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U.S. Expected to Approve Expanded LNG Exports to Japan

The US policy of LNG exports to Japan is expected to see a significant change in near future as more export approvals are considered.

A report published by Baker & McKenzie has said that last year the US government approved exports from a second terminal, and decisions on eight other applications for export approval are expected later this year.

Implications for Japanese LNG buyers and investors

The report stressed that expanded U.S. LNG exports represents an opportunity not only for Japanese LNG buyers to diversify their supply sources with shale gas but also at more competitive pricing linked to Henry Hub prices rather than oil prices.  Japanese companies also could establish value chains in the U.S. by investing in projects to build export facilities and by acquiring interests in shale gas fields.

Since 1967 the Kenai LNG Plant in Alaska, which produced all eight of the LNG cargoes shipped from the U.S. to Japan in 2011, had been the only LNG plant with export approval.  This changed last year when the Sabine Pass facility in Louisiana obtained export approval.  Eight other applications for export approval are now pending.

Export approval process and outlook

Under the Natural Gas Act gas exports require permission from the federal government.  Such permission is only granted if the Department of Energy (DOE) determines that the proposed exports are consistent with the public interest.  Exports to 17 countries which have free trade agreements (FTAs) with the U.S. are deemed consistent with the public interest and the DOE must approve exports to these countries “without modification or delay”.  In contrast, approvals for exports to non-FTA countries, including Japan, are subject to a lengthy public interest finding process which allows for comments, protests, and motions to intervene from interested parties.

The applicable legislation does not require the DOE to take action on applications within a certain timeframe.  After Sabine Pass received approval for exports to non-FTA countries in May last year, the DOE suspended consideration of all applications pending the results of a study on the impact of exports on the domestic energy market.  This followed complaints from some U.S. lawmakers who were concerned that exports might increase domestic prices.  The domestic market impact study was initially scheduled to be completed by the first quarter of this year, but it is still pending and is now expected to be completed later this summer.  Accordingly, none of the pending applications are likely to be approved until the fourth quarter of this year at the earliest.

There are, however, some reasons to believe there is political support for expanding LNG exports to non-FTA countries such as Japan.  For example, on July 2, 2012, a bipartisan group of 21 members of Congress from states with shale gas deposits sent a letter to Energy Secretary Steven Chu urging the DOE to expedite the pending LNG export applications.  In February, Secretary Chu said he supports LNG exports, and Prime Minister Yoshihiko Noda also said he discussed expanding LNG exports when he met with President Barack Obama on April 30, 2012.

Actions to consider 

• Conduct preliminary due diligence on LNG projects with pending non-FTA export approval applications, as these projects are likely to be now seeking LNG buyers and equity investors.

• Monitor the DOE’s non-FTA export approval process.

• Investigate the compatibility of LNG produced from U.S. shale gas with regasification facilities and pipeline networks in Japan

Conclusion

Given the currently wide differential between the Henry Hub spot price used for trading on the New York Mercantile Exchange (NYMEX) and JCC pricing, expanded LNG exports produced from U.S. shale gas fields is a potential game changer for the gas market in Northeast Asia, and Japan in particular.  From the Japanese buyer’s perspective, it is clear that approvals for further export terminals is an important development to monitor in order to position themselves as potential buyers and equity investors.  For more information, please contact Colin Cook or Hiromitsu Kato.

Source: Baker & McKenzie via: Source

Natural Gas: Where Endless Money Went to Die

Wednesday, June 20, 2012 at 4:17PM

The fiasco that is playing out in the natural gas industry doesn’t happen often in a free market, and when it does happen, it’s usually short—and brutal for all involved: namely, prices that are way below production costs. In most industries, hedging strategies might get market participants through the period, while unhedged production, a money-losing activity, gets slashed. If it lasts long enough, it causes a shakeout where less efficient or poorly capitalized producers, and their investors, get wiped out. It’s all part of the capitalist system that weeds out weaker elements through occasional sweeps of creative destruction.

As shortages crop up on the horizon, prices return to sustainable levels, and occasionally spike to once again unsustainable levels. For the survivors, or for lucky new entrants, the next step in the cycle has begun.

Alas, thanks to the Fed’s zero-interest-rate policy and the trillions it has handed over to its cronies since late 2008, the sweeps of creative destruction have broken down. Instead, boundless sums of money have been searching for a place to go, and they’re chasing yield when there is none, and so they’re taking risks, any kind of risks, in their vain battle to come out ahead. The result is a stunning misallocation of capital to the tune of tens of billions of dollars to an economic activity—drilling for dry natural gas—that has been highly unprofitable for years. It’s where money has gone to die. What’s left is debt, and wells that will never produce enough to make their investors whole. For that whole debacle, read…. Capital Destruction in Natural Gas.

But the money has dried up. And drilling for natural gas is collapsing. Last week, there were only 562 rigs drilling for dry natural gas—the lowest number since September 1999. A dizzying downward trajectory:

 

Producers, if at all possible, are switching to drilling for oil and natural gas liquids (priced like oil), still a profitable activity. Thus, capital is now being channeled to where it can make money. Drilling for dry natural gas will continue to decline as the long delayed sweep of creative destruction is scouring the industry.

The largest producer, ExxonMobil, given its monumental size and worldwide focus on oil, will weather the fallout just fine. But the second largest producer, Chesapeake Energy, is struggling. It’s trying to dump assets to raise cash to deal with its mountain of decomposing debt. Other producers that haven’t diversified away from dry natural gas are in a similar quandary. And at current prices, it’s going to be bloody.

At $2.53 per million Btu at the Henry Hub, the price of natural gas is up 33% from the April low of $1.90 per million Btu—a number not seen in a decade. But even if it doubled, it would still be below the cost of production. And if it tripled, it might still be below the cost of production for most producers. That’s how mispriced the commodity has become.

Misallocation of capital, and the resulting overproduction, is only part of the problem. The other part of the problem is horizontal fracking itself—a drilling method that extracts gas from shale formations. With nasty economics. It’s an expensive method. And once drilled, the well suffers from steep decline rates; after a year or a year-and-a-half, only 10% of the original production might still come to the surface.

The breakeven price for natural gas under these conditions—and it differs from well to well—is still partially theoretical since horizontally fracked wells have not yet gone through their entire lifecycle. Here is a detailed discussion and pricing model. The short answer: over $8 per million Btu. Even if that number is off, at the current price of $2.53 per million Btu, the industry is still near its point of maximum pain.

There are consequences. Power generators, having switched massively from coal to natural gas, are driving up demand. And production has finally seen a bend, a small one, in the curve that had set new highs month after month. Now, it’s declining. There is a lag between dropping rig count and production. The rig count estimates how many new wells are being drilled. Even if it dropped to zero next week, production would not immediately be impacted because the current wells would continue to produce. Production would then taper off as a function of decline rates per well—and in fracked wells, that lag is expressed in months, not years.

While the US doesn’t yet have LNG terminals to liquefy and export natural gas—in the global markets, LNG fetches mouthwatering prices between $10 and $15 per million Btu—it does have a pipeline to Mexico. According to BENTEK Energy (via the EIA), pipeline exports to Mexico hit 1,867 million cubic feet per day, a record in the seven plus years that BENTEK has been tracking it (by comparison, Chesapeake Energy produces about 2,575 MMcf/day).

 

Rising demand and exports are slamming into declining production. What was a record amount of natural gas in storage is coming down rapidly. Fears that storage would reach capacity towards the end of the injection period in the fall, and that natural gas would have to be flared, thus reducing its price to zero, seem ridiculous now. But prices, if they stay in the current ballpark, will continue to demolish producers, drive them away from dry natural gas, and cause financial bloodshed.

Until shortages appear on the horizon. But then, production can’t be ramped up quickly, regardless of what the price might be. Expect a spike and more mayhem, but this time in the other direction.

And oil, which has experienced a phenomenal boom in drilling? In North America, the range of oil qualities and a raft of infrastructure nightmares are wreaking havoc with record price differentials, writes energy expert Marin Katusa in his excellent…. Oil Price Differentials: Caught between the Sands and the Pipelines.

Source

Spain: Repsol Reports Drop in 2011 Net Income

Spain: Repsol Reports Drop in 2011 Net Income| Offshore Energy Today

Spanish oil company, Repsol, posted a net income of EUR 2.193 billion in 2011, 53.3% lower than that recorded in 2010 and which included the one-time gain from the agreement between Repsol and China’s Sinopec in Brazil.

Earnings were negatively affected by external factors such as the armed conflict in Libya and the strikes and the suspension of the Petróleo Plus program in Argentina.

The Upstream unit’s (exploration and production) recurring operating income was 1.301 billion euros by the end of 2011, a decrease of 11.7% compared to the previous year. Higher international crude oil and gas prices along with lower exploration costs somewhat mitigated the effect of lower production due to external factors and the depreciation of the dollar against the euro.

Repsol’s crude realization prices increased 14.4% compared to 2010. Particularly noteworthy was the 29.6% increase in the Repsol gas realization price compared with a 9.1% decline in the Henry Hub index benchmark. Realization prices had a positive impact of 648 million euros on the upstream unit’s income. During 2011, oil and gas production was 298,800 Boepd, 13.2% less than in 2010, mainly due to reduced production of liquids in Libya, and maintenance work in Trinidad and Tobago. In October, operations in Libya resumed and gross production of almost 300,000 Boepd has already been achieved.

Especially significant was the increased reserve replacement ratio for the Upstream unit, which in 2011 rose to 162% from 131% in 2010. Investments made during the period in this area totalled 1.813 billion euros, 62% more than during 2010.  Investment in field development represented 43% of the total and was assigned mainly to the United States, Bolivia, Trinidad & Tobago, Venezuela, Peru and Brazil. Investments in exploration were 40% of total investments, and conducted primarily in the United States, Brazil and Angola. The rest of the investment went mainly to the acquisition of Eurotek in Russia.

During 2011 multiple operations were carried out in this unit that consolidated and increased a portfolio of assets and projects that will allow Repsol to meet its production growth objectives and reserves replacement ratio.

Repsol highlighted the start of development of the giant Cardon IV gas field in Venezuela, the new discovery in the Sapinhoa (previously Guará) appraisal well in Brazil which confirms the high potential of the area, as well as the  declaration of commercial viability which allows the company to book reserves. Additionally the company increased production in the Margarita-Huacaya fields in Bolivia and the Shenzi field in the United States.

Repsol in 2011 also received approval from the Algerian authorities to start development work in the Reggane gas project in Algeria.

In addition, the company drilled six successful wells: Sapinhoa North, Northeast Carioca, Gávea (rated one of the 10 largest oil discoveries in the world in 2011) and Malombe in Brazil; Buckskin 2 in the United States and A1-130 in Libya (February 2011).

During 2011, Repsol added 720 mboe in contingent resources from successful exploration, acquisitions and revisions of existing fields. During the period, Repsol acquired a total of 79,000 km² of new acreage in 13 countries including Alaska,  Ireland, Norway, Colombia and the United States.

In February 2012, Repsol announced two new discoveries; in Sierra Leone (Jupiter) and a highly promising find in Brazil (Pao de Açúcar).

Spain: Repsol Reports Drop in 2011 Net Income

USA (Sabine Pass): BG Ups Sabine Pass LNG Volumes to 5.5 MTPA

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Cheniere Energy Partners, L.P. announced today that its subsidiary, Sabine Pass Liquefaction, LLC , has entered into an amended and restated LNG sale and purchase agreement with BG Gulf Coast LNG, LLC, a subsidiary of BG Group plc, under which BG has agreed to purchase an additional 2.0 million tonnes per annum (mtpa) of LNG, bringing BG’s total annual contract quantity to 5.5 mtpa of LNG.

BG will purchase 3.5 mtpa of LNG with the commencement of train one operations and will purchase a portion of the additional 2.0 mtpa of LNG as each of trains two, three and four commence operations.

Under the SPA, the purchase terms essentially remain the same, whereby BG will pay Sabine Liquefaction a fixed sales charge for the contracted quantity and will pay a contract sales price for LNG purchases based on the applicable Henry Hub index traded on the New York Mercantile Exchange, with the exception that the fixed sales charge will increase ratably in order to account for the increased fixed sales charge on the additional volumes.

In assessing the optimal contracting strategy for the Sabine Liquefaction Project, we have decided to sell part of the additional volumes on a long-term basis to BG, our first foundation customer,” said Charif Souki, Chairman and CEO.  “There’s a trade-off in whether we sell the additional volumes on a long-term basis or in the open market.  Contracting a portion of the additional volumes adds further certainty to the long-term cash flows of the project and preserves the opportunity for additional upside.

Articles

Source

USA: Total Close to Sign Sabine Pass LNG Deal

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French oil and natural gas major Total is close to signing a firm long-term sales agreement with Cheniere Energy to lift 3.5 million tonnes per annum (mtpa) of LNG from its Sabine Pass liquefaction project, according to sources close to the deal.

The structure of the deal is understood to be virtually identical to Cheniere’s 20-year sales and purchase agreement signed with BG Group last week, the first firm offtake deal signed by the project. Under that agreement BG will pay the US developer a fixed take-or-pay fee of $2.25/MMBtu to cover the procurement, liquefaction and loading costs at the Sabine Pass plus an interruptible 115% of US Henry Hub natural gas futures fetching fee paid to Cheniere to provide free on board (FOB) cargoes.

Total is also understood to be taking the commercial export agreement one step further by assuming an ownership stake in Cheniere’s Sabine Pass Liquefaction company. Specific terms of the equity stake were undisclosed.

Bringing an equity partner into the project has been seen as crucial for Cheniere if it is to secure its financial future and reduce its $3.14bn debt, which includes $2.2bn specifically related Sabine Pass.

While credit rating agency Standard & Poors (S&P) called Cheniere’s deal with BG a “significant milestone” in its efforts to generate future cash flows, it has reaffirmed its CCC+ junk-status rating with a negative outlook.

Assuming its current liquidity does not materially improve, Cheniere will not be able to make its 2012 maturity payments,” S&P said in a report released on Monday.

The company must generate significantly more liquidity to avoid further credit deterioration or default. We believe its options include further asset sales and terminal use agreements (TUAs), incremental LNG marketing activity, equity offerings, and debt restructuring.”

Closing in on sales threshold

A firm 3.5mtpa sales commitment from Total would bring Cheniere to the 7mtpa threshold, a figure that chief executive Charif Souki told ICIS Heren last week was the target for moving forward with the first phase of the liquefaction project.

Phase One at Sabine Pass is planned for two liquefaction trains of 4.5mtpa capacity each, with Cheniere indicating that it will retain and market the remaining 2mtpa.

Cheniere and Total both declined to comment when contacted to confirm the deal.

Total is already an import capacity holder at Sabine Pass where it has 1 billion cubic feet/day – 0.2 million cubic metres/day – of regasification capacity as part of 20-year terminal utilization agreement.

The agreement with Cheniere follows Total’s declaration last week that the company has been studying the possibility of exporting US gas but provided no additional details.

Total secured a firm upstream US unconventional gas presence in December 2009 when it purchased 25% of Chesapeake Energy’s portfolio in the Barnett Shale Basin in Texas.

Source

USA: Cheniere, BG Ink LNG Sale and Purchase Deal

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Cheniere Energy Partners, L.P. announced today that its subsidiary, Sabine Pass Liquefaction, LLC, has entered into its first liquefied natural gas (LNG) sale and purchase agreement (SPA) with BG Gulf Coast LNG, LLC (BG), a subsidiary of BG Group plc, under which BG has agreed to purchase 3.5 million tonnes per annum (mtpa) of LNG.

Sabine Liquefaction is planning to develop the ability to produce 9 mtpa of LNG in the first phase of its project at the Sabine Pass Terminal owned by Cheniere Partners. On May 20, 2011, Sabine Liquefaction received authorization from the U.S. Department of Energy to export up to 16 mtpa of LNG destined to all countries with which trade is permissible.

Under the agreement, BG will pay Sabine Liquefaction a fixed sales charge for the full annual contract quantity and will also pay a contract sales price for LNG purchases based on the applicable Henry Hub index traded on the New York Mercantile Exchange. LNG will be loaded onto BG’s vessels. The SPA has a term of twenty years commencing upon the date of first commercial delivery, and an extension option of up to ten years. LNG exports are expected to commence as early as 2015. The SPA is subject to certain conditions precedent, including but not limited to Sabine Liquefaction’s receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct the liquefaction facilities.

BG is one of the largest participants in the global LNG markets and will be a strong foundation customer for our Sabine Pass liquefaction project,” said Charif Souki, Chairman and CEO. “Entering into this agreement is a significant milestone for our project and we look forward to finalizing additional commercial agreements and proceeding with the development of the first two trains.

Source

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