration of two now-producing fields, Caelus’ Oooguruk and Nikaitchuk, now owned by Eni, as well as the discovery with Repsol.

A jobs slowdown will eventually hit the North Slope because part of what’s keeping things busy are projects started before oil prices plunged, like the big ExxonMobil-led Point Thomson gas cycling project and CD-5, ConocoPhillips’ new oil project near the Alpine field. But CD-5 is now finished and Point Thomson soon will be.

The dip may not be all that pronounced, however. Last week ConocoPhillips announced a $900 million new project in the National Petroleum Reserve–Alaska. Caelus Energy, headed by Musselman, is pressing ahead with Nuna, a $1.2 billion new oil project near that company’s Oooguruk offshore field.

There’s other new exploration, too. South of Prudhoe Bay two small independents, 88 Energy and Great Bear Petroleum, are exploring shale formations that are the source of oil now being produced in the slope’s large conventional fields.

88 Energy is currently drilling a test well and is reported to have found, so far, substantial quantities of liquids-rich gas, a good sign. Great Bear drilled an exploration well last year and plans to return for more testing.

Tax incentives help small companies take bigger risks

What’s surprising for Alaska is that two largest North Slope producers, BP and ExxonMobil, have turned their backs on new North Slope exploration, leaving only ConocoPhillips and the independents to explore. This isn’t totally fair, because the big producers are now focused on commercializing the known gas reserves in the known fields, and BP points to potential for heavy oil in the producing Prudhoe and Kuparuk fields.

Still, why the seeming contradiction in new exploration? Big oil is unenthused and yet little oil, and medium-sized oil, is bullish? The explanation, Alaska state officials say, is that the North Slope just doesn’t offer targets big enough to interest the super majors, except for the heavy oil and natural gas. However, there are plenty of medium-to-smaller prospects in outlying areas that are suitable for ConocoPhillips and quite enticing for small newcomers.

There’s one more thing, however — money. Alaska has something else – a generous state incentive system. Through a combination of tax credits (negotiated royalty reductions are possible, too) the state of Alaska can pay up to 60% to 70% of the cost of exploration wells and up to 40% of development costs in some cases if discoveries are made. This is huge for small independents, who use tax credit certificates issued by the state to raise financing.

There’s trouble brewing, however. The program’s escalating costs, over $500 million last year and headed to $700 million this year, has become unaffordable for the state, which has been hit hard by low oil prices.

Earlier this year Gov. Bill Walker slammed a $500 million ceiling on tax credit expenditures, while promising to pay $200 million in additional credit applications for credits later. — Tim Bradner

Source: http://blogs.platts.com/

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Bears win out at Coal Trading Association conference

In trading circles, the bulls are effectively those who believe the forward price will go up and the bears believe it will go down.

At the Coal Trading Association’s annual conference this week in New York City, both sides were on display, although sentiment leaned more heavily toward the latter.

Representing the bulls in a light-hearted end of conference debate was Stephen Doyle, president of BtuBaron, who argued in favor of coal’s eventual recovery as more supply comes offline and prices eventually recover.

“We are going to have a surviving coal sector that has never been leaner,” Doyle said as part of a “Bull vs. Bear” debate that wrapped up the 14th annual conference.

Doyle acknowledged the challenges facing the coal industry, including weak utility demand, crumbling export markets and the effects of the shale revolution.

“The shale ship is so big, it takes a while to reverse the effects we’re in,” he said. “In my opinion, the market is settled into these weak conditions, but when supply catches up, we’re finally going to have some chance to recover losses.”

Eventually, US forward pricing curves will rebound, railroads will recognize the need for changes in how they structure contracts and the global seaborne market will bounce back with a re-emergence of China.

Potentially, the industry will reap the benefits of an “Act of God,” such as a ban on Russian coal imports to Europe, to rebound, he said.

Bears eye technology, court, FX markets

“That would have to be something pretty dramatic,” said Seth Schwartz, principal at Energy Ventures Analysis, who presented on the side of the bears in the debate.

According to Schwartz, the US domestic coal market, which will shrink to about 750 million st this year, is not going to recover. That is because the competition, including natural gas and renewables, are getting better technologically while coal has stagnated.

In natural gas drilling, technological improvements have included horizontal drilling rigs that drill laterals three miles long in both directions. Coal technologies include highwall, longwall and dragline mining, technologies that date back decades, Schwartz said.

“If technology doesn’t improve, you go out of business,” he said. “There have been no technology improvements.”

Declining gas rig counts mean little for production totals when average production at those rigs goes up, he said.

Regulated utilities, which Schwartz said have been “hijacked by the environmental movement,” will do whatever it takes to make money for their shareholders.

“The power industry is not your friend,” he said. “They’re not trying to save their coal plants anymore. We are losing the politics.”

The US coal industry’s future could be determined by the result of a stay motion filed by the state of West Virginia and other states October 23 asking the US Court of Appeals for the District of Columbia Circuit to halt the implementation of rules stemming from the Clean Power Plan until all legal challenges have been resolved, Schwartz said.

The lack of a stay on the Mercury and Air Toxic Standards resulted in numerous coal-fired plant retirements before the Supreme Court remanded the MATS rule back to the the US Environmental Protection Agency in the fall.

“The biggest fight for the future of coal-fired generation is the stay motion for the CPP,” Schwartz said. “The power industry has to invest and plan for the future. They’re not waiting around.”

The politics of the stay are not in coal’s favor as the Court of Appeals for the District of Columbia Circuit, which is reviewing the stay, is stacked with Obama administration appointees, he said.

Another major factor hurting US coal markets is the exchange rate for the US dollar, which is much stronger than other currencies.

The first thing traders should be looking at is exchange rates, he said, noting that the 30% increase in the US dollar’s strength when compared with the Australian dollar has effectively taken Appalachian metallurgical coal out of the picture.

“The world is awash in coal,” Schwartz said. “But prices aren’t down in pesos. They’re down in US dollars.”

And the arguments from the bearish side of the market appear to be winning over the bulls, with Doyle acknowledging at the end of the session that he would “pull a reversal” by the second half of 2016 if gas production does not decline.

Source: http://blogs.platts.com/

Nigerian crude no longer the ‘talk of the town’

“It is a buyer’s market.” This phrase is omnipresent on most oil trader’s lips these days as crude oil prices continue to slide. None typifies this better than the current state of the Nigerian crude oil market. Overhang, glut, oversupply, unsold barrels, are some of the words most associated with Nigerian crude.
Rewind to almost a decade ago: Nigerian crude was every refiners’ oil of choice. Most of them wanted to refine Nigerian light sweet oil in order to produce a substantial amount of middle distillates and gasoline, the profit-making products for refineries.
Now fast forward to the present day. Nigerian crude has lost its appeal. With the growing pace of technological advancement in refineries that can take a greater variety of crude grades, Nigerian crude is no longer the talk of the town.
In the past six years Nigeria also lost its biggest customer, the US, which now buys only a small amount of Nigerian crude oil due to the dramatic rise in domestic shale production. And Nigeria has still not been able to adapt to this loss.
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A large amount of Nigerian crude exports, which have ranged between 1.9 million and 2.15 million barrels per day this year, struggle to sell every month. Refiners and crude oil buyers have a lot of different crudes to choose from, especially in this glut, which is dominated by largely light sweet crudes. This is why there is currently a lot of Nigerian crude floating on ships with a significant amount finding homes in storage tanks rather than in refineries.
Complex refiners look at price over grade
As a trader of Nigerian crude oil said recently: “About a decade ago, quality of the crude was everything, now it is all about the price.” Traders like him and others have said the only way Nigerian crude can compete or fight for market share in an oversupplied and fiercely competitive market is with price.
Nigeria’s state-owned oil firm Nigerian National Petroleum Corp., which sets the Official Selling Price (OSP) for the various Nigerian crudes each month, has been reactive rather than proactive in the current market.
Traders have said heavy sour crude producers in the Middle East, like Iraq and Saudi Arabia, have adapted faster to the current crude glut by aggressively lowering their OSPs to make them more appealing to refiners. This has paid off for them as almost all of the Iraqi and Saudi Arabian crude cargoes sell steadily every month, going straight to refiners or end users. It is high time NNPC and its crude oil marketing department pay heed to this strategy. If not, the overhang will continue to linger.
The majority of Nigerian crude oil travels to Europe, a region where oil demand is on the decline, and this also doesn’t bode well for Africa’s largest oil producer. Out of the five biggest global crude oil importers — China, US, Japan, India, and South Korea — it is only really India that buys a significant amount of Nigerian crude. Nigeria needs to attract countries or regions where crude oil demand is on the rise.
The 2015/2016 NNPC crude oil term contracts are due by the end of this year, and including some of the world’s biggest importers would go a long way in turning around its fortunes.
Nigeria needs to find innovative ways to market its crude to new buyers. Five years ago, no crude from the North Sea would flow to South Korea, but the European Union and South Korea signed a free trade agreement almost four years ago, and now Forties crude from the United Kingdom regularly flows to South Korean refineries — and sometimes even to China. Nigeria needs to be inspired by this example and find more customers.
There is another model Nigeria could follow, which would be to develop its refining industry and become a key oil products exporter. Having a cheap crude available could yield significant margins, akin to what the US has achieved.
But Nigeria’s downstream sector is in a sad state of affairs with all of its four refineries currently shutdown. The poor performance of these refineries has forced Nigeria to import almost all of its domestic fuel needs, at a very large cost to the country.
Nigeria’s oil marketers need new ideas and reforms, as it looks like this buyer’s market we find ourselves in is not going away anytime soon. — Eklavya Gupte

Source: http://blogs.platts.com/

A re-rollers’ steel market on scrap, DRI costs

Rolling semi-finished steels into bars used for construction is the healthiest steelmaking option available right now, looking at margins.

The Middle East and Eastern Mediterranean region has, like others, succumbed to steel price pressure led by Chinese imports, with low iron ore fines prices aiding competitive billet pricing for re-rolling.

Higher relative ferrous scrap and prevailing contract levels of direct reduction (DR) pellet premiums at around $40/dry mt and up is keeping DRI producers and mini mills on the edge.

DRI plants in North America and the Caribbean have already been idled in recent months, with operators blaming high DR premiums and lower prices for metallics and a range of steel products leaving DRI in the shade.

“DRI is the highest cost of steel production right now,” said a market source in Dubai.

DRI modules situated along the Persian Gulf stretching from Hadeed’s Al Jubail down through Bahrain, Qatar, the UAE and Oman have state support, more limited optionality around feedstocks due in part to technologies, steel product and quality requirements.

Low iron ore fines prices may spell trouble ahead for the Middle East, said a regional source. He put the reduction in blast furnace feedstocks at a 60% rate against a drop of 40% for DRI producers.

Cheaper imports of rebars and semi-finished steels erode markets, along with lower availability and options using ferrous scrap keeping up reliance on DR pellets.

In an iron ore market where around 25-30% of supply in DR pellets are from Samarco, and are not expected to return in the near future, demands remain for premiums to stay at over 100% of underlying fines prices.

That is a recipe for more regional stress in steel markets.

Source: http://blogs.platts.com/

Gas quotas and earthquakes: Minister Kamp’s Groningen balancing act

Dutch economic affairs minister Henk Kamp must be more than ready for the holiday season after what has been an eventful year for the man in charge of the country’s energy policy.
Public concern over earthquake risk from gas extraction at the giant Groningen field forced him into a succession of policy shifts as he sought to balance safety concerns with maintaining supplies to the country’s households.
This balancing act reaches what could be its climax in the coming days, with the minister due to announce around December 18 his final decision on the Groningen production quota for the 2015/16 gas year (Oct. 1, 2015 through Sept. 30, 2016).
The field is Europe’s largest and has been producing gas since 1963. Kamp first introduced annual Groningen output quotas in January 2014, but these were progressively tightened as public unease grew.
An interim 27 Bcm ceiling is currently in place after the Council of State, the Netherlands’ top administrative court, quashed the minister’s decision in December 2014 to introduce a 39.4 Bcm quota for the 2015 calendar year and a June amendment reducing this quota to 30 Bcm. The court ruling came in response to a raft of appeals from over 40 parties protesting at Kamp’s Groningen policy.
The court-imposed interim quota can be raised to 33 Bcm should gas year 2015/16 turn out to be cold. But these limits only apply until six weeks after Kamp makes his long-awaited 2015/16 Groningen quota decision.
The Council of State has stressed the minister is free to set his own ceiling when he makes his announcement, so, in that sense, the ball is very much back in his court.
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But the industry view is that Kamp will retain the 27 Bcm quota in 2015/16.
Any attempt to set a higher quota would leave him vulnerable to new legal challenges given the court’s insistence that 27 Bcm is appropriate for an average temperature year — which this is shaping up to be.
To aid his decision, Kamp commissioned a study to determine the highest level of Groningen output consistent with ensuring the safety of buildings in the area.
It found that the seismic risk from a 33 Bcm quota would be acceptable from 2016-2021 as long as 4,000 buildings were strengthened, which would give Kamp some cover if he decided to opt for a 31 Bcm quota.
However, the minister could decide to completely reverse the current operation of the Dutch gas system and mandate Groningen only be used once other sources of gas have been exploited in any given gas year. This option was explored in another study commissioned by the minister to inform his December decision.
Such a policy would require extensive use of the Netherlands gas quality conversion capacity to ensure sufficient quantities of high-calorific gas (such as gas from Norway or Russia or LNG) can be changed into the Groningen-type low-calorific equivalent that is consumed by Dutch households.
But such a radical change to the gas system would be difficult to implement and may have legal ramifications, since it would require TSO Gasunie to dictate daily production levels.
Because of this, it is unlikely Kamp will go with the second option for the 2015/16 gas year. However, it is possible that some variant of it could form the basis for a medium-long term solution to the Groningen conundrum.
But whatever his decision this month, Kamp is likely to disappoint some people. He will just hope he carries enough of the public with him to make for a slightly less fraught 2016.

Source: http://blogs.platts.com/

If you’re a steelmaker, it’s all about China, baby

Anglo American said recently it would scrap its dividend this year and next, hugely reduce capex and look to sell all its lossmaking assets. The move — deemed unsurprising by some and insufficient to a few — is a testimony to the primary issue facing the ferrous mining and metals market: China’s slowdown.
China was ostensibly the sole driver of the commodities boom, and its drastic downsizing is the pain point for steelmakers, iron ore and coal miners worldwide. Anyone selling to the dragon is getting burned. Badly. Even mining titan Vale has had its credit rating downgraded to one notch above junk.
Clearly this is not just in reaction to China’s cooling. Other events such as the Samarco dam collapse disaster also play a role — but a primary buyer running into trouble is a huge issue.
News of Anglo’s restructuring arrived just a smidgeon earlier than the yuan hitting a four-year low against the greenback in the first week of December, as investors fretted about the extent of capital outflows and weakening imports and exports.
China’s foreign reserves depleted by $87 billion in November, near the record high of $94 billion, with Morgan Stanley estimating around $55 billion was accounted for by outflows. This took China’s foreign reserves to around a monumental, but massively reduced, $3.4 trillion.
This suggests Beijing is spending mammoth amounts to prop up the yuan, and that investors are more than a little concerned by China’s more sluggish growth, to put it mildly.
China is the big proverbial patient zero of the ferrous metals market, so whatever infection it catches is transmitted to the rest of the world. The chart below shows how European hot-rolled coil prices have tracked FOB China levels lower.
richardson-innace-hrc-prices
This price erosion is being mirrored across the globe. And FOB China is increasingly important for the ferrous chain, as is often the case in maturing commodities markets — global benchmarks (such as dated Brent or WTI, or arguably CFR China 62% iron ore) become focal points for trade and are widely adopted in industry pricing.
Sluggish steel demand and environmental concerns mean further mill production cuts are inevitable; Beijing and the China Iron and Steel Association (CISA) have to do something to stem the us-versus- them vibe developing in the rest of the global steel market, with China’s exports already surpassing 100 million mt.
Such reductions will not be an overnight fix by any stretch, and represent something of a double-edged sword — while lower output might lift low steel prices, it will bite into raw material demand and pricing. And the cheaper yuan will likely continue to buoy China’s export competitiveness, something the rest of the world will definitely not be crazy about.
From boom to bust
So steelmakers globally are aiming to slash the tire of the wheel that’s China, the former darling of the supercycle. And the debate over its market economy status is yet another controversial area of the battleground.
When China joined the World Trade Organization in 2001, some members expressed worries about how trade remedy laws would apply.
“The continuing role of the Chinese government in the economy in general, and its control over prices of key inputs to many manufactured products in particular, meant that Members investigating possible dumping of Chinese products could not rely upon prices or costs in China as the basis for determining whether dumping had occurred,” Washington, US-based law firm Wiley Rein said in white paper released Sept. 15, 2015.
To alleviate these concerns, China agreed to provisions allowing countries to base dumping comparisons on external prices and costs. This was detailed in Section 15 of China’s Protocol of Accession to the WTO, according to Wiley Rein. However, this provision will expire on Dec. 11, 2016, fueling a debate in Europe and the US as to what implications it could have for the industry should China be treated as a bona fide market economy.
Should typical WTO protocols apply, dumping margins would have to be calculated comparing export prices with China’s domestic pricing — and herein lies the root of the issue, according to those in the European and US industries.
“Because of excess capacity and subsidies, the Chinese domestic price is artificially depressed, down to levels which go below even export prices [in the case of steel] meaning that no further dumping margin will be found,” with the dumping margin being equal to the positive difference between domestic price and export price, Axel Eggert, director general of Eurofer, told Platts.
Eggert said “potentially the whole steel sector in Europe is under threat because of the sheer size of Chinese [excess] capacity, which alone represents 50% of global steel capacity.”
“If China perceives EU anti-dumping instruments as measures that will be neutralized upon their receiving market economy status, this [anti-dumping] remedy against unfair trade practices would lose its deterrence capability,” Eggert added.
Gareth Stace, director of UK Steel, said the association’s position was that the European Commission should not grant China market economy status.
“The EU and other members of the WTO — including the United States — are currently considering whether to grant market economy status to China, with some EU officials reportedly leaning in favor of a unilateral grant of MES,” Washington-based Economic Policy Institute said. The UK, facing the near-demise of its own steelmaking industry, is reportedly in support of China’s market economy status.
In a report prepared for European businesses, the Economic Policy Institute said the unilateral granting of market economy status to China would put around 1.7 million-3.5 million European jobs at risk by curbing the ability to impose tariffs on dumped products — as many as 350,000 jobs could be eliminated in Europe’s steel sector alone, out of 779,300-1.5 million in the wider manufacturing sector, it said.
“I cannot assess the likelihood of China gaining market economy status, that’s not for me to say,” Dr Peter Morici, an economist and professor at the R.H.Smith School of Business, University of Maryland, told Platts. However, he said the granting of MES would “make life more difficult for others in the steel industry.”
Think!Desk China Research & Consulting said, “Chinese government bodies at all levels are exerting substantial direct and indirect influence on the resource allocation in the Chinese economy as well as concrete decision making processes in Chinese enterprises.” It suggested the Chinese economy meets only one out of five for MES under WTO guidelines.
“The dumping route doesn’t work and the countervailing duty approach is tough because of hidden subsidies — things like cheap bank loans, or steel mills there getting resources that are subsidized, such as a lot of energy and petroleum-based products. These things are extremely difficult to track,” Morici added.
“Given the circumstances, I think our government needs to fight the fight. Steel [and other producers] have a valid case and valid concerns, and I believe they are correct in their analysis of the situation,” Morici said, adding, “China could end up dumping its unemployment on us.”
Think!Desk said 33 anti-dumping investigations were opened against China in the first half of 2014, and 75 in 2013.
“The use of true market determined pricing for determining whether there is dumping from non-market economies is the only way to calculate the true margin of dumping and to prevent the distortions in the Chinese system from contaminating market based price setting,” it added.

Source: http://blogs.platts.com/

US natural gas is high, low, and looking to 2016

If I had to sum up the US natural gas industry of 2015 in four words, they would be: high production, low prices. This year has indeed been a year that some people — such as consumers — will want to remember, while others — namely, producers — will want to forget.
It was one of those years when prices continued to drop, and market observers seemed to be holding their breath, waiting to see when prices would rebound. With just a few more weeks left in the year, it seems like we will still be holding our breaths at least into 2016.
Looking at natural gas supply, demand, and prices at hubs throughout the US on a daily basis all year, I wanted to share some of the most eye-opening year-over-year figures that I have come across while covering the market. Unless noted otherwise, in this piece I will be comparing 2015 averages year-to- date (with December 10 being our date) to the same time period in 2014.
What I hope to convey is just how challenging of a price environment 2015 has been for producers and just how resilient producers have been amid this downright pathetic price environment.
Prices
As of December 10, the NYMEX prompt-month contract in 2015 has averaged $2.66/MMBtu, 38.3% lower than the same time period in 2014, when the prompt-month’s contract average price was $4.31/MMBtu.
Cash prices at Henry Hub have been similar to the NYMEX contract. Year-to-date Henry Hub prices have averaged $2.658/MMBtu, a 39.7% decline compared to the same time period in 2014, when Henry Hub averaged $4.40/MMBtu.
pedersen-henry-hub
Therefore, as a producer, two popular options for selling your gas this year has yielded returns that are nearly 40% lower than a year ago.
For producers working out of the prolific Marcellus and Utica formations, which is now the country’s largest producing region, cash prices at one the most liquid hub, Dominion, South Point, have been miserable. Year-to-date Dominion South prices have averaged $1.49/MMBtu this year, a 55% decline from a year ago, when the average price fetched at Dominion South was $3.33/MMBtu. I hate to beat a dead horse, but it is difficult to overstate how sobering and challenging it is for producers to work with such low prices.
Production
And yet, 2015 has been a stellar year for natural gas production. No matter how you look at or break down the numbers, the word “impressive” continues to be at the tip of my tongue.
US natural gas production has averaged 71.9 Bcf/d in 2015, a 3.2 Bcf/d increase from a year ago. It is easy to forget the magnitude of just how much 71.9 Bcf/d of gas really is. To put this figure in perspective, Russia, the second largest producer with the world’s reserves, produced an average of 57 Bcf/d in 2014. The country with the world’s largest natural gas reserves is Iran, produced about 16.5 Bcf/d in 2014.
Put another way: Just the increase in US natural gas production over the past 6 years is equal to Iran’s total production.
Even the increase of gas production from a year ago of 3.2 Bcf/d is very impressive. Mexico as a whole has managed to produce just over 4 Bcf/d in 2015. Therefore, our year-over-year increase in natural gas production is over 75% of Mexico’s total production.
How is the US producing such record levels of natural gas? If you look at the Baker Hughes rig count report, rig numbers no longer indicate levels of production. At the end of November this year, the natural gas rig count stood at 187 rigs, the lowest number of gas rigs on record, which goes back to 1987.
When looking at rig counts, one should consider just how astonishingly effective rigs have become. In July, EQT, a large player in the Utica, set an on-shore shale world record when their rig drilled a well that produced an initial production rate of 72.9 MMcf/d.
Numbers like these are why shale gas production has grown to be such a large part of US supply. Energy Information Administration data shows US shale gas production was 5% of total US natural gas production in 2004, 10% in 2007, and is now 56% in 2015. Considering how shale gas has been the primary driver in overall supply, shale wells will continue to be drilled.
Demand
Total US demand is only up 1.7 Bdf/d from a year ago, averaging 72.8 Bcf/d in 2015. If it was not for residential/commercial demand, which comes in at 24.5 Bcf/d, down 1.8 Bcf/d from a year ago to (weather driven), total US demand growth could have been impressive because US power burn is up 3.8 Bcf/d to 26.2 Bcf/d from a year ago. Power burn has grown for a number of reasons, such as fuel switching, coal retirements, and a higher level of nuclear maintenance outages from a year ago.
South of the border, Mexican demand for US gas has been strong, growing 700 MMc/d year to date to 2.7 Bcf/d in 2015. December exports to Mexico have averaged 3.2 Bcf/d so far.
Conclusion
While natural gas producers have been hammered in 2015, it is clear that the industry is more efficient, quick-learning, and nimble compared to a year ago. You absolutely need to have these and many other gritty traits to survive this low-cost environment.
I invite all readers to share their thoughts on the gas market in 2015 and pitch what you foresee shaping out in 2016, and I hope everyone can enjoy some happy holidays, regardless of what the markets may bring.

Source: http://blogs.platts.com/

Everything you need to know about the US crude export vote (almost)

Congress is scheduled to vote Friday on a massive government spending package with a provision to lift all limits on crude oil exports, a potentially landmark policy change which would give US producers unfettered access to the world market for the first time in four decades.

While it remains unclear if the House and Senate will pass the bill, known as the omnibus, the White House has indicated that President Barack Obama will sign it into law if they do.

With so much hype over crude exports, which have been at the center of an intense two-year lobbying campaign, and the ever-changing nature of world oil markets, it’s a challenge, if not an impossibility, to forecast the effects of the possible policy change.

Still, here’s (almost) everything you need to know ahead of what may be a meaningful day on Capitol Hill:

Why would Democrats vote for crude exports now?

After sinking attempts this year to get two crude export bills to the president’s desk and months spent depicting an export policy change as a giveaway to Big Oil, congressional Democrats may have received an offer they couldn’t refuse from Republican leaders this week. In a series of closed door meetings and secretive negotiations, Republicans agreed to include a series of environmental-friendly concessions in the omnibus, chiefly five-year extensions of wind and solar tax credits. (For more about possible policy implications of bill, listen to this week’s special breaking news episode of Capitol Crude: The US Oil Policy Podcast.)

When will US crude hit the world market and how much is coming?

Theoretically, US crude exports could begin shortly after Obama signs the bill into law. Economically, that probably doesn’t make sense. A narrow Brent-WTI spread, which has averaged under $1.50/b so far this month, its lowest relational value in more than two years, makes most US crude exports uneconomic. The US Energy Information Administration maintains that if crude export limits were dropped, the US would likely export about the same amount of crude over the next 10 years than if those limits remain in place.

What about those East Coast refiners?

Since the debate over exports ramped up about two years ago, East Coast refiners were widely seen as having the most to lose from an export change. Bakken crude now shipped by rail to the East Coast, for example, may soon be more cheaply be sent by pipe to the US Gulf Coast and exported.

At the same time, shipments of Gulf Coast crude to the East Coast by vessel will still need to be shipped on Jones Act-compliant ships, which may be more costly than foreign-flagged vessels.

To address refiners concerns, Republicans included a provision in the bill which will expand a manufacturers tax deduction to cover 75% of an independent refiners’ crude shipping costs through 2021. The US Congressional Budget Office estimates that this new tax break could result in about $1.87 billion in lost federal revenue over seven years. Shipping by rail would be about $3/b to $3.50/b with the tax break, while shipping by pipe to the Gulf Coast would be about $8.50/b to $9/b, according to a Bentek analysis.

Could export limits go back into place?

Yes. The bill includes language allowing the president to require licensing for crude export during national emergencies, for sanctions purposes and during times of supply shortages and high domestic prices. It should be noted, the president retains executive powers to reimpose export limits as well.

Source: http://blogs.platts.com/

The cyclical nature of spreads and effects on PDH propylene

Propane prices are cyclical, peaking during the winter and bottoming out during the summer, and propane/propylene spreads hit their lowest during the winter and their highest during the summer. After all, feedstock prices are the biggest component of production costs in this industry.
While last winter was an anomaly, due to the drastic drop in global oil prices impacting many commodities, propane prices dropped alongside other prices. This year we are seeing the return to normalcy regarding propane pricing, but at a time when Asia is seeing low propylene prices, margins have deteriorated, and PDH units are feeling the impact the most.
gonzalez-asian-propane
The South Asia propane/propylene spread has surged as a result of the unplanned shutdown at Shell’s steam cracker in Singapore. Shell Singapore issued a force majeure on propylene supply from its 960,000 mt/year steam cracker at Pulao Bukom during the first week of December. As a result of supply tightness in the region, the southeast Asia propylene price increased $25 to $650/mt, which caused the propane/propylene spread to increase to $225/mt.
After hitting a low during the first week of October, propylene prices have continued to rise, but stayed stagnant during the first week of November, when propane prices experienced a sharp rise, causing spreads to hit their lowest point in years at $30/mt.
gonzalez-asian-propylene
PDH process
Of all propylene producers aside from olefin conversion units (OCU), low propane/propylene spreads have the biggest impact on propane dehydrogenation (PDH) units.
As a result of more shale-based ethane being used as a feedstock in US steam crackers, the production of propylene has decreased from approximately 6.2 million mt to below 4 million mt in 2014, a 36% change. Ethane yields very little propylene — about 3% — compared to heavier feedstocks that yield between 15%-23%.
In China, there was much demand for downstream propylene derivatives such as polypropylene. Keen interest increase propylene production in the US and Asia means there were many PDH projects built over the last couple of years.
The PDH process removes two hydrogen atoms from propane and converts it into propylene. Propane is mixed with a hydrogen-rich recycled gas which is then fed into a heater in high temperatures (1000° F), then transferred into the rector in the presence of a metal catalyst (platinum) to be converted into propylene. The catalyst is continuously withdrawn from the reactor, regenerated, and fed back into the reactor bed.
The PDH process is straightforward: propane in and propylene out. As the process is simple, so are the economics, and PDH production is only viable in a region with low propane prices and high propylene prices.
Asia PDH capacity
gonzalez-pdh-capacityGlobally, propylene capacity through PDH in 2015 is expected be 13.8 million mt/year. The 660,000 mt/year Flint Hills Houston PDH plant was the only unit running in North America prior to November of this year. In late November, Dow completed its 750,000 mt/year PDH plant in Freeport. During the fourth quarter 2016, Enterprise is expected to startup their 750,000 mt/year plant in Mont Belvieu. By 2018, we expect Formosa’s 750,000 mt/year plant to come online at Point Comfort. Capacity in the US is expected to increase to 2.9 million mt.
Asia accounts for 72% of the world’s global capacity with 9.9 million mt/year. China produces 90% of Asia’s PDH propylene capacity or 9 million mt/year in 2015, and is expected to increase PDH propylene capacity to 20.6 million mt/year by 2020.
Propylene outlook
According to Platts editors, tight propylene supplies have been able to offset the drop in crude prices; however, propylene margins remain negative, and propylene supply may remain flat through the rest of the year. While there will be supply coming back online from residue fluid catalytic crackers (RFCC) unit restarts, there will also be removed supply as a result of a cracker outage and shut PDH plant.
JX Nippon Oil and Energy will be restarting two of its RFCC units soon: a 60,000 mt/year RFCC in Oita that was shut on Nov. 24 and a 100,000 mt/year RFCC in Sendai that was shut around Nov. 9.
In Taiwan, CPC is expected to restart its 400,000-450,000 mt/year RFCC at its Talin refinery by mid-December, but plans to shut its 193,000 mt/year No. 4 steam cracker in Linyuan on Dec. 12 for 50 days of annual maintenance. Also, Platts reported that Zhejiang Satellite plans to shut its 450,000 mt/year PDH plant in Zhejiang, China during mid-December.
Therefore, we don’t anticipate any changes to the Asia propylene supply/demand picture or its impact on the market, unless there is a delay in RFCC restarts or unexpected cracker outages. The latter can occur at any time considering the number of old facilities operating in the region.

Source: http://blogs.platts.com/

US nuclear power trade group head to retire in 2016

A new leader will head the US nuclear power industry’s powerful trade group when Marvin Fertel, president and CEO of the Nuclear Energy Institute since 2008, retires at the end of 2016.
The nuclear industry, facing escalating economic challenges and rising operating costs, could tap an executive with Exelon, the largest merchant nuclear plant operator, to succeed him, Fertel said. He first revealed his retirement plans in an exclusive interview with Platts December 16.
Fertel, 69, said NEI’s board of directors has been notified of his decision and a search firm will provide a list of candidates for his replacement to the group’s executive committee.
Maria Korsnick, NEI’s chief operating officer since mid-2014, “will be certainly one of the prime candidates in that search,” Fertel said.
“I’m getting tremendous benefit from having her here working with me,” he said.
“It’s a great asset to this organization having Maria work with us now, and it will be a tremendous asset if she gets the job, in that she’ll have so much experience with what NEI does, as well as all the great background that she has,” Fertel said. “We look at it as a really good thing.”
Fertel noted, however, that he will not make the decision on his successor.
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Prior to joining NEI, Korsnick was senior vice president of Exelon’s Northeast operations and acting chief executive officer and chief nuclear officer of Constellation Energy Nuclear Group. She is also executive director of the US nuclear power industry’s Fukushima Steering Committee, which is responsible for coordinating with the NRC the industry’s activities in response to lessons learned from the Fukushima I accident in Japan in 2011. Korsnick joined NEI in 2014.
Before Fertel joined NEI’s predecessor organization, the US Council for Energy Awareness, in 1990, he held positions at Ebasco, Management Analysis Company and Tenera.
He became vice president of nuclear economics and fuel supply at NEI when the organization was formed in 1994, and he was named senior vice president and chief nuclear officer in 2003. Fertel became acting president and CEO in 2008 before being elected permanently to the position by NEI’s board in 2009.
During Fertel’s tenure, among other efforts, NEI has supported the licensing and construction of five new nuclear power units in the US. After the Barack Obama administration canceled in 2010 DOE’s project to build a geological repository for spent fuel and nuclear waste at Yucca Mountain, Nevada, NEI successfully sued the department in federal court to halt the collection of a fee imposed on nuclear-generated electricity to build the Nuclear Waste Fund that would have been used to pay for that project.
NEI has also advocated for low-carbon portfolio standards and other policies to assist merchant nuclear power plants facing economic challenges from low natural gas and power prices, and coordinated enhancements of nuclear power plants’ ability to mitigate severe accidents similar to that at Fukushima under its Flex initiative.
Fertel took the helm of NEI at the height of talk about a “nuclear renaissance” in the US, spurred by expectations of strong growth in demand as well as government support for new plants. Fertel saw those hopes sharply diminished as an economic contraction followed by a historic drop in the price of natural gas sent power prices plunging and reduced the need for new generation. In the past three years, Fertel and NEI have faced announcements that seven nuclear units in the US would shut. Just this year, Entergy has said it will close its Pilgrim and FitzPatrick units in Massachusetts and New York, respectively, because of financial challenges faced by merchant nuclear plants. Those units rely on wholesale market rates for electricity, which have tumbled, to make profits.
The support for Korsnick, an executive at the largest US merchant nuclear unit operator, reflects the importance that the problems of the merchant fleet represents for the industry.
She has recently been at the forefront of industry efforts to spread awareness of the issues facing the industry, and earlier this month she outlined an industry-wide initiative to improve the economics of nuclear plants by reducing costs and increasing revenue.
Fertel’s departure from NEI had been rumored for years.

Source: http://blogs.platts.com/