Lithuanian LNG – The Latest European Move Away from Gazprom and Russia

Posted by Mark Young

Oct 29, 2014 8:41:00 AM

Lithuania has historically imported its gas from Russia and Gazprom. This is about to change however, with the country’s first LNG Cargo being received at its brand new floating terminal. Analysis by Evaluate Energy shows that, by itself, the terminal represents just a small amount of gas that Gazprom needs to find a new market for, but Lithuania’s new found potential independence does form part of a major overall change in the European gas market. This change in Europe means Gazprom will have to adapt in order to remain a major player and to make sure Russia’s new Asian-focused enterprises represent a true success and sustained growth for the country, rather than just a way of filling a hole in the country’s finances that Europe leaves behind .

Lithuania’s First LNG Cargo Arrives

Lithuania’s four year project to introduce LNG imports to the country is complete. The country and the companies involved have been working hard to make this endeavour a reality and Monday 27th October 2014 saw the Baltic nation receive its first ever LNG cargo, around 100,000 cubic metres, or approximately 3.5 million cubic feet (mcf), from Statoil’s Snøhvit terminal in Norway, according to media reports.  

Lithuania’s new terminal is one of the world’s first import facilities to be located offshore on a floating vessel. The vessel, which is pointedly named Independence, was built by Höegh LNG and has an annual import and regasification capacity of 2.2 million tonnes per year (mtpa), or approximately 107 billion cubic feet (bcf).

This figure is very significant for Lithuania and could well prove significant for Gazprom. Russian supplies of gas to the Baltic state only amounted to 96 bcf in 2013 according to Gazprom’s annual report of the same year. This means that should Lithuania be able to source the entire capacity of its new import facility elsewhere each year, Gazprom would not be needed as a gas supplier any longer. This is very powerful leverage for the Baltic country; the supply contract between Lithuania and Gazprom is up for renewal next year according to media reports. Lithuania will not necessarily pull away from Gazprom completely of course; if the Russian giant’s notoriously expensive gas prices are lowered, to the point where Russian imports remain viable, due to Lithuania’s new found leverage, then why change? But the leverage is undoubtedly there. Norway’s Statoil will supply the Lithuanian facility from Snøhvit with 2.3 billion cubic metres (bcm) of gas per year, or 81 bcf, meaning around 76% of the Lithuanian facility’s capacity is taken up and 84% of Russian imports in 2013 have effectively been replaced already.

Death by a Thousand Cuts? – Europe Moving Away from Russian Supply

Gazprom_Europe_Gas_Supply_2013

Source: Gazprom Annual Report 2013 (Other Europe represents a combination of gas supplied to all European countries that were each supplied with less than 5 bcm of gas by Gazprom in 2013, see note 3)

In reality, 96 bcf on its own is a very small figure as far as Gazprom in concerned – the company sold well over 8000 bcf to European and Central Asian countries in 2013. The potential complete loss of business in Lithuania will not, as a singular event, impact Gazprom’s financial position or its overall standing in Europe by too great a margin. But this new 96 bcf terminal is part of a desired general transition away from Russian supply by a large portion of Europe. Each move seems insignificant on its own, but together they could in fact end up having a substantial impact on Gazprom.

Starting locally, Lithuania’s terminal may provide gas in excess of what is actually required; after all, the 107 bcf capacity is over 10 bcf per year higher than Russian imports in 2013. Lithuania’s president Dalia Grybauskaite has been quoted by Argus as saying the terminal could meet 90% of the combined gas needs of Lithuania and its Baltic neighbours, Estonia and Latvia, which also have import contracts with Russia. Estonia and Latvia imported 25 and 39 bcf from Gazprom in 2013, respectively. If excess gas is marketed to these countries by Lithuania, it is another loss for Gazprom. Again, as the above chart shows, with all three countries 2013 imports combined, this amounts to another small total for Gazprom, but it is a potential loss of business nonetheless.

Poland is another country in the area with LNG plans on the verge of coming to fruition. Of course, Poland’s desire to break from Gazprom’s expensive gas prices has been well publicised over the past 5 years as its shale gas exploration plans have developed. As these plans began to falter however, LNG became another option. 2015 will see the first Polish LNG imports at the Świnoujście import facility, which will have an initial capacity of around 3.6 mtpa and plans for expansion are already underway. The initial import capacity represents around 39% of Russia’s sales to Poland in 2013. Expansion plans will further eat into this total and Poland still hopes that the country’s shale gas potential can still be realised before too long, despite the recent setbacks. All of these things will give the country its own leverage in price negotiations.

The Netherlands (part of “Other Europe” in the above chart) is one example of a country where evidence suggests that LNG has been used to move away from Russian gas. The Gate LNG terminal in Rotterdam came onstream during 2011 with annual regasification capacity of around 430 bcf; 2012 saw an approximate 37% reduction in Gazprom gas sales to the Netherlands, year-on-year.

All of these LNG imports still represent small numbers and it is a fact that Italy, France, Turkey and the UK all have LNG import facilities but still import a substantial portion of Gazprom’s total gas sales between them. So whilst LNG in Europe isn’t a major problem on its own to Gazprom or Russia, it is one alternative option and now undoubtedly a source of leverage for more European countries than before.

Other alternative options will present themselves to European gas importers in the coming years. The potential influx of gas from the giant fields in Azerbaijan to mainland Europe will provide at least the south eastern European countries on the above chart and a significant portion of the “Other Europe” contingent with a new option for gas imports. The potential arrival of LNG from North America could also play a very significant role in replacing Gazprom as a supplier or at the very least creating negotiation leverage as Gazprom’s long term contracts with the LNG-importing countries in the chart come up for renewal. The South Stream pipeline project, which is a highly controversial topic in most of mainland Europe, would bring more Russian gas into Europe if it is ever approved, but this is still highly uncertain; the conflict in the Ukraine caused the EU to adopt a resolution that opposed the South Stream pipeline and recommend the search for alternatives. If Gazprom wants to remain a major player it seems as though it will have no choice but to adapt to a new pricing structure before too long. The pressure from all these sources, as well as increased global sanctions against Russia in recent times, will create a hole in Gazprom’s and indeed Russia’s finances; retaining as much existing business as possible will be key in making sure that the hole isn’t too big.

Alternative Plans – Russia Switches Focus to Asia after Decades in Europe

After decades of focusing on supplying gas to domestic, European and central Asian markets, Gazprom and Russia are now moving into Asia with some very lucrative opportunities on the table. Just how lucrative these actually end up being and how much growth for Gazprom and Russia they create is, however, very much dependent on how much of a market the company can retain in Europe.

In June 2014, Russia signed a huge gas supply deal with neighbouring China. The deal was for around US$400 billion and 38 bcm (approximately 1340 bcf) of gas annually, ranking as the biggest gas supply deal in history. The gas will be supplied from Siberian gas fields through a new pipeline for 30 years starting in 2018. This supply of 38 bcm should more than make up for the potential loss in business as more of Europe finds alternative sources of energy and, of course, this deal would probably have been signed had Europe been moving away from Gazprom or not. However, the level of potential success for Russia in signing this deal is now mitigated; a large portion of anything made in the Chinese deal could simply just replace lost income from Europe. This would presumably not be ideal; Russia will want the deal to create growth.

LNG is also becoming an option for Russia to continue exporting high levels of gas and the country’s proximity to the premium Asian market makes the country very attractive as a supplier – transportation costs will be lower than from other burgeoning markets such as Australia, Canada and the US. Gazprom is building a 5 mtpa terminal in Vladivostok (due onstream in 2018) and already exports 9.6 mtpa (full capacity) from the Sakhalin project in the far east of the country. Total Russian capacity by the end of 2018 is due to hit around 50 mtpa if all terminals are completed on time, which is a very striking figure considering there was not a single operational terminal until 2009. Again, as Asia is the prime market for LNG, much of this will be headed in that direction and this could prove to be an extremely profitable venture for Russia.

Conclusion

Overall, the singular event of Lithuania’s first LNG cargo may seem an insignificant blot on Gazprom’s, and Russia’s, landscape, but in reality it is another important part of the quickly changing European gas market. Obviously, the move to Asia mitigates the potential loss of business, but to make this venture a true success, it surely cannot afford to lose all business in Europe, as it will be simply filling a hole in its finances with an alternative buyer rather than beginning any substantial growth.

Notes

1) All Gazprom historical supply figures were sourced from Gazprom’s Annual Report 2013.

2) All LNG terminal information was sourced from the Evaluate Energy LNG Database, which holds information on all operational, planned and possible import and export terminals worldwide, including details on annual capacity, onstream dates, news, ownership information and project costs.

3) “Other Europe” is made up of Gazprom supply to the following countries: Bulgaria, Bosnia & Herzegovina, Croatia, Denmark, Finland, Georgia, Greece, Ireland, Moldova, the Netherlands, Romania, Serbia, Slovenia and Switzerland.

Evaluate Energy provides efficient data solutions for oil and gas company analysis. As well as the comprehensive LNG database, Evaluate Energy offers 25+ years of financial and operating data for the world’s biggest and most important oil & gas companies worldwide, an M&A database, which has every E&P deal back to 2008, and a global E&P assets database, providing details on all exploration blocks, discoveries and producing fields outside of North America. Download our Brochure here.

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JuneWarren-Nickle's Acquires Major Stake in Evaluate Energy

Posted by Mark Young

Oct 8, 2014 8:04:04 AM

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Evaluate Energy is pleased to announce that it has now joined forces with Canadian company JuneWarren-Nickle's Energy Group (JWN), a division of TSX-listed Glacier Media, and Chris Innis, a global extractive industries information executive, to expand the range of energy information intelligence and tools it offers to its growing client base. 

JWN, based in Calgary and Edmonton, has acquired a major interest in Evaluate Energy, which is based in London, UK, with offices in Calgary. Evaluate Energy (www.evaluateenergy.com) will continue to be operated independently, but its team will work closely with the JWN team to offer a broader range of complementary energy intelligence services, including consulting and customized reporting.

Richard Krijgsman, Evaluate Energy's founder, said of the partnership:

"All of us at Canoils and Evaluate Energy look forward to working with JWN. Together, the two groups will be superbly placed to develop valuable, intelligence-based products and services for the energy industry in Canada and internationally. Meanwhile we will continue to provide matchless levels of data quality and service. I am confident that clients will see clear benefits as a result of today's announcement."

Evaluate Energy offers two comprehensive databases: Evaluate Energy itself, which offers deeply detailed insights into major international oil and gas companies, and Canoils (www.canoils.com), which covers hundreds of companies in Canada at a level of granularity unmatched by any other data provider, noted Bill Whitelaw, JWN's CEO.

"We know this is an industry in which information and the insights it offers matter. What we're now able to provide our clients is a deeper, richer, information experience that aligns with the way they make important business decisions," he said.

JWN's flagship – The Daily Oil Bulletin – already offers a diverse mix of news, analysis and commentary in addition to a range of daily data reports ranging from crown land postings and sales to well activity and commodity pricing. In addition to the Bulletin's data reports, JWN also offers a broad spectrum of data sets and tools which offer market and competitive insights – including an ever-strengthening platform for the oilsands industry.

The two groups will work together to strengthen the breadth and depth of the services they offer, said Whitelaw. 

"Whether people are seeking macro-level perspectives on global activity or very specific insights into company benchmarking, we're going to be able to meet their needs with customised solutions. Our joint objective is to move ever closer to our customers' decision-making processes – and help them make the right decisions, at the right time, with the right information."

For more information on the new partnership between Evaluate Energy and JWN, please call:

Bill Whitelaw

1.403.462.5108

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Oil & Gas M&A in Upstream Sector Falls to $34.5 Billion in Q3 2014

Posted by Mark Young

Oct 2, 2014 7:38:00 AM

Q3 2014 was a quieter period for global oil and gas M&A activity compared to the previous quarter, but 2014 is still on track to have a greater total M&A spend than 2013.

The total value of E&P deals worldwide in the quarter amounted to $34.5 billion, an approximate 30% drop on the total value of deals announced in Q2. North American activity grew for the 5th consecutive quarter but, curiously, deals outside of North America almost dried up completely; deals in North America made up almost 86% of the total deal value worldwide.

M_A_Deals_Q3_2014

The rise in deals in North America could be attributable to various factors. Unconventional oil resource plays are still the hottest properties on the market, with the Permian basin seeming to the current centre of highest demand. There are also many cases of companies with a diverse variety of assets trying to streamline their property holdings to give a more specific area of focus and as a result many North American assets have been made available for purchase. This stands in stark contrast to a few years ago where companies looked to hoard as much shale and unconventional acreage as possible across every play they could find. With the increasing gas prices and the approaching reality of North American gas exports, gas assets are also becoming more and more marketable. As for deal value drying up outside of North America, it is very hard to pinpoint any specific factors that would drive down activity. The number of deals announced outside of North America has been reasonably consistent over the last few quarters, so this points to the lack of “big” deals being the main contributor of the low deal value. In Q3 2014, there were only 2 deals announced outside of North America with a value of more than US$500 million, one of those happening on the very last day. In Q1 and Q2 2014, there were 8 and 12 such deals respectively.

US Permian Basin – High Demand in Q3 2014

Whilst Q3 2014 seems to have been a quiet period for global E&P M&A activity, the US Permian basin has seen a hectic few months in contrast. Acquisitions in the Permian basin made up nearly half of the total E&P deal value in the US and just under a third of total E&P deal value worldwide at around US$11.2 billion. M&A activity in the Permian Basin has been on the rise since Q1 2014.

M_A_Deals_Permian

Encana Speeds Up Move to Oil Production with Biggest Deal of the Quarter

In late September, Encana, Canada’s biggest gas producer, signed the largest deal of the quarter in agreeing to acquire Texas-based Athlon Energy Inc. for around US$5.93 billion in cash. Once the assumed debt of US$1.15 billion as well as Athlon’s cash position of around US$243 million is taken into consideration, the deal represents a total outlay by Encana of US$6.84 billion.

The deal marks Encana’s entry into the Permian basin, which seems to be the most sought after resource play in North America right now. It is typically oil rich from shale and other tight, unconventional formations. Encana’s acquisition of Athlon is a huge step for the company in quickly realising its goal to become a more oil weighted company. Of all the companies listed on the TSX, Encana is the biggest gas producer but only ranks as the 11th biggest oil producer. Encana’s board has been seeking to rectify that in recent times, solely focusing efforts on its North American unconventional resource plays. The multi-billion dollar spin-off of PrairieSky Royalty Ltd., which closed in September, was part of this strategy and helped leave the Canadian company with ownership positions in the following shale plays:

Encana_Shale_Holdings_Sept_2014

Encana’s positions in the plays listed above gives them a large amount of current natural gas production, but any oil is mainly prospective, future production. The position in the Permian basin (roughly 140,000 acres) will add to this, but does give Encana some immediate oil production (the 30,000 boe/d acquired was made up of 80% oil, 20% natural gas) to bolster its figures. The future potential of the asset and Encana’s plans to quickly expand the oil portion of its portfolio will explain the relatively high prices paid per boe/d of production and per boe of 1P reserves ($223k and $38.69 respectively).

All Permian Basin Deals in Q3 2014

Permian_deals_Q3_2014

Whiting to Become the Largest Bakken Producer as Baytex Moves South

Whiting Petroleum announced the second biggest deal of Q3 2014 with the US$6 billion acquisition of Kodiak Oil & Gas. The acquisition adds approximately 34,000 boe/d to Whiting’s Bakken portfolio, according to Q1 2014 figures from Kodiak. Its new combined acreage position of 855,000 net acres is still not as large as Continental Resources, which holds over 1.2 million acres in the play, but this additional production combines with Whiting’s own reported Q1 production to give 107,000 boe/d from the first quarter’s operations, which is higher than Continental’s 97,500 boe/d in the same period. The deal is expected to close by the end of the year. The Bakken has seen a lot of deals like this in recent years, with companies agreeing deals that consolidate already significant acreage positions in the play, suggesting that the Bakken is an area where only those with the largest scale operations can succeed. Of course, the flip-side to this is that smaller operators find things difficult and Baytex Energy has followed in the footsteps of Magnum Hunter Resources and QEP Resources (to name only two from recent times) this quarter in selling off acreage in the Bakken.

Baytex Energy is actually a very interesting case study; the company’s US business has changed completely within the first nine months of 2014. At the turn of the year, the company was operating in the Bakken and agreed to acquire Aurora Oil & Gas, a South Texas Eagle Ford producer, in February. Around the time of this deal completing late in the second quarter, Baytex (currently Canada’s 19th biggest producing company) began a portfolio review aimed at identifying and selling producing assets with lower rates of return that would not be the focus of major investment going forward. The Bakken assets that were held at the turn of the year are the first major assets to be sold; Baytex announced a deal with SM Energy in July to sell the Bakken properties for US$330.5 million. So within nine months (the Bakken sale closed in late September) the company’s US business has moved south in its entirety, now completely focused on Texas and the Eagle Ford shale, where wells cost around US$1.7 million less to drill on average, according to latest data from the Evaluate Energy North American shale play database (see note 1).

Murphy Oil sells Stake in Malaysian Assets on Last Day of Quarter

The biggest deal outside of North America this quarter was announced on 30th September, as Indonesia’s Pertamina agreed to acquire 30% of Murphy Oil’s Malaysian offshore assets for US$2 billion. Offshore assets can be costly to maintain, and the reduced ownership for Murphy will free up significant funds every year for the company to reassign towards its core Eagle Ford position back in the US or towards other acquisition opportunities. For Pertamina, this may only be the start of things to come as the company continues to struggle with demand back home in Indonesia. More deals like this should be expected from Pertamina as demand for oil and gas is growing while production is falling. Consequently, sourcing cheaper imports are becoming a much higher priority than ever before and acquiring overseas stakes will assist in this endeavour.

Top 10 E&P Deals Worldwide in Q3 2014

Top10_Deals_Q3_2014

Notes:

1) In the Bakken, company guidance for the year 2014 gave an average well cost estimate of US$8.9 million, and Eagle Ford wells averaged at a cost of US$7.2 million.

This report was created using the Evaluate Energy M&A Database which holds all E&P deals back to 2008. The database also now includes Refinery, Midstream (inc. Pipelines and LNG) and Service Sector deals. To find out more about Evaluate Energy's M&A offering, please download our brochure.

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The Top 100 Canadian Oil & Gas Companies

Posted by Mark Young

Sep 29, 2014 12:24:00 PM

CanOils is pleased to announce the release of its new free report, Canada's Top 100 Oil & Gas Companies, which has been compiled using Q2 2014 canadian oil & gas production results from all TSX and TSX-V listed Canadian oil and gas companies in the CanOils database.

 Oil Sands Maintenance has a Major Impact towards the Top of the Rankings

Both Imperial Oil and Canadian Oil Sands suffered temporary but significant falls in production in the second quarter of 2014. Canadian Oil Sands is the main operator at the Syncrude project and both planned and unplanned maintenance impacted production here throughout April, causing the Alberta-based company’s production to fall by around 28,000 boe/d. This meant that Canadian Oil Sands fell 2 places and now ranks as Canada’s 14th biggest oil and gas producer. Imperial’s fall in production was even greater, as alongside the maintenance issues at Syncrude, in which Imperial is also a partner, maintenance at both Cold Lake and Kearl caused a second quarter fall in production of 43,000 boe/d from Q1 2014. Husky Energy, a company that has increased production by around 25,000 boe/d since the turn of the year, now occupies 5th position in the rankings following Imperial’s temporary decrease.

Differing fortunes for Canadian Companies in UK North Sea

The UK North Sea was the location for two of the more significant movers in this quarter’s rankings. Ithaca Energy Inc. was the third highest climber, a 5,000 boe/d increase in production in the area saw the company leap 13 places into 44th position. The company has recently completed the acquisition of Summit Petroleum in the North Sea as well, so further climbs should probably be expected in subsequent periods. Another UK North Sea operator, Iona Energy Inc., in contrast, was the quarter’s second biggest faller, suffering operational difficulties at its Huntington property that resulted in a 34% decrease in production in Q2 2014.

Top100June14Table

Source: CanOils via Canada's Top 100 Oil & Gas Companies, June 2014

Download the complete report on Canada’s Top 100 Oil & Gas Companies from CanOils here for free now.

Canada's_Top_100_Oil_Gas_Companies

The CanOils database provides clients with efficient data solutions to oil and gas company analysis, with 10+ years financial and operating data for over 300 Canadian oil and gas companies, M&A deals, Financings, Company Forecasts and Guidance, as well as an industry leading oil sands product.

 

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US Companies Benefit from Move from Natural Gas to Oil Production

Posted by Mark Young

Aug 26, 2014 7:42:00 AM

The last few years have seen many of the oil and gas companies in the United States change their strategy away from natural gas and focus on oil producing assets due to low gas prices. Despite the steady and gradual recovery in the Henry Hub benchmark gas price in the US since the middle of 2012, second quarter data from a group of US oil and gas producers in the Evaluate Energy database shows that this move towards oil production has still been very worthwhile.

Oil_Gas_Commodity_Prices_08_14

Source: Evaluate Energy - The Henry Hub gas price shows a gradual increase on average from Q2 2012 ($2.29/mcf) to Q2 2014 ($4.60/mcf) while the WTI oil price has stayed relatively stable at around $90-$100/bbl in the same timeframe.

To show how worthwhile the strategy change has been, a group of 20 US domestic oil and gas producing companies with market caps between $1 billion and $10 billion have been selected. All of the companies in question were gas weighted - produced more gas than oil - in Q2 2012. The companies in that group that have switched their strategies to now be producing more oil than gas in Q2 2014 are shown in the chart below. The strategy was carried out by either buying oil assets, selling natural gas wells or by simply reallocating capital away from gas to develop oil projects instead.

Oil_Producers_Benefit_from_Change_in_Strategy_1

Source: Evaluate Energy

The other half of the group, shown in the chart below, is still gas weighted. As 3 of these companies - Comstock Resources, Goodrich Petroleum and QEP Resources - have shown a distinct movement towards oil production similar to those companies in the graph above, these will be considered as companies who have made a strategy change as well, despite still technically being gas weighted. 

Oil_Producers_Benefit_from_Change_in_Strategy_2

Source: Evaluate Energy

In the chart below, 5 significant metrics have been chosen to show how these 2 groups of companies have fared since the second quarter of 2012. The group of companies that changed strategy (see note 1) are denoted as “oil” in the chart below, and the companies who remained natural gas weighted are denoted as “gas” (see note 2). Each group’s results for the 5 metrics in the graph below have been taken from the Evaluate Energy database and averaged out for Q2 2012 and Q2 2014. The average % increase in that time for all metrics is displayed in the chart.

Oil_Producers_Benefit_from_Change_in_Strategy_3

Source: Evaluate Energy

As you can see, whilst gas producers are doing better than in 2012, the percentage increases for those companies who switched their strategies to focus efforts on oil production are much greater. There is a slightly larger increase in operating expenses associated to oil production, but this is more than offset by the increases in other areas.

On average, revenues per barrel have increased by double the percentage of the gas producers and the difference between the respective increases in operating netbacks is very striking. This has also translated into higher cash from operations in the financial statements. The market has also clearly approved of the switch to oil, with market caps for the oil producers now nearly 70% higher than they were in 2012.

It is clear that the change in strategy has paid off for those who were able to do it. Whilst the gas producers are better off with the higher gas prices in 2014, the move to oil has boosted the other half of the 2012 gas weighted peer group by a much larger degree.

Notes:

1) The companies that have changed strategy since 2012 and included in the “oil” group are Bill Barrett Corp. (BBG), Breitburn Energy Partners (BBEP), Carrizo Oil & Gas (CRZO), Energen Corp. (EGN), MDU Resources Corp. (MDU), Newfield Exploration (NFX), Penn Virginia (PVA), SM Energy Co (SM) and W&T Offshore (WTI). Comstock Resources (CRK), Goodrich Petroleum (GDP) and QEP Resources (QEP) are also included in this group despite still being gas weighted, as they have shown large movements towards oil production since 2012.

2) The companies who have remained gas weighted and are included in the “gas” group are Atlas Resources Partners (ARP), EV Energy Partners (EVEP), EXCO Resources (XCO), Magnum Hunter Resources (MHR), National Fuel Gas (NFG), Ultra Petroleum Corp. (UPL), Unit Corp. (UNT), and WPX Energy (WPX).

This report was created using second quarter data for 20 US oil and gas companies in the Evaluate Energy database. Evaluate Energy holds quarterly and annual financial and operating data for 300+ of the world’s biggest and most significant oil and gas companies. 

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Risk Appetites Changing for Major Oil

Posted by Richard Krijgsman

Aug 6, 2014 4:52:00 AM

Analysis of country risk profiles for different major oil and gas companies reveals wide differences between companies with some - such as ENI and Total - concentrating their production in countries deemed much riskier by international rating agencies. The analysis, undertaken by Evaluate Energy, calculated a consensus country risk weighted by oil and gas production by country for both 2000 and 2013.  Country risk in each country was estimated by Evaluate Energy based on a consensus of country risk ratings published by Fitch, S&P, Moody's, Institutional Investor and the OECD.  The Evaluate Energy methodology translates and standardises each of the rating agency's particular ratings to numbers 1-7 where 1 is less risky and 7 is very risky.

 

country_risk_profiles_by_company

ENI has one of the highest country risk appetites, and this has increased in the last decade as the company expanded production in Libya, Algeria, Angola, the Congo, Nigeria and Kazakhstan while its relatively 'low risk' European production declined.

Total's relatively high country risk profile stems from its focus on African production and its European production has also declined over the period. Petrobras' risk profile has fallen in the last decade as the financial markets began to take a rosier view of the risks attached to doing business in Brazil.

BP increased its country risk exposure noticeably since 2000, albeit from much lower levels, as its European and North American production declined and as it boosted output in Azerbaijan and Trinidad and Tobago. In fact, the company's risk profile is probably even higher if its stake in Rosneft is taken into account.

Apache's risk profile increased significantly due to the ramp up in Egyptian output over the period.

Other companies with much lower risk profiles include ExxonMobil, Devon, ConocoPhillips and Anadarko. ExxonMobil to take one example has 86% of its oil and gas production sourced from what the rating agencies consider the 'lower risk' OECD countries.

This report was completed using the Evaluate Energy database, which holds 20+ years of financial and operating data for the world's biggest and most important oil and gas companies. Evaluate Energy now provides a Production Portfolio Risk Rating for all producing companies in the database.

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EIA: Major Oil & Gas Companies Take on Debt to Meet Spending Needs

Posted by Mark Young

Aug 5, 2014 3:44:00 AM

In a recent study using quarterly company data from the Evaluate Energy database, the US Energy Information Administration (EIA) concluded that the gap between cash from operations and the main uses of cash for 127 of the world's major oil and gas companies has widened in recent years from a low of $18 billion in 2010 to $100 billion to $120 billion during the past three years. 

To meet spending with a relatively recent flat growth in cash from operations, companies increased their borrowing. When comparing the major sources of cash for the first quarter only, the net increase in debt has made up at least 20% of cash since 2012.

EIA_Cash_Flow_Uses_2014

Read the full EIA study here

This study was completed using Evaluate Energy's 20+ years of oil and gas financial and operating data.

To see how this was done for yourself, request a demo of Evaluate Energy.

 

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Oil & Gas M&A in Upstream Sector Reaches $51.3 Billion in Q2 2014

Posted by Mark Young

Jul 3, 2014 10:22:00 AM

Following a lacklustre first quarter for M&A activity in the oil and gas upstream sector, the second quarter of 2014 saw a spectacular rebound according to anaysis from Evaluate Energy. The total upstream deal value of US$51.3 billion is the highest single quarter total since 2012.

Quarterly Upstream Deal Value by Deal Type 2012-2014 

Oil_and_Gas_Deals_Q2_2014

Source: Evaluate Energy M&A Database

The majority of the increase in global upstream deal activity is attributable to companies and assets based in North America, where the total value of upstream deals announced increased for the fourth quarter in a row. Deals to acquire North American upstream assets or businesses made up 47% of the total deal value (US$24.3 billion) in the second quarter of 2014.

Oil_and_Gas_Deals_Regional_Split_Q2_2014

Source: Evaluate Energy M&A Database

American Energy Partners LP Continues with Utica Acquisitions

Acquisitions by North American companies also made up 47% of the quarterly total upstream deal value. Amongst the biggest-spending North American companies this quarter was the Aubrey K. McClendon-led American Energy Partners LP (AELP), which made large acquisitions in the prolific Permian Basin (US$2.5 billion) and the Marcellus and Utica shale plays (US$1.75 billion) in early June. McClendon was an early champion of the Utica shale in his Chesapeake Energy days and the acquisition continues to show that his faith in the play's potential has not wavered; this US$1.75 billion deal was AELP’s fourth acquisition this year to include a position in the Utica shale.

Apache, Devon, Encana & Freeport-McMoRan Streamline North American Positions

On the whole, AELP’s activity was a rare case as most other acquisitions in the quarter of this size were accompanied by a similarly-sized sale of assets elsewhere; it seems many North American companies are focused on streamlining positions rather than making large acreage gains like AELP. The motivation behind this streamlining of strategies will most likely be high North American production costs as well as low gas prices that have caused major rethinks for many companies trying to keep netbacks in line with shareholder expectations.

Apache Corp., Devon Energy, Encana Corp. and Freeport-McMoRan Copper & Gold Inc. (FCX) are four big North American companies who conducted the highest profile restructurings within the region this quarter.

Apache continued its US$4 billion divestiture plan to aid debt repayment and share buybacks by completing the US$1.4 billion sale of the Lucius and Heidelberg Gulf of Mexico shelf prospects to FCX and entities exercising pre-emptive rights over the assets. FCX had originally agreed to acquire the full stakes held by Apache in the assets but eventually ended up contributing US$919 million of the US$1.4 billion Apache received in consideration. This acquisition by FCX was funded by the biggest single deal of the second quarter, an agreement to sell 45,500 acres and 59 million barrels of proved reserves in the Eagle Ford shale to Encana for US$3.1 billion. FCX – having increased its focus on the Gulf of Mexico - will use the rest of the proceeds from this sale to redeem $1.7 billion in senior notes. In turn, Encana made a couple of sales of its own to fund this Eagle Ford acquisition. In April, the company agreed to sell some East Texas assets for approximately US$486 million and then in June, Apollo Global Management LLC – a New York-based private equity investor – acquired the company’s Bighorn Alberta Deep basin assets in Canada for US$1.8 billion.

Devon completed the majority of its own restructuring plan last quarter, completing the biggest deal of 2013 to finalise its entry into the Eagle Ford shale for US$6 billion, as well as announcing the sale of non-core assets in Canada to CNRL for US$2.9 billion. The final piece of the company’s restructuring jigsaw – a US$2.3 billion deal that will see Linn Energy acquire Devon’s non-core onshore assets - was announced on the very last day of the second quarter. Once this final deal is complete, the restructuring process for Devon will be over and it is hard to argue that it has not gone well; the company now has a premier position in one of the US’ most attractive shale plays, lucrative oil and condensates will have risen to form 60% of the company’s oil & gas production by year end and net debt will have been reduced by US$4 billion.

Outside of North America, further large restructuring operations took place this quarter and amongst the highest profile of these was Hess Corp’s latest deal on its way to becoming a single-resource play company. Hess agreed to sell its Thai business to state-backed PTTEP for US$1 billion. In Chad, Chevron decided to sell its 25% stake in producing assets and a pipeline to the Central African country’s government for US$1.3 billion. These deals made up the majority of the total state-backed deal value this quarter, as state-backed entities have had a very quiet 2014 with only US$3.2 billion of deals in the second quarter after a first quarter total of US$1.8 billion – in Q3 and Q4 2013 state-backed companies were involved in nearly US$25 billion of upstream deals combined.

Investment Firms Active in Q2 2014

Apollo Global Management was not the only investment firm to be active in the upstream M&A arena in the second quarter. Morgan Stanley completed Repsol’s exit from Argentina by acquiring the final 11.86% stake in YPF SA held by the Spanish major for US$1.4 billion including debt, whilst various investment firms were involved in the combined US$3 billion acquisition of a 9.5% stake in Australia’s Woodside Petroleum from Royal Dutch Shell. This willingness of private investment firms to buy interests in global E&P assets speaks volumes for the confidence held in the sector right now, despite ever-climbing operational costs seeming to hinder the profit-making abilities of upstream companies worldwide.

This report was created using the Evaluate Energy M&A database. The database includes every upstream and downstream acquisition since 2008. Evaluate Energy provides clients with efficient data solutions for oil and gas company analysis. Alongside our M&A product, Evaluate Energy also has historical financial and operating data for 300+ of the world’s biggest and most important oil and gas companies, a global assets database and a North American shale-focused product. Download our brochure here.

Top 10 Upstream Deals in Q2 2014

Acquirer

Target

Target Country

Brief Description

Total Acquisition Cost (US$000s)

Encana Corporation

Freeport-McMoRan Oil & Gas LLC and PXP Producing Company LLC

United States

Encana acquires 45,500 net Eagle Ford acres in heart of the oil-rich portion of the play

        3,100,000

Various Investment Firms

A 9.5% stake in Woodside Petroleum from Royal Dutch Shell

Australia

Royal Dutch Shell plc disposes 9.5% of its share in Woodside Petroleum Limited to a range of equity market investors

        2,985,653

Woodside Petroleum

A 9.5% stake in Woodside Petroleum from Royal Dutch Shell

Australia

Woodside Petroleum Limited buys back 9.5% of its own shares from Royal Dutch Shell plc

        2,679,965

Det Norske

Marathon Oil Norge AS

Norway

Det Norske Oljeselskap ASA acquires Marathon Oil's wholly owned subsidiary, Marathon Oil Norge AS

        2,661,049

American Energy Partners, LP

Enduring Resources, LLC

United States

American Energy Partners, LP, through its subsidiary American Energy – Permian Basin, LLC, acquires approximately 63,000 net acres from Enduring Resources, LLC

        2,500,000

Linn Energy

Devon Energy Corporation

United States

Linn Energy acquires Devon's non-core US oil and gas properties in the Rockies, onshore Gulf Coast and Mid-Continent regions

        2,300,000

Al Mirqab Capital SPC

Heritage Oil Plc

Various

Energy Investments Global Ltd, a wholly-owned subsidiary of Al Mirqab Capital SPC makes a cash offer to acquire Heritage Oil Plc

        1,874,737

Apollo Global Management, LLC

EnCana Corporation

Canada

Jupiter Resources, held by Apollo Global Management, acquires Encana's Bighorn assets in the Alberta Deep Basin

        1,800,000

American Energy Partners, LP

East Resources, Inc. and an unnamed private company

United States

American Energy Partners, LP (through subsidiaries) acquires approximately 75,000 net acres in the Marcellus and Utica shale plays from East Resources, Inc. and an unnamed private company

        1,750,000

Glencore Xstrata plc

Caracal Energy Inc.

Chad

Glencore Xstrata plc acquires Caracal Energy Inc.

        1,633,094

 

 

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North American Oil Production Rises by 34% in 10 Years

Posted by Ilda Sejdia

Jul 1, 2014 9:42:00 AM

North American oil production is 34% higher now than in 2003, whilst natural gas production in the Middle East has doubled over the same time period. These are the major takeaways from a new analysis from Evaluate Energy’s Global database that looks at the latest BP Statistical Review and EIA figures for country-by-country oil and gas data.

12 Month Analysis

Over the last year, the main changes in production include the following:

  • Global crude/NGL production increased by 0.6%. The North American region recorded the largest percentage growth by 10.4%. The MENA region (Middle East & North Africa) recorded the largest decline in Oil/NGL production 16.2% and that can be attributed to the political and social unrest within the region causing various production outages. Crude/NGL Production in East Africa increased from to 134,000 barrels per day to 221,000 barrels per day as a result of the production resumption in South Sudan. Global proved Oil/NGL reserves fell by almost 6% from 2012 to 1,585.5 billion barrels at the end of 2013.

Global_Oil_Production_2013

Source: Evaluate Energy Global Database via BP Statistical Review 2013

  • Global natural gas production was largely stable over the year, only increasing by 0.6% in 2013. Africa saw a large reduction of 11.9% in the last year however, which can be attributed to the fall of gas production in Nigeria (16.44%) and Algeria (3.29%). Global proved gas reserves stood at 6,554,975 billion cubic feet at the end of 2013.

Global_Gas_Production_2013

Source: Evaluate Energy Global Database via BP Statistical Review 2013

10 Year Analysis - 2003-2013

Comparing the figures for 2013 with those of 10 years ago we observe the following:

  • Unsurprisingly following the shale gas and liquids boom of the mid-late 2000’s, the largest 10-year increase in Crude/NGL production levels happened in North America (34.6%). Other regions that experienced increases in Crude/NGL production were Asia Central (33.1%) and Africa (28%). The largest falls in Crude/NGL production were recorded in Europe - which nearly halved its annual oil production over the 10 year period - and North Africa (22.3%).
  • Natural gas production has doubled in the last 10 years in the Middle East region. Other regions exhibiting large increases in natural gas production were Africa (87.5%), Asia Pacific (48.9%) and Asia Central (10.9%). Europe was the only region to experience a fall in natural gas production over the 10 year period, recording a 7.1% decline from 2003 production levels.
  • In 2013, global proved crude/NGL reserves have increased by 18.8% since 2003, although since last year this figure has fallen by around 6%. Proved Crude/NGL reserves in Latin America are 2.9 times larger compared to 2003. The huge discoveries in Brazil’s Pre-Salt Basins are a very significant contributing factor to this increase; with discoveries such as the Libra field, Brazil has seen an increase of approximately 47.1% in oil reserves from 2003 levels. Other countries contributing to the Latin American increase in crude/NGL reserves are Colombia, Ecuador and Peru, whereas Mexico shows a relatively stagnant proved reserves figure from 2004 onwards. East Africa also shows a very dramatic increase in proved crude/NGL reserves, which can be attributed to Sudan and South Sudan’s abundant reserves.
  • In 2013, global proved natural gas reserves increased by 19.4% since 2003. The shale gas boom means that the single largest 10 year increase occurred in North America (63.4%), while Asia Central (44.6%) and Asia Pacific (20.1%) both showed their own significant increase.

This report was created using the Evaluate Energy global database, which holds annual country by country oil and gas operational data back to 1989, including oil and gas production, reserves and reserves life figures, as well as import and export statistics and refinery capacities. The data for the global database is compiled using the BP Statistical Review and the EIA.

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Africa Needs Greater Oil Refinery Capacity Urgently

Posted by Heather Brooks

Jun 23, 2014 11:02:24 AM

Africa is struggling over the growing need for fuel accompanying its economic expansion and the stagnation of its refining capacity.

Despite producing 3.5 times the amount of oil consumed in its raw state, there is still a reliance on imported fuels. There is no denying Africa’s growing need for fuel but refineries are not being built as planned when left to the free market. For example, Algeria’s crude production has remained roughly the same over the past decade according to Evaluate Energy’s latest data available. However, consumption has increased by 50% over the same time frame. This is well over the demand growth rate within developed regions such as the United States, which had a 6% decrease in this time. Algeria and other African countries are left to rely on fuel imports to supplement their production as they do not have enough refinery capacity to keep up with demand. It will take a long time for this to change according to Evaluate Energy data. Only three new refineries are ‘highly’ likely to be built by 2020 in Africa with the earliest of these due to be commissioned in 2017. These new projects, however, have been continually pushed back as companies abandon contracts and struggle to find investors. While European and Asian countries are expanding existing refineries and constructing new ones, there is only a 46,000 barrel per day total upgrade capacity to be added to refineries across all of Africa by 2016.

The main issue hampering the construction of refineries, even in areas with large local supplies of oil, is the lack of economic viability these projects hold in the free market. In Kenya, the recent oil discoveries would usually lead to potential expansion across the whole supply chain, yet Essar Oil abandoned plans in late 2013 to expand the country’s sole refinery, citing that the $1.2 billion cost would not be economically viable.

Kenya is ploughing ahead with other development plans however, click here for more details.

This economic viability issue may be relevant for public oil companies operating in the continent but many governments subsidise oil refined in Africa due to large income disparities in the local markets, which dramatically alters the investment criteria. It is estimated that imported fuel subsidies amount to just under $20 billion in Africa per year. In the medium term, governments would lose less money building a refinery, even with its large upfront cost due to the decreased reliance on importation. Therefore, for the few currently planned refinery projects this is where the funding is predominately coming from.

There are 19 planned refinery projects being tracked by Evaluate Energy in Africa which are considered to have at least a medium likelihood of completion. Algeria takes up 4 of this total with a potential capacity increase of over 300,000 barrels per day. The government of Uganda has been pushing for an oil refinery in its landlocked country for some time now. Uganda has oil to supply the refinery but the cost of such a venture has been difficult to justify so far given the comparably low fuel prices in Africa. Therefore, the planned refinery seems doubtful especially considering the 150,000 b/d capacity it is slated to handle. One proven alternative option was carried out in Djibouti with the purchase of an existing refinery from Saudi Aramco for $150 million. The old refinery was bought, dismantled, and shipped to Djibouti where it was reassembled to avoid the high cost of constructing a new refinery.

Africa_Refined_Product_Demand_2020Note: Evaluate Energy has only included refineries with at least a medium chance of being completed in this chart.

Evaluate Energy’s refinery database encompasses all active refineries worldwide with capacities, company ownership information, secondary conversions and nelson complexity indices. The database also covers all construction projects for refineries worldwide. 

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