Risk Appetites Changing for Major Oil

Posted by Richard Krijgsman

Aug 6, 2014 4:52:32 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. 

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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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Top 100 Canadian Oil & Gas Companies

Posted by Mark Young

Jun 10, 2014 12:16:00 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 Q1 2014 oil and gas production results from all TSX and TSX-V listed Canadian oil and gas companies in the CanOils database. The full report can be downloaded here.

Maintenance, Disruptions and Winter Weather Cause Major Falls in the Rankings

The winter was not kind to TSX and TSX-V listed companies in 2014; poor weather conditions impacted transportation activities all over the world and this caused a cut down in production or complete shutdowns for many companies in the Top 100. Tethys Petroleum fell the furthest in the rankings since December 2013, now 11 places lower, due to harsh weather conditions in February and March in Kazakhstan. Ithaca Energy, another of the Top 100’s big fallers, also suffered from the weather, this time in the UK North Sea, where production at its Cook field had to be shutdown.

Civil disruptions also impacted certain companies. Gran Tierra fell victim to pipeline disruption activities in Colombia and recorded a 23% decrease in production in Q1 2014 compared to Q4 2013 and a 6 place fall in the Top 100 rankings.

As well as civil disruptions, enforced maintenance periods have also been affecting the Umusadege field in Nigeria for some time, which has caused Mart Resources to bounce up and down the rankings from quarter to quarter. This quarter the company rose by 18 places in the rankings, but do not rule out an equally drastic fall next quarter!

Raging River Continues to Climb as Top 20 Sees Little Movement

The top portion of the rankings is usually reasonably static from quarter to quarter, due to the larger production volumes associated with being this high in the rankings and Q1 2014 was no different. Husky Energy Inc. is a good example of this; the company recorded the highest increase in production out of all the TSX-listed companies this quarter (Q1 production averaged 17,000 boe/d higher than in Q4) but did not move up from 6th place, with a further 5,000 boe/d separating the company from Imperial Oil Ltd. in 5th place. Similarly, Penn West Petroleum did not fall in the rankings despite recording this quarter’s biggest fall in production of approximately 13,000 boe/d.

As we move down the rankings and the production volumes drop, movements are more frequent from one quarter to the next. Raging River Exploration Inc. is one company that has continuously been moving up the rankings over the past year. To see how far Raging River has moved in this time, you can download all of our previous Top 100 reports using this link, as well as other free oil and gas reports.

Top 5 Climbers and 5 Biggest Declines

Top_100_Ups_and_Downs-1

Source: CanOils via Canada’s Top 100 Oil & Gas Companies, March 2014

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

Top_100_Cover_March_2014-1

Canada’s Top 100 Oil & Gas Companies is a new report from CanOils. 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. Download our brochure here.

 

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Investment in Natural Gas Loses its Shine

Posted by Richard Krijgsman

May 20, 2014 5:34:00 AM

Total upstream capital spending continued to rise in 2013, but while investment in oil-related projects is up, capital spending in upstream natural gas is falling. What's more, the overall rate of increase in upstream capital spending is losing momentum, prompting the question of whether we are seeing the early signs of a cyclical downturn in capital spending following a decade of strong growth. That's according to an Evaluate Energy analysis of the latest company capital expenditure data for 2013. This analysis adds more granularity to the EIA's analysis of upstream capital spending that used Evaluate Energy's data last month.

Companies do not generally report the split between capital expenditure (capex) on oil vs gas related projects. So we have created a couple of peer groups for this analysis: one oil-weighted group of 85 companies (see note 1) whose oil production forms more than 75% of their total oil and gas output and another gas-weighted group of 29 companies (see note 2) whose natural gas production forms more than 75% of their output.

For the purposes of this report, we have studied the capex of the oil-weighted group since 2007. These companies accounted for US$250 billion of capex in 2013 and their total capex has been rising in absolute terms in recent years. However, the rate of growth in oil capex has been slowing, a trend that looks like it will continue as margins continue to be squeezed. 

capex_oil

Source: Evaluate Energy

For the gas-weighted group, we can see that both the rate of growth and the absolute level of capex has been falling. As many of the companies in this group are based in the United States, this trend partly reflects the downturn in gas-focused capital projects as gas prices remain low.

capex_gas

Source: Evaluate Energy

This report was created using the Evaluate Energy database, which provides clients with efficient data solutions for oil and gas company analysis. Our database holds over 20 years of financial and operating data for the world's biggest oil and gas companies. Evaluate Energy also has extensive M&A, Assets, Refinery and LNG databases.

Notes

1) Oil weighted group includes: Berry Petroleum Co., Clayton Williams Energy, PDVSA, Madalena Energy Inc., Sinopec, EPL Oil & Gas Inc, CNOOC Ltd, Pemex, Lundin Petroleum, Petrobras (IFRS US$), Resolute Energy Corporation, Lukoil (US GAAP), Nexen Inc., KazMunayGas, Ecopetrol, Gazprom Neft, Whiting Petroleum Corporation, Surgutneftegaz (IFRS), Oil Search, Imperial Oil Limited, Baytex Energy Corp., TNK-BP International Ltd, Diamondback Energy Inc., Pacific Rubiales Energy Corp., Kodiak Oil & Gas Corp., Coastal Energy Company, Rosneft, Kuwait Petroleum Corporation, Suncor Energy Inc., Oasis Petroleum Inc., Oil India, Northern Oil & Gas, Inc, Gulfport Energy Corporation, Circle Oil, Denbury Resources Inc., Grupa Lotos, Vaalco Energy Inc, Afren, Gran Tierra Energy Inc., Sherritt International Corp, Tatneft, Europa Oil and Gas, Kinder Morgan Energy Partners, L.P., Pan Pacific Petroleum, Petro Vista Energy Corp., Baron Oil PLC, Hardy Oil, Egdon Resources, CAMAC Energy Inc, Sterling Energy, Global Energy Development, Oilex, Carnarvon Petroleum Ltd, Suroco Energy Inc., Maple Energy, Cooper Energy Limited, Amerisur Resources, PA Resources AB, PetroLatina Energy, TransGlobe Energy Corporation, Max Petroleum Plc, Providence Resources PLC, ROC Oil, Heritage Oil Plc., Horizon Oil, BPZ Resources Inc, DNO International ASA, Ithaca Energy Inc., Canacol Energy Ltd., Gulf Keystone, Nostrum Oil & Gas LP, Bankers Petroleum Ltd, Cosmo Oil, Parex Resources Inc., Dragon Oil, Kosmos Energy, Maurel & Prom SA, Petrominerales Ltd., KazMunaiGas Exploration Production, Bashneft, Galp Energia, SK Innovation Co. Ltd, EnQuest PLC, GAIL, Maersk Group.

2) Gas weighted group includes: Southwestern Energy Co., CPC Corporation, Ultra Petroleum Corporation, Northern Petroleum, EXCO Resources, Niko Resources Ltd., Nexus Energy, Cabot Oil & Gas Corp., Encana Corporation, Questar, EQT Corp, Novatek, Gazprom, Polish Oil & Gas, Bill Barrett Corporation, Comstock Resources, Paramount Resources Ltd., PetroQuest Energy, Inc, Regal Petroleum, Quicksilver Resources Inc, WPX Energy, Chesapeake Energy Corp., National Fuel Gas, Goodrich Petroleum Corp, Range Resources Corp, JKX Oil & Gas, QEP Resources Inc, KUFPEC, Santos

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Topics: Capital Expenditure

How Much Water is used in the Alberta Oil Sands?

Posted by Mark Young

May 1, 2014 7:15:00 AM

It is no secret that to produce any oil from an oil sands project, you need water and lots of it.

To create the steam needed to extract oil in oil sands projects, operators mainly recycle water that has already been used in the project over and over again. When this amount of water isn’t sufficient, fresh or brackish, saline water (see notes 1 & 2) is obtained from external sources to make up the shortfall. This water can be taken from surface water sources, such as rivers or lakes, or from underground sources via water wells. CanOils now provides data on how much water from external sources is used by producing oil sands in situ and mining projects each year. For a demonstration of this new data set, click here.

Analysing this data, we can see that over time, operators in the Alberta oil sands have been getting their water usage from external sources increasingly under control. Total external water use by in situ projects in 2013 was more than double the amount used in 2002, but high recycle ratios have meant this external water usage total has been relatively flat since 2010 whilst bitumen production has continued to rise.

Biggest Water Using Projects in 2013

Of the in situ projects that are currently producing, it is Canadian Natural Resources’ Primrose/Wolf Lake project that used the most water from external sources in 2013, approximately 146,000 barrels per day (bbl/d). Cenovus Energy’s Foster Creek (68,000 bbl/d), Nexen’s Long Lake (56,000 bbl/d) and Imperial Oil’s Cold Lake (46,000 bbl/d) were also amongst the highest water using in situ projects in 2013. 

Alberta_Oil_Sands_Water_1

Source: The CanOils Oil Sands Database

Water Use Efficiency Improving Over Time

In situ projects use a lot of water at start-up before production really begins to ramp up. If all in situ projects’ production and external water use are combined, we can see that until production really started to increase in 2009, more external water was always being used compared to bitumen being produced. Recycle ratios within projects have improved markedly since 2009 – most in situ projects now have recycle ratios of over 90% – and the overall requirement to source water from external sources has consequently fallen for each barrel of oil produced.

Alberta_Oil_Sands_Water_2

Source: The CanOils Oil Sands Database

A Project in Focus: Foster Creek, Cenovus Energy

One project that has improved its efficiency in terms of external water use is Cenovus Energy’s 120,000 bbl/d Foster Creek project. In 2002, the project was only 1 year into its producing life, and was using over 2 barrels of water for every barrel of bitumen it produced. Now, 12 years later with a recycle ratio of around 100%, the project only needs to source 0.6 barrels of external water to produce a barrel of bitumen.

Alberta_Oil_Sands_Water_3

Source: The CanOils Oil Sands Database

Fresh Water Use Falling

As well as this increasing efficiency in terms of external water use, it is also important to note that Foster Creek is now using much less fresh water than when it first started producing. From the above graph, we can see that the project is using almost 3 times as much water in 2013 than in 2002, but this is almost all made up of brackish, saline water (see note 2). Fresh water use has in fact been reduced to just 5,000 bbl/d or 7% of the total water used in the project.

Alberta_Oil_Sands_Water_4

Source: The CanOils Oil Sands Database

This is a trend that can again be seen across the board for in situ oil sands projects. Brackish water use has increased at a much higher rate than the use of fresh water. In 2002, nearly all external water used by in situ oil sands projects was fresh water, whereas in 2013, brackish water makes up almost 42% of the total external water used.

Alberta_Oil_Sands_Water_5

Source: The CanOils Oil Sands Database

An important project to note here is Jackfish, operated by Devon Energy. This project started producing in 2007 and is the only producing oil sands in situ project to have never used fresh water in its operations.

So not only are in situ operators improving the efficiency with which they use water from external sources in bitumen production, they are also becoming less and less reliant on fresh water sources and using more and more brackish water when available that would not otherwise be suitable for human or agricultural use (see note 3).

This report was created using new data now available in Canoils’ Oilsands product. CanOils now provides annual fresh and brackish water usage statistics for 7 producing oil sands mining projects and 24 producing in situ projects. This data complements the already available recycle, steam/oil and water/oil ratios, giving CanOIls Oilsands subscribers a comprehensive picture of water use in the Alberta Oil Sands industry.

To request a demonstration of the CanOils Oilsands product please click here.

 Notes:

1)      Fresh water is either non-saline groundwater, which is groundwater that has total dissolved solids less than or equal to 4000 milligrams per litre, or surface water, which is as defined in Section 1(1)(bb) of the Alberta Water (Ministerial) Regulation as “all water on the ground surface, whether in liquid or solid state.”

2)      Brackish water is saline groundwater as defined in section 1(1)(z) of the Alberta Water (Ministerial) Regulation as “water that has total dissolved solids exceeding 4000 milligrams per litre.” Such groundwater is defined as “brackish water” in PETRINEX and “saline groundwater” by Alberta Environment and Sustainable Resource Development. Brackish water cannot be used in oil sands mining operations.

3)      Most fresh water used in oil sands operations is not immediately suitable for drinking or agricultural use either. It requires treatment after being extracted from deep underground sources.

4)      All water usage data available in CanOils is sourced from the Government of Alberta Oil Sands Information Portal (OSIP). CanOils and Evaluate Energy gratefully acknowledge the Government of Alberta Oil Sands Information Portal (OSIP) and its data contributing partners for the provision of all data used in this report. The agencies and organisations responsible for the data contributions in this report include Alberta Environment and Sustainable Resource Development, Alberta Energy Regulator and aemera.org.

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EIA: Upstream Oil and Gas Spending Favours Exploration and Development

Posted by Mark Young

Apr 28, 2014 12:33:00 PM

In a recent study conducted using annual data from the Evaluate Energy database, the US Energy Information Administration (EIA) concluded that 42 upstream oil and gas companies' spending on exploration and development worldwide increased by 5% ($18 billion) in 2013, whilst overall spending was relatively flat following a 12 year period of strong growth.

EIA_Capital_Spending_Trends_Using_Evaluate_Energy_Data

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

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

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Canadian Oil & Gas Companies Endure a Tough 2013

Posted by Isabelle Li

Apr 15, 2014 7:16:00 AM

Overall, 2013 was a difficult year for Canadian oil and gas companies, according to a new analysis by CanOils of the last 5 years' annual results for 99 TSX-listed companies (note 1). Capital expenditures reached record highs for recent periods, but so did the average well costs and the amount of capital spending financed by long term debt. Many companies followed up a net loss in 2012 with further - and often increasing - losses in 2013.

Continuing Losses

The 99 companies’ (hereafter: “the group”) total combined net income continued last year’s downslide by dropping 5.7% from 2012 to Cdn$10.9 billion, the lowest total in the past 5 years and 51.4% lower than the total of Cdn$21.3 billion in 2010, the recent high. This is not very surprising considering the average natural gas price has dropped 16.9% from an average of Cdn$3.59/mcf in 2010 to Cdn$2.98/mcf in 2013 and the demand in the US for oil and gas imports from Canada has continuously fallen between 2010 and 2012 according to the BP Statistical Review. Total combined EBITDA for these companies increased from last year’s Cdn$54.2 billion by 4.2%, but this is still 8.4% less than 2011’s recent high of Cdn$61.6 billion. The changes in net income and EBITDA over the past five years show that the group’s non-operating costs have increased by almost 60%.

Combined Total Earnings and Impairments (Cdn$ Million)

Canadian-Oil-Gas-Companies-2013-1

Source: The CanOils Database. All figures are combined totals of all the reported figures for the group.

Although earnings have generally been falling and the current profitability position is not very encouraging, it should not be too worrying for shareholders and potential investors in the short term. 27 companies in the group declared dividends this year, with an average payout representing 70.6% of these companies' combined net income. This stands in stark contrast to 5 years ago, when only 8 out of the group declared dividends and the payout ratio was only 30.6%. The total distribution has more than doubled from Cdn$3,437.6 billion in 2009 to Cdn$7,777.5 billion in 2013.

Dividends and Payout Ratios (Cdn$ Million)

Canadian-Oil-Gas-Companies-2013-2

Source: The CanOils Database. Total dividend distribution is the combined total of all dividends declared by the group each year. The dividend payout ratio is estimated using the total dividend distribution amount and the reported net income of only those companies that declared dividends.

Bucking the Trend

The senior peer group (companies producing more than 100,000 boe/day) performed better than most in 2013, protected from rising costs by their larger economies of scale and from the low gas price by their generally high oil weighting; only 2 of the 10 companies in the senior peer group, Encana Corp. (TSX:ECA) and Talisman Energy Inc. (TSX:TLM), produce more gas than oil.

There are also some smaller companies bucking the trend and achieving growth. Tourmaline Oil Corp. (TSX:TOU) has performed especially well recently; the company’s EBITDA has increased for four consecutive years. Birchcliff Energy Ltd. (TSX:BIR), Bellatrix Exploration Ltd. (TSX:BXE) and ARC Resources Ltd. (TSX:ARX) also showed a profit in the past two years and achieved growth in terms of both net income (396%, 158% and 73% respectively) and EBITDA (61%, 55% and 16% respectively) since 2012. 

Spending Focused on Drilling

In 2013, total upstream capital expenditures increased 8.4% and 77.2% from year 2012 and 2009 respectively, reaching a 5-year high of Cdn$56.8 billion. Among the total expenditures, only Cdn$3.0 billion and Cdn$3.2 billion were spent on property and corporate acquisitions, constituting 11.0% of the total expenditures. Most companies chose to focus on exploration and development activity through drilling.

For a free pdf detailing the 25 Most Active Canadian Oil & Gas Companies in 2013, click here.

It is getting more and more expensive to execute this kind of strategy. In 2013, 8,789 (net) wells were drilled, which is about 3.1% less than last year. However, the overall average capital expenditure has increased significantly, showing that well costs are undoubtedly on the rise. This has been the trend for the last three years.

Capital Expenditures (Cdn$ Million)

Canadian-Oil-Gas-Companies-2013-3

Source: The CanOils Database. All figures are combined totals of all the reported figures for the group, apart from cost per well which has been estimated using the combined totals (see note 2) For a free pdf detailing the 25 Most Active Canadian Oil & Gas Companies in 2013, click here.

The continuing downward trend of company net income means a lot of companies do not have sufficient resources internally to fund growth, causing a need to raise more funds from external sources. By the end of 2013, almost 27% of the group’s long-term capital was financed by long-term debt, the highest level of leverage in the past five years. However, this seems safe for now; the group’s combined long-term debt was only 4.7 times bigger than current cash in hand and combined cash coverage of interest expenses was 5.1 times. 

Production

Actual production volumes fell in 2013; the average results for the group showed 2013 production was 4,775 thousand barrels of oil equivalent per day, 9.15% lower than last year’s daily average. Oil production decreased for the first time in 5 years from 2,410 thousand barrels per day (mbbl/d) in 2012 to 2,173 mbbl/d in 2013, even though the WTI annual average price reached a high of Cdn$101.42/bbl this year. Despite the natural gas price showing a recovery in recent months, natural gas production continued to decrease in 2013; the average daily production was 7,249 million cubic feet, which is in fact the lowest daily average for the past five years.

Production, Prices and Netbacks

Canadian-Oil-Gas-Companies-2013-4

Source: The CanOils Database. All production and netback figures are estimated averages of the combined reported individual amounts for the group

The number of these 99 companies whose production is gas-weighted has dropped from 49 in 2011 to only 33 in 2013, showing a definite movement towards oil production across the board as the gas price remains low. The companies that have remained gas-focused will be looking to the west coast in British Columbia for encouragement; numerous LNG export terminals applications are being filed to try and start taking advantage of higher gas prices in Asia by 2020, which could have a positive impact on domestic Canadian prices for operators. As a further point of encouragement, the Henry Hub benchmark price in the US hit a 5-year high of over US$6 at the start of 2014.

All data for this report is sourced from the CanOils database, an Evaluate Energy service that provides efficient data solutions for Canadian oil and gas company analysis. CanOils holds historical financial and operating data for 300+ oil and gas companies listed on the TSX and TSX-V back to 2002, and also has extensive M&A deals, financing deals, key personnel and Oil Sands databases. For more information about any of our data offerings and to see the power of the CanOils database for oil and gas company analysis and how we can help you, please refer to our brochure or request a demonstration of our product.

Notes

  1. The 99 companies included in this report, “the group”, are the 99 TSX-listed oil & gas companies who had reported their annual 2013 (December year-end) results on and before 10th April 2014.
  2. The Alberta Gas Reference Price is a monthly weighted average of an intra-Alberta consumer price and an ex-Alberta border price, reduced by allowances for transporting and marketing gas.

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